Edgar Filing: NOBLE ENERGY INC

form10-q.htm

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 June 30, 2008

¨ 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 July 15, 2008: 172,697,075.

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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008		2007
Revenues
Oil, gas and NGL sales	$	1,130		$	727		$	2,074	$	1,394
Income from equity method investees		56			49			118		95
Other revenues		19			18			38		48
Total		1,205			794			2,230		1,537
Costs and Expenses
Lease operating expense		88			83			170		161
Production and ad valorem taxes		51			28			94		54
Transportation expense		16			16			29		27
Exploration expense		103			54			143		99
Depreciation, depletion and amortization		196			183			399		349
General and administrative		61			48			121		93
Loss on involuntary conversion		-			38			-		51
Other operating expense, net		18			16			38		32
Total		533			466			994		866
Operating Income		672			328			1,236		671
Other (Income) Expense
Loss (gain) on commodity derivative instruments		828			(1	)		1,065		(2	)
Interest, net of amount capitalized		17			31			34		58
Other expense, net		25			5			18		18
Total		870			35			1,117		74
Income (Loss) Before Income Taxes		(198	)		293			119		597
Income Tax Provision (Benefit)		(54	)		84			48		176
Net Income (Loss)	$	(144	)	$	209		$	71	$	421

Earnings (Loss) Per Share
Basic	$	(0.84	)	$	1.22		$	0.41	$	2.46
Diluted	$	(0.84	)	$	1.21		$	0.41	$	2.43

Weighted average number of shares outstanding
Basic		172			171			172		171
Diluted		172			173			175		173

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

Noble Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(in millions, except share amounts)

	(Unaudited)
	June 30,			December 31,
	2008			2007
ASSETS
Current Assets
Cash and cash equivalents	$	983		$	660
Accounts receivable - trade, net		864			594
Other current assets		301			315
Total current assets		2,148			1,569
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)		11,129			10,217
Other property, plant and equipment		139			112
Total property, plant and equipment		11,268			10,329
Accumulated depreciation, depletion and amortization		(2,799	)		(2,384	)
Total property, plant and equipment, net		8,469			7,945
Goodwill		759			761
Other noncurrent assets		561			556
Total Assets	$	11,937		$	10,831

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade	$	921		$	781
Commodity derivative instruments		964			540
Other current liabilities		320			315
Total current liabilities		2,205			1,636
Deferred income taxes		1,999			1,984
Asset retirement obligations		146			131
Commodity derivative instruments		390			83
Other noncurrent liabilities		361			337
Long-term debt		1,851			1,851
Total Liabilities		6,952			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		2,170			2,106
Accumulated other comprehensive loss		(195	)		(284	)
Treasury stock, at cost; 19 million shares		(613	)		(613	)
Retained earnings		2,982			2,964
Total Shareholders’ Equity		4,985			4,809
Total Liabilities and Shareholders’ Equity	$	11,937		$	10,831

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

Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in millions)
(unaudited)
	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities
Net income	$	71		$	421
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		399			349
Dry hole expense		69			31
Deferred income taxes		10			104
Income from equity method investees		(118	)		(95	)
Dividends received from equity method investees		121			97
Unrealized loss (gain) on commodity derivative instruments		934			(2	)
Settlement of previously recognized hedge losses		(101	)		(91	)
Loss on involuntary conversion		-			51
Other		59			98
Changes in operating assets and liabilities, net of acquisition:
(Increase) in accounts receivable		(276	)		(22	)
(Increase) decrease in other current assets		(28	)		37
Increase in accounts payable		64			30
(Decrease) in other current liabilities		(50	)		(235	)
Net Cash Provided by Operating Activities		1,154			773

Cash Flows From Investing Activities
Additions to property, plant and equipment		(932	)		(695	)
Proceeds from property sales		109			-
Net Cash Used in Investing Activities		(823	)		(695	)

Cash Flows From Financing Activities
Exercise of stock options		24			16
Excess tax benefits from stock-based awards		23			10
Cash dividends paid		(53	)		(33	)
Purchases of treasury stock		(2	)		(102	)
Proceeds from credit facility		450			280
Repayment of credit facility		(425	)		(115	)
Repayment of installment notes		(25	)		-
Proceeds from short term borrowings		-			15
Net Cash (Used in) Provided by Financing Activities		(8	)		71
Increase in Cash and Cash Equivalents		323			149
Cash and Cash Equivalents at Beginning of Period		660			153
Cash and Cash Equivalents at End of Period	$	983		$	302

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

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		-		-		-		-			-			-			71			71
Stock-based compensation expense		-		-		-		20			-			-			-			20
Exercise of stock options		1		-		4		20			-			-			-			24
Tax benefits related to exercise of stock options		-		-		-		23			-			-			-			23
Restricted stock awards, net		-		-		1		(1	)		-			-			-			-
Dividends ($0.30 per share)		-		-		-		-			-			-			(53	)		(53	)
Changes in treasury stock, net		-		-		-		2			-			-			-			2
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		-		-		-		-			97			-			-			97
Interest rate cash flow hedges:
Unrealized change in fair value		-		-		-		-			(7	)		-			-			(7	)
Net change in other		-		-		-		-			(1	)		-			-			(1	)
June 30, 2008		192		19	$	641	$	2,170		$	(195	)	$	(613	)	$	2,982		$	4,985

December 31, 2006		188		17	$	629	$	2,041		$	(140	)	$	(511	)	$	2,095		$	4,114
Net income		-		-		-		-			-			-			421			421
Stock-based compensation expense		-		-		-		12			-			-			-			12
Exercise of stock options		1		-		3		13			-			-			-			16
Tax benefits related to exercise of stock options		-		-		-		10			-			-			-			10
Restricted stock awards, net		1		-		2		(2	)		-			-			-			-
Dividends ($0.195 per share)		-		-		-		-			-			-			(33	)		(33	)
Purchases of treasury stock		-		2		-		-			-			(102	)		-			(102	)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		-		-		-		-			(3	)		-			-			(3	)
Unrealized change in fair value		-		-		-		-			(51	)		-			-			(51	)
Net change in other		-		-		-		-			2			-			-			2
June 30, 2007		190		19	$	634	$	2,074		$	(192	)	$	(613	)	$	2,483		$	4,386

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is an independent energy company engaged in the 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 June 30, 2008 (unaudited) and December 31, 2007 and for the three months and six months ended June 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 six-month period ended June 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, as amended, for the year ended December 31, 2007.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(in millions)
Other Revenues
Electricity sales	$	14		$	14		$	29		$	37
Gathering, marketing and processing revenues		5			4			9			11
Total	$	19		$	18		$	38		$	48
Other Operating Expense, net
Electricity generation expense	$	13		$	12		$	28		$	28
Gathering, marketing and processing expense		4			4			8			9
Other operating (income) expense, net		1			-			2			(5	)
Total	$	18		$	16		$	38		$	32
Other Expense, net
Deferred compensation expense	$	29		$	3		$	22		$	15
Interest income		(6	)		(3	)		(12	)		(6	)
Other (income) expense, net		2			5			8			9
Total	$	25		$	5		$	18		$	18

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

	June 30,		December 31,
	2008		2007
	(in millions)
Other Current Assets
Inventories	$	92	$	60
Commodity derivative instruments		52		15
Prepaid expenses and other current assets		24		27
Deferred income taxes		133		131
Assets held for sale		-		82
Total	$	301	$	315
Other Noncurrent Assets
Equity method investments	$	355	$	357
Mutual fund investments		117		124
Probable insurance claims		37		37
Commodity derivative instruments		22		5
Other noncurrent assets		30		33
Total	$	561	$	556
Other Current Liabilities
Accrued and other current liabilities	$	233	$	206
Current income taxes payable		-		52
Current installment of long-term debt		25		25
Asset retirement obligations		15		13
Interest payable		11		18
Interest rate lock derivative instrument		12		1
Deferred gain on asset sale		24		-
Total	$	320	$	315
Other Noncurrent Liabilities
Deferred compensation liability	$	243	$	225
Accrued benefit costs		59		51
Other noncurrent liabilities		59		61
Total	$	361	$	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 have begun incorporating our own credit standing into the measurement of certain 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 non-financial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants 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 these 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 June 30, 2008 and December 31, 2007, we had no significant cash collateral obligations.

Note 3 – Fair Value Measurements

Measurement information for financial assets and liabilities reported at fair value at June 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	$	117	$	-		$	-	$	-		$	117
Commodity derivative instruments		-		130			-		(56	)		74
Financial liabilities:
Commodity derivative instruments		-		(1,410	)		-		56			(1,354	)
Interest rate lock derivative instruments		-		(12	)		-		-			(12	)

(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, that 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 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 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 includes a measure of nonperformance risk. 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.

Interest Rate Lock Derivative Instruments – At June 30, 2008, we had interest rate locks of $1 billion notional value, based on US Treasury rates. We estimate the fair values of the locks based on published interest rate yield curves as of the date of the estimate. We settled the locks in July 2008. 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. Such instruments include variable to fixed price swaps, costless collars and basis swaps.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008		2007			2008		2007
	(in millions)
Unrealized loss on commodity derivative instruments	$	716	$	-		$	934	$	-
Realized loss on commodity derivative instruments		112		-			131		-
Ineffectiveness gain		-		(1	)		-		(2	)
Loss (gain) on commodity derivative instruments	$	828	$	(1	)	$	1,065	$	(2	)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(in millions)
Decrease in crude oil sales	$	(93	)	$	(40	)	$	(190	)	$	(68	)
(Decrease) increase in natural gas sales		(2	)		29			35			72
Total (decrease) increase in oil and gas sales	$	(95	)	$	(11	)	$	(155	)	$	4

As of June 30, 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
3rd Qtr 2008	NYMEX WTI		16,500	$	38.11	NYMEX WTI		3,100	$	60.00	$	72.40
4th Qtr 2008	NYMEX WTI		16,500		37.92	NYMEX WTI		3,100		60.00		72.40
3rd Qtr 2008	Dated Brent		2,000		88.18	Dated Brent		3,848		45.00		66.19
4th Qtr 2008	Dated Brent		2,000		88.18	Dated Brent		3,587		45.00		65.90

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

2010						NYMEX WTI		5,500		69.00		85.65

As of June 30, 2008, we had entered into the following natural gas derivative instruments:

	Variable to Fixed Price Swaps (1)					Costless Collars
				Weighted					Weighted		Weighted
Production		MMBtu		Average			MMBtu		Average		Average
Period	Index	Per Day		Fixed Price		Index	Per Day		Floor Price		Ceiling Price
3rd Qtr 2008	NYMEX HH		170,000	$	5.33	IFERC CIG		14,000	$	6.75	$	8.70
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

2010						IFERC CIG		15,000		6.25		8.10

(1)

In addition to the NYMEX HH variable to fixed price swaps shown above for 2008, we have 100,000 MMBtu per day of IFERC CIG basis swaps with an average differential to NYMEX HH of $(1.66) per MMBtu, 40,000 MMBtu per day of IFERC ANR-OK basis swaps with an average differential to NYMEX HH of $(1.01) per MMBtu, and 10,000 MMBtu per day of IFERC PEPL basis swaps with an average differential to NYMEX HH of $(0.98) per MMBtu.

Approximately $130 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 June 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.

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 designated these locks as cash flow hedges and a related deferred loss of $8 million, net of tax, was included in AOCL at June 30, 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:

	Six Months Ended
	June 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		137
Reclassed to proved oil and gas properties based on determination of proved reserves		-
Capitalized exploratory well costs charged to expense		-
Capitalized exploratory well costs at end of period	$	386

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

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:

	June 30,		December 31,
	2008		2007
	(in millions, except number of projects)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	277		$	187
Capitalized exploratory well costs that have been capitalized for a period greater than one year after completion of drilling		109			62
Balance at end of period	$	386		$	249
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year after completion of drilling		6			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 June 30, 2008:

			Suspended Since
	Total		2007		2006		2005
	(in millions)
Project
Raton South (deepwater Gulf of Mexico)	$	27	$	4	$	23	$	-
Redrock (deepwater Gulf of Mexico)		17		-		17		-
Blocks O and I (West Africa)		47		27		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	$	109	$	43	$	47	$	19

Exploratory well costs capitalized for more than one year at June 30, 2008 include six projects, two of which include activity in the deepwater Gulf of Mexico. One project relates to Raton South (Mississippi Canyon Block 292) and includes $27 million of suspended exploratory well costs. We currently have a rig on location to drill a sidetrack-appraisal well and further test this prospect. 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 planned sidetrack-appraisal well at Raton South. In addition, we are currently evaluating options to tie back to subsea pipelines and other facilities.

We also incurred exploratory well costs of $47 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 $187 million in suspended costs related to additional drilling activity in West Africa through June 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 we are working with the operator to formulate a development plan.

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

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:

	Six Months Ended
	June 30, 2008
	(in millions)
Asset retirement obligations at beginning of period	$	144
Liabilities incurred in current period		14
Liabilities settled in current period		(7	)
Revisions		6
Accretion expense		4
Asset retirement obligations at end of period	$	161

Accretion expense is included in depreciation, depletion and amortization expense in the consolidated statements of operations.

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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(in millions)
Service cost	$	3		$	3		$	6		$	6
Interest cost		3			2			6			5
Expected return on plan assets		(3	)		(2	)		(6	)		(5	)
Other		1			1			1			2
Net periodic benefit cost	$	4		$	4		$	7		$	8

Note 8 – Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(in millions)
Stock-based compensation expense	$	11		$	7		$	20		$	12
Tax benefit recognized	$	(4	)	$	(3	)	$	(8	)	$	(5	)

During the six months ended June 30, 2008, we granted 1.1 million stock options with a weighted-average grant-date fair value of $20.65 per share and awarded 0.5 million shares of restricted stock subject to service conditions with a weighted-average grant-date fair value of $73.63 per share.

Note 9 – Basic and Diluted Earnings (Loss) Per Share

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

				Weighted				Weighted
	Net			Average		Net		Average
	Income (Loss)			Shares		Income		Shares
	2008					2007
	(in millions, except per share amounts)
Three Months Ended June 30:
Net income (loss)	$	(144	)		172	$	209		171
Basic Earnings (Loss) Per Share	$	(0.84	)			$	1.22

Net income (loss)	$	(144	)		172	$	209		171
Effect of dilutive stock options and restricted stock		-			-		-		2
Net income (loss) available to common shareholders	$	(144	)		172	$	209		173
Diluted Earnings (Loss) Per Share	$	(0.84	)			$	1.21

Six Months Ended June 30:
Net income	$	71			172	$	421		171
Basic Earnings Per Share	$	0.41				$	2.46

Net income	$	71			172	$	421		171
Effect of dilutive stock options and restricted stock		-			3		-		2
Net income available to common shareholders	$	71			175	$	421		173
Diluted Earnings Per Share	$	0.41				$	2.43

A total of 1.1 million weighted average shares of our common stock held in a rabbi trust and weighted average stock options were antidilutive for both the second quarter and the first six months of 2008 and were excluded from the calculation of diluted earnings per share. A total of 2.8 million and 2.6 million weighted average shares of our common stock held in a rabbi trust and weighted average stock options were antidilutive for second quarter and the first six months of 2007, respectively, and were excluded from the calculation of diluted earnings per share.

Note 10 – Income Taxes

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008		2007
	(in millions)
Current	$	(28	)	$	28	$	38	$	72
Deferred		(26	)		56		10		104
Total income tax (benefit) provision	$	(54	)	$	84	$	48	$	176

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.

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 as of June 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 June 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 - 2004, Equatorial Guinea - 2006, China - 2006, Israel - 2000, UK - 2006 and the Netherlands - 2005.

Note 11 – Comprehensive Income (Loss)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(in millions)
Net income (loss)	$	(144	)	$	209		$	71		$	421
Other items of comprehensive income (loss)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		95			11			155			(4	)
Less tax provision		(36	)		(4	)		(58	)		1
Unrealized change in fair value:		-			18			-			(82	)
Less tax provision		-			(7	)		-			31
Interest rate cash flow hedges:
Unrealized change in fair value		32			-			(11	)		-
Less tax provision		(12	)		-			4			-
Net change in other:		-			1			(1	)		2
Other comprehensive income (loss)		79			19			89			(52	)


Comprehensive income (loss)	$	(65	)	$	228		$	160		$	369

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 and production: the US, West Africa, the North Sea, Israel, and Other International, Corporate and Marketing. Other International includes Argentina (through February 2008), China, Ecuador and Suriname.

In February 2008, we closed on the sale of our interest in Argentina for a sales price of $117.5 million, effective July 1, 2007. The gain on sale has been deferred, as the sale is contingent upon approval of the Argentine government. We are currently unable to predict when government approval will be obtained. The Argentina operations, financial position and cash flows are not material for the current or prior periods and have not been segregated as discontinued operations.

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 June 30, 2008
Revenues from third parties	$	1,244		$	752		$	163		$	99	$	30	$	200
Amount reclassified from AOCL (1)		(95	)		(84	)		(11	)		-		-		-
Intersegment revenue		-			144			-			-		-		(144	)
Income from equity method investees		56			-			56			-		-		-
Total Revenues		1,205			812			208			99		30		56

DD&A		196			165			9			12		5		5
Loss on commodity derivative instruments		828			677			151			-		-		-
Income (loss) before taxes		(198	)		(214	)		38			72		23		(117	)

Three Months Ended June 30, 2007
Revenues from third parties	$	756		$	426		$	122		$	62	$	24	$	122
Amount reclassified from AOCL (1)		(11	)		(11	)		-			-		-		-
Intersegment revenue		-			71			-			-		-		(71	)
Income from equity method investees		49			-			49			-		-		-
Total Revenues		794			486			171			62		24		51

DD&A		183			149			7			15		4		8
Loss on involuntary conversion		38			38			-			-		-		-
Gain on commodity derivative instruments		(1	)		(1	)		-			-		-		-
Income (loss) before taxes		293			160			142			27		18		(54	)

Six Months Ended June 30, 2008
Revenues from third parties	$	2,267		$	1,329		$	304		$	191	$	70	$	373
Amount reclassified from AOCL (1)		(155	)		(132	)		(23	)		-		-		-
Intersegment revenue		-			260			-			-		-		(260	)
Income from equity method investees		118			-			118			-		-		-
Total Revenues		2,230			1,457			399			191		70		113

DD&A		399			329			18			28		11		13
Loss on commodity derivative instruments		1,065			886			179			-		-		-
Income (loss) before taxes		119			(68	)		188			127		54		(182	)

Six Months Ended June 30, 2007
Revenues from third parties	$	1,438		$	809		$	185		$	117	$	49	$	278
Amount reclassified from AOCL (1)		4			4			-			-		-		-
Intersegment revenue		-			167			-			-		-		(167	)
Income from equity method investees		95			-			95			-		-		-
Total Revenues		1,537			980			280			117		49		111

DD&A		349			287			10			28		8		16
Loss on involuntary conversion		51			51			-			-		-		-
Gain on commodity derivative instruments		(2	)		(2	)		-			-		-		-
Income (loss) before taxes		597			377			226			60		37		(103	)
Total assets at June 30, 2008 (2)	$	11,937		$	8,693		$	1,605		$	707	$	267	$	665
Total assets at December 31, 2007 (2)		10,831			7,918			1,355			562		268		728

(1)	Revenues include increases (decreases) resulting from hedging activities. The 2008 decreases resulted from hedge gains and losses that were deferred in AOCL as of December 31, 2007 and subsequently reclassified to revenues.

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

Note 13 – Commitments and Contingencies

Purchaser Bankruptcy – We have a potential 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 21, 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 June 30, 2008, we had a receivable of approximately $42 million from SemCrude. Including sales of crude oil production to SemCrude during the period July 1 – 21, 2008, we estimate the current receivable balance to be approximately $73 million. We are pursuing various legal remedies to protect our interests. We are currently unable to quantify the amount of the receivable balance, if any, that is uncollectible. However, we believe that ultimate disposition of this matter will not have a material adverse affect on our liquidity or overall financial position.

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. Trial is currently set for September 29, 2008. 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.

SFAS 162 – In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP (the GAAP hierarchy). SFAS 162 is effective 60 days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We are currently evaluating the provisions of SFAS 162 and assessing the impact, if any, it may have on our financial position and results of operations.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

We are a worldwide producer of crude oil, 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.

Effective January 1, 2008, we discontinued cash flow hedge accounting on all existing commodity derivative instruments. We voluntarily 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 in the period in which they occur. The discontinuance of cash flow hedge accounting for commodity derivative instruments 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. For the second quarter of 2008, we recognized an unrealized $716 million mark-to-market loss on commodity derivative instruments.

Financial results for second quarter 2008 also included the following:

net loss of $144 million, as compared with net income of $209 million for 2007;

diluted loss per share of $0.84, as compared with diluted earnings per share of $1.21 for 2007; and

cash flow from operating activities of $648 million, as compared with $351 million for 2007.

Operational results for second quarter 2008 included the following:

9% overall increase in sales volumes over 2007 with growth in both the US and international operations;

execution of agreement to acquire producing properties in western Oklahoma;

successful Benita oil appraisal well, offshore Equatorial Guinea; and

exploration discoveries offshore Equatorial Guinea at Diega and Felicita.

Mid-continent Acquisition – In July 2008, we acquired producing properties in western Oklahoma for $291 million in cash, subject to customary adjustments. Properties acquired cover approximately 15,500 net acres and are currently producing 25 MMcfepd with approximately 75% natural gas and 25% liquids. We will operate the assets with an average working interest of 83%, with plans to double production over the next two years.

OUTLOOK

We expect crude oil, natural gas and condensate 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;

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:

potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas of our US operations;

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;

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

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 30% of the 2008 capital forecast has been allocated to exploration opportunities, including additions for the deepwater lease sale and other leasehold acquisitions. Approximately 70% of the 2008 capital forecast has been allocated to acquisitions, production, development and other projects. US expenditures are forecast at $1.835 billion, international expenditures are forecast at $486 million and corporate expenditures are forecast at $36 million. We expect that our 2008 capital forecast will be funded primarily from cash flows from operations and borrowings under our revolving credit facility. We will evaluate the level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations, and property acquisitions and divestitures.

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

RESULTS OF OPERATIONS

Oil, Gas and NGL Sales

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

	Sales Volumes						Average Realized Sales Prices
	Crude Oil &		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 June 30, 2008
United States (2)		44		402		10		$	99.05	$	9.82	$	59.65
West Africa (3)		14		222		-			112.32		0.27		-
North Sea		8		5		-			126.05		10.81		-
Israel		-		121		-			-		2.72		-
Ecuador (4)		-		22		-			-		-		-
Other International		4		-		-			109.17		-		-
Total Consolidated Operations		70		772		10			105.46		5.86		59.65
Equity Investees (5)		2		-		7			118.95		-		69.70
Total		72		772		17		$	105.74	$	5.86	$	63.75
Three Months Ended June 30, 2007
United States (2)		45		418		-		$	51.34	$	7.25	$	-
West Africa (3)		19		116		-			69.23		0.29		-
North Sea		10		5		-			67.88		4.81		-
Israel		-		97		-			-		2.70		-
Ecuador (4)		-		22		-			-		-		-
Other International		7		-		-			50.51		-		-
Total Consolidated Operations		81		658		-			57.42		5.27		-
Equity Investees (5)		2		-		7			70.76		-		44.60
Total		83		658		7		$	57.76	$	5.27	$	44.60

Six Months Ended June 30, 2008
United States (2)		43		397		10		$	85.36	$	9.40	$	57.55
West Africa (3)		15		221		-			100.16		0.27		-
North Sea		9		6		-			112.36		10.18		-
Israel		-		133		-			-		2.90		-
Ecuador (4)		-		23		-			-		-		-
Other International		5		-		-			87.47		-		-
Total Consolidated Operations		72		780		10			91.88		5.60		57.55
Equity Investees (5)		2		-		7			107.01		-		65.50
Total		74		780		17		$	92.24	$	5.60	$	60.80
Six Months Ended June 30, 2007
United States (2)		45		413		-		$	48.88	$	7.74	$	-
West Africa (3)		16		86		-			64.15		0.31		-
North Sea		10		6		-			64.45		5.51		-
Israel		-		100		-			-		2.72		-
Ecuador (4)		-		26		-			-		-		-
Other International		7		-		-			47.87		-		-
Total Consolidated Operations		78		631		-			53.75		5.83		-
Equity Investees (5)		2		-		6			65.46		-		42.34
Total		80		631		6		$	54.04	$	5.83	$	42.34

(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 volumes from 2007 to 2008.

(2)

Average realized crude oil and condensate prices reflect reductions of $20.46 per Bbl and $9.74 per Bbl for second quarter 2008 and 2007, respectively, and reductions of $21.13 per Bbl and $8.30 per Bbl for the first six months of 2008 and 2007, respectively, from hedging activities. Average realized natural gas prices reflect a reduction of $0.06 per Mcf and an increase of $0.77 per Mcf for second quarter 2008 and 2007, respectively, and increases of $0.49 per Mcf and $0.96 per Mcf for the first six months of 2008 and 2007, respectively, from hedging activities. The 2008 price reductions resulted from hedge gains and losses that were deferred in AOCL as of December 31, 2007.

(3)

Average realized crude oil and condensate prices reflect reductions of $8.20 per Bbl for second quarter 2008 and $8.42 per Bbl for the first six months of 2008 from hedging activities. The 2008 price reductions resulted from hedge gains and losses that were deferred in AOCL as of December 31, 2007. Hedging activities had no effect on West Africa prices in the first six months of 2007. 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 175 MMcfpd and 58 MMcfpd during second quarter 2008 and 2007, respectively, and 174 MMcfpd and 30 MMcfpd during the first six 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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(MBopd)
United States		44		45		43		45
West Africa		15		16		15		16
North Sea		9		11		10		10
Other International		4		7		5		7
Total Consolidated Operations		72		79		73		78
Equity Investees		2		2		2		2
Total		74		81		75		80

Revenues from sales of commodities were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(in millions)
Crude oil and condensate sales	$	674	$	422	$	1,200	$	755
Natural gas sales		399		305		771		639
NGL sales (1)		57		-		103		-
Total	$	1,130	$	727	$	2,074	$	1,394

(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 volumes from 2007 to 2008.

Crude Oil and Condensate Sales – During second quarter 2008, crude oil and condensate sales increased a net $252 million, or 60%, as compared with second quarter 2007. US sales increased by $186 million, or 88%, and international sales increased $66 million, or 31%.

During the first six months of 2008, crude oil and condensate sales increased a net $445 million, or 59%, as compared with the first six months of 2007. US sales increased by $273 million, or 68%, from the first six months of 2007, and international sales increased $172 million, or 49%.

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:

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

timing of hydrocarbon tanker liftings in Equatorial Guinea and 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 $93 million and $40 million for second quarter 2008 and 2007, respectively, and decreases of $190 million and $68 million for the first six months of 2008 and 2007, respectively.

Natural Gas Sales – During second quarter 2008, natural gas sales increased a net $94 million, or 31%, as compared with second quarter 2007. US sales increased $83 million, or 30%, and international sales increased $11 million, or 38%.

During the first six months of 2008, natural gas sales increased a net $132 million, or 21%, as compared with the first six months of 2007. US sales increased $101 million, or 17%, and international sales increased $31 million, or 52%.

Factors contributing to the changes in natural gas sales included:

higher commodity prices;

our 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:

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.

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 $2 million and an increase of $29 million for second quarter 2008 and 2007, respectively, and increases of $35 million and $72 million for the first six 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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Net income (in millions)
AMPCO and affiliates	$	17	$	11	$	45	$	36
Alba Plant	$	39	$	38	$	73	$	59
Distributions/Dividends (in millions)
AMPCO	$	5	$	21	$	39	$	42
Alba Plant	$	40	$	23	$	82	$	55
Sales volumes
Methanol (Mgal)		36		34		70		73
Condensate (MBopd)		2		2		2		2
LPG (MBpd)		7		7		7		6
Production volumes
Methanol (Mgal)		31		40		63		81
Condensate (MBopd)		2		2		2		2
LPG (MBpd)		6		7		6		6
Average realized prices
Methanol (per gallon)	$	1.15	$	0.87	$	1.38	$	1.06
Condensate (per Bbl)	$	118.95	$	70.76	$	107.01	$	65.46
LPG (per Bbl)	$	69.70	$	44.60	$	65.50	$	42.34

Net income from AMPCO increased $6 million, or 55%, during second quarter 2008 as compared with second quarter 2007 and increased $9 million, or 25%, during the first six months of 2008 as compared with the first six months of 2007 primarily due to higher average realized methanol prices. The decreases in methanol production volumes were due to down time for compressor and other equipment maintenance.

Net income from Alba Plant increased $1 million, or 3%, during second quarter 2008 as compared with second quarter 2007 and increased $14 million, or 24%, during the first six months of 2008 as compared with the first six 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.

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 June 30, 2008
Oil and gas operating costs (2)	$	80	$	56	$	10	$	9	$	2	$	3
Workover and repair expense		8		8		-		-		-		-
Lease operating expense		88		64		10		9		2		3
Production and ad valorem taxes		51		41		-		-		-		10
Transportation expense		16		14		-		2		-		-
Total production costs	$	155	$	119	$	10	$	11	$	2	$	13

Three Months Ended June 30, 2007
Oil and gas operating costs (2)	$	77	$	51	$	11	$	7	$	2	$	6
Workover and repair expense		6		6		-		-		-		-
Lease operating expense		83		57		11		7		2		6
Production and ad valorem taxes		28		24		-		-		-		4
Transportation expense		16		14		-		2		-		-
Total production costs	$	127	$	95	$	11	$	9	$	2	$	10

Six Months Ended June 30, 2008
Oil and gas operating costs (2)	$	156	$	105	$	19	$	20	$	4	$	8
Workover and repair expense		14		14		-		-		-		-
Lease operating expense		170		119		19		20		4		8
Production and ad valorem taxes		94		74		-		-		-		20
Transportation expense		29		25		-		4		-		-
Total production costs	$	293	$	218	$	19	$	24	$	4	$	28

Six Months Ended June 30, 2007
Oil and gas operating costs (2)	$	151	$	106	$	18	$	13	$	4	$	10
Workover and repair expense		10		10		-		-		-		-
Lease operating expense		161		116		18		13		4		10
Production and ad valorem taxes		54		44		-		-		-		10
Transportation expense		27		22		-		4		-		1
Total production costs	$	242	$	182	$	18	$	17	$	4	$	21

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

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

Total production costs increased $28 million, or 22%, during second quarter 2008 as compared with second quarter 2007 and increased $51 million, or 21%, during the first six months of 2008 as compared with the first six months of 2007. US lease operating expense increased from 2007 primarily due to expenses relating to increased workover activity and higher costs related to the continuing active drilling program in the Northern region. These increases were partially offset by a decrease in insurance costs for our Gulf of Mexico deepwater operations related to a change in insurance coverage made second quarter 2007. North Sea oil and gas operating costs for the second quarter and first six 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.

Selected expenses on a per BOE basis were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007

Oil and gas operating costs	$	4.23	$	4.41	$	4.05	$	4.58
Workover and repair expense		0.42		0.35		0.38		0.30
Lease operating expense		4.65		4.76		4.43		4.88
Production and ad valorem taxes		2.67		1.66		2.45		1.63
Transportation expense		0.81		0.93		0.74		0.82
Total production costs (1) (2) (3)	$	8.13	$	7.35	$	7.62	$	7.33

(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 $1.32 per BOE and $0.40 per BOE for second quarter 2008 and 2007, respectively, and $1.21 per BOE and $0.21 per BOE for the first six 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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(in millions)
Oil and gas exploration expense (1)	$	103	$	54	$	143	$	99

(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 increased $49 million during second quarter 2008 as compared with second quarter 2007 and $44 million during the first six months of 2008 as compared with the first six months of 2007. The increases were 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 Gulf of Mexico.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(in millions, except unit rate)
DD&A expense - property, plant and equipment	$	194	$	181	$	395	$	345
Accretion of discount on asset retirement obligations		2		2		4		4
Total DD&A expense	$	196	$	183	$	399	$	349
Unit rate per BOE (1) (2)	$	10.30	$	10.58	$	10.36	$	10.57

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

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 $1.34 per BOE and $0.46 per BOE for second quarter 2008 and 2007, respectively, and $1.32 per BOE and $0.24 per BOE for the first six months of 2008 and 2007, respectively.

Total DD&A expense for the second quarter and first six 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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
G&A expense (in millions)	$	61	$	48	$	121	$	93
Unit rate per BOE (1) (2)	$	3.21	$	2.76	$	3.15	$	2.81

(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 $0.52 per BOE and $0.14 per BOE for second quarter 2008 and 2007, respectively, and $0.50 per BOE and $0.07 per BOE for the first six months of 2008 and 2007, respectively.

G&A expense increased during the second quarter and first six 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 $4 million and $8 million during the second quarter and first six months of 2008, respectively, as compared with 2007.

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

Loss (Gain) on Commodity Derivative Instruments – 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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(in millions)
Interest expense	$	23		$	34		$	49		$	64
Capitalized interest		(6	)		(3	)		(15	)		(6	)
Interest expense, net	$	17		$	31		$	34		$	58

Interest expense decreased during the second quarter and first six months of 2008, as compared with 2007 due to declining interest rates applicable to our credit facility from 5.67% at June 30, 2007 to 2.84% at June 30, 2008 and a slightly lower average outstanding debt balance.

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 (Benefit) – The income tax provision (benefit) was as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Income tax provision (benefit) (in millions)	$	(54	)	$	84		$	48		$	176
Effective rate		27.3	%		28.7	%		40.3	%		29.5	%

Our effective tax rate increased during the first six months of 2008 as compared with 2007. Certain tax items that normally have a small effect on the effective rate have had a greater impact during 2008 due to our lower pretax income. Pretax income was lower for the first six months of 2008 due to the impact of mark to market commodity derivative losses. One tax item that affected the rate was the recognition of losses from certain controlled foreign corporations, primarily Suriname, for which no foreign tax benefit was recognized. This rate increase was partially offset by the impact of an increase in earnings of our equity method investees. Earnings from equity method investees represent a favorable permanent difference in calculating income tax expense. These earnings increased during the current period even though the tax holiday for the Alba Plant in Equatorial Guinea expired at the end of 2007.

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.

Cash and Cash Equivalents – We had $983 million in cash and cash equivalents at June 30, 2008, compared with $660 million at December 31, 2007. Approximately 90% of this cash is attributable to our foreign subsidiaries and would be subject to additional US income taxes if repatriated. The 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. We currently intend to use our international cash to fund international projects, including the development of West Africa.

We are monitoring the current conditions in the credit markets. 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 negatively impacted. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.

Commodity Derivative Instruments – As of June 30, 2008, we had a net liability of $1.3 billion relating to commodity derivative instruments. We estimated the fair value of this liability 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 LIBOR rates, Eurodollar futures rates and interest swap rates. We adjust the discount rate used to value our commodity derivative liabilities to include a measure of non-performance risk, consisting of the current published credit default swap spread on our public debt. 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.

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 June 30, 2008, the current portion of our commodity derivative liability totaled $964 million. We are not subject to significant margin calls by our counterparties. 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.

Contractual Obligations – During second quarter 2008, we entered into a drilling and equipment contract for our international operations totaling $278 million. Had this contract 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, as amended, for the year ended December 31, 2007, our international drilling and equipment obligations would be $115 million in 2008, $75 million in 2009, $90 million in 2010 and $66 million in 2011 for a total of $346 million.

Cash Flows

Cash flow information is as follows:

	Six Months Ended
	June 30,
	2008			2007
	(in millions)
Total cash provided by (used in):
Operating activities	$	1,154		$	773
Investing activities		(823	)		(695	)
Financing activities		(8	)		71
Increase in cash and cash equivalents	$	323		$	149

Operating Activities – Net cash provided by operating activities was $1.2 billion for the first six months of 2008, as compared with $773 million for the first six months of 2007. The increase was primarily due to higher commodity prices.

Investing Activities – Net cash used in investing activities was $823 million for the first six months of 2008, as compared with $695 million for the first six months of 2007. Investing activities in 2008 consisted of $932 million in capital expenditures offset by $109 million in proceeds from asset sales. Investing activities in 2007 consisted entirely of capital expenditures. See Acquisition, Capital and Other Exploration Expenditures below.

Financing Activities – Net cash used in financing activities was $8 million for the first six months of 2008, as compared with $71 million provided by financing activities for the first six months of 2007. During 2008 and 2007, cash flows provided by financing activities included proceeds from the exercise of stock options and related excess tax benefits. Cash flows used in financing activities during 2008 and 2007 included dividends paid on common stock. In addition, there were net proceeds from borrowings of $180 million in 2007, while there were no net proceeds from borrowings 2008. 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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(in millions)
Acquisition, Capital and Other Exploration Expenditures
Unproved property acquisition	$	87	$	103	$	263	$	106
Proved property acquisition		-		6		-		6
Exploration expenditures		198		91		243		152
Development expenditures		261		271		506		482
Corporate and other expenditures		15		10		34		19
Total capital expenditures	$	561	$	481	$	1,046	$	765

Unproved property acquisition cost for the first six months of 2008 includes deepwater lease blocks acquired in the March 2008 Gulf of Mexico lease sale and a prepayment on the Mid-continent acquisition completed in July 2008.

Sale of Argentina Assets – In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The sale is subject to Argentine government approval. We are currently unable to predict when government approval will be obtained.

Financing Activities

Long-Term Debt – Our long-term debt totaled $1.9 billion (net of unamortized discount) at June 30, 2008. Maturities range from 2011 to 2097. Our ratio of debt-to-book capital was 27% at June 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 a $2.1 billion unsecured revolving credit facility. The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. The credit facility (i) provides for credit facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregate amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the credit facility. The credit facility is with certain commercial lending institutions and is available for general corporate purposes. At June 30, 2008, $1.2 billion in borrowings were outstanding under the credit facility. The weighted average interest rate applicable to borrowings under the credit facility at June 30, 2008 was 2.84%.

Installment Payment Due – 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 3.00% at June 30, 2008.

Short-Term Borrowings – Our credit facility is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. Other than the installment payment discussed above, there were no short-term borrowings outstanding at June 30, 2008.

Dividends – We paid cash dividends of 30 cents per share of common stock during the first six months of 2008 and 19.5 cents per share of common stock during the first six months of 2007. On July 22, 2008, our Board of Directors declared a quarterly cash dividend of 18.0 cents per common share, payable August 18, 2008 to shareholders of record on August 4, 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 $24 million from the exercise of stock options during the first six months of 2008 as compared to $16 million during the first six months of 2007.

Common Stock Repurchases – During the first six 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 shares issued under stock-based compensation plans. During the first six 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.

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. We believe that we are well positioned with our mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.

At June 30, 2008, we had entered into variable to fixed price 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 $1.3 billion. Based on the June 30, 2008 published forward commodity price curves for the underlying commodities, simultaneous price increases of $1.00 per Bbl for crude oil and $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $23 million. 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 June 30, 2008, we had $1.9 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, $1.2 billion at June 30, 2008, was variable-rate debt. We also had $25 million in a current installment payment at June 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 June 30, 2008 balance of variable-rate debt would result in a change in annual interest expense of approximately $3 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 June 30, 2008, AOCL included $11 million, net of tax, related to interest rate locks. A portion of this amount is currently being reclassified into earnings as adjustments to interest expense over the term of our 5¼% Senior Notes due April 2014. The remainder relates to interest rate locks that were settled in July 2008. See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities.

We are also exposed to interest rate risk related to our short-term investments. As of June 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 June 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.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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

our growth strategies;

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

anticipated trends in our business;

our future results of operations;

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

market conditions in the oil and gas industry;

our ability to make and integrate acquisitions; and

the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included herein, if any, and included in our 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. There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

None.

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

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
							(in millions)
April 1 - April 30, 2008		-	$	-		-		-
May 1 - May 31, 2008		8,138		99.23		-		-
June 1 - June 30, 2008		-		-		-		-
Total		8,138	$	99.23		-		-

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

(a)	Our annual stockholders meeting was held at 9:30 a.m., Central Time, on Tuesday, April 22, 2008 in The Woodlands, Texas.

(b)	Proxies were solicited by our Board of Directors pursuant to Regulation 14A under the Securities Exchange Act of 1934. There was no solicitation in opposition to the Board of Directors’ nominees as listed in the proxy statement and all such nominees were duly elected.

(c)	Out of a total of 172,105,199 shares of our common stock outstanding and entitled to vote, 159,662,000 shares were present in person or by proxy, representing 92.77% of the outstanding shares of common stock.

The stockholder voting results are as follows:

Proposal I. Election of our Board of Directors to serve until the next annual stockholders meeting.

	Number of Shares Voting for Election As Director	Number of Shares Withholding Authority To Vote for Election As Director
Jeffrey L. Berenson	145,897,440	13,764,560
Michael A. Cawley	143,308,680	16,353,320
Edward F. Cox	143,290,423	16,371,577
Charles D. Davidson	144,994,224	14,667,776
Thomas J. Edelman	145,421,648	14,240,352
Kirby L. Hedrick	145,911,675	13,750,325
Scott D. Urban	156,969,129	2,692,871
William T. Van Kleef	145,988,031	13,673,969

Proposal II. Ratification of appointment of KPMG LLP as our independent auditors.

(For 157,446,653; Against 1,163,741; Abstaining 1,051,606)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

SIGNATURES

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

	NOBLE ENERGY, INC.
	(Registrant)

Date	July 30, 2008		/s/ CHRIS TONG
			CHRIS TONG Senior Vice President and Chief Financial Officer

INDEX TO EXHIBITS

Exhibit

Number

Exhibit

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).