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 March 31, 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 April 15, 2008: 172,212,293.

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
	March 31,
	2008			2007
Revenues
Oil, gas and NGL sales	$	944		$	667
Income from equity method investees		62			46
Other revenues		19			30
Total		1,025			743
Costs and Expenses
Lease operating costs		82			79
Production and ad valorem taxes		43			25
Transportation expense		13			11
Exploration expense		40			45
Depreciation, depletion and amortization		203			166
General and administrative		60			45
Other operating expense, net		21			29
Total		462			400
Operating Income		563			343
Other (Income) Expense
Loss (gain) on commodity derivative instruments		237			(1	)
Interest, net of amount capitalized		17			27
Other (income) expense, net		(7	)		13
Total		247			39
Income Before Income Taxes		316			304
Income Tax Provision		101			92
Net Income	$	215		$	212

Earnings Per Share
Basic	$	1.25		$	1.24
Diluted	$	1.20		$	1.22

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

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

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

		(unaudited)March 31,		December 31,
		2008		2007
ASSETS
Current Assets
Cash and cash equivalents	$	807	$	660
Accounts receivable - trade, net		727		594
Deferred income taxes		125		131
Other current assets		117		184
Total current assets		1,776		1,569
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)		10,684		10,217
Other property, plant and equipment		117		112
		10,801		10,329
Accumulated depreciation, depletion and amortization		(2,594)		(2,384)
Total property, plant and equipment, net		8,207		7,945
Goodwill		759		761
Other noncurrent assets		540		556
Total Assets	$	11,282	$	10,831

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade	$	731	$	781
Commodity derivative instruments		623		540
Other current liabilities		429		315
Total current liabilities		1,783		1,636
Deferred income taxes		2,019		1,984
Asset retirement obligations		148		131
Commodity derivative instruments		109		83
Other noncurrent liabilities		329		337
Long-term debt		1,851		1,851
Total Liabilities		6,239		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		639		636
Capital in excess of par value		2,133		2,106
Accumulated other comprehensive loss		(274)		(284)
Treasury stock, at cost; 19 million shares		(613)		(613)
Retained earnings		3,158		2,964
Total Shareholders’ Equity		5,043		4,809
Total Liabilities and Shareholders’ Equity	$	11,282	$	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)

	Three Months Ended
	March 31,
	2008			2007
Cash Flows From Operating Activities
Net income	$	215		$	212
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization - oil and gas production		203			166
Deferred income taxes		35			48
Income from equity method investees		(62	)		(46	)
Dividends received from equity method investees		76			53
Unrealized loss (gain) on commodity derivative instruments		218			(1	)
Settlement of previously recognized hedge losses		(62	)		(51	)
Other		20			58
Changes in operating assets and liabilities:
(Increase) in accounts receivable		(137	)		(51	)
(Increase) decrease in other current assets		(5	)		34
(Decrease) increase in accounts payable		(61	)		12
Increase (decrease) in other current liabilities		66			(12	)
Net Cash Provided by Operating Activities		506			422

Cash Flows From Investing Activities
Additions to property, plant and equipment		(464	)		(332	)
Proceeds from sale of property, plant and equipment		109			-
Net Cash Used in Investing Activities		(355	)		(332	)

Cash Flows From Financing Activities
Exercise of stock options		10			13
Excess tax benefits from stock-based awards		9			8
Cash dividends paid		(21	)		(13	)
Purchases of treasury stock		(2	)		(102	)
Proceeds from credit facilities		500			115
Repayment of credit facilities		(500	)		(115	)
Proceeds from short term borrowings, net		-			100
Net Cash (Used in) Provided by Financing Activities		(4	)		6
Increase in Cash and Cash Equivalents		147			96
Cash and Cash Equivalents at Beginning of Period		660			153
Cash and Cash Equivalents at End of Period	$	807		$	249

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		-		-		-		-			-			-			215			215
Stock-based compensation expense		-		-		-		9			-			-			-			9
Exercise of stock options		1		-		2		8			-			-			-			10
Tax benefits related to exercise of stock options		-		-		-		9			-			-			-			9
Restricted stock awards, net		-		-		1		(1	)		-			-			-			-
Dividends ($0.12 per share)		-		-		-		-			-			-			(21	)		(21	)
Changes in treasury stock, net		-		-		-		2			-			-			-			2
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		-		-		-		-			38			-			-			38
Interest rate cash flow hedges:
Unrealized change in fair value											(27	)								(27	)
Net change in other		-		-		-		-			(1	)		-			-			(1	)
March 31, 2008		192		19	$	639	$	2,133		$	(274	)	$	(613	)	$	3,158		$	5,043

December 31, 2006		188		17	$	629	$	2,041		$	(140	)	$	(511	)	$	2,095		$	4,114
Net income		-		-		-		-			-			-			212			212
Stock-based compensation expense		-		-		-		5			-			-			-			5
Exercise of stock options		1		-		3		10			-			-			-			13
Tax benefits related to exercise of stock options		-		-		-		8			-			-			-			8
Restricted stock awards, net		1		-		2		(2	)		-			-			-			-
Dividends ($0.075 per share)		-		-		-		-			-			-			(13	)		(13	)
Purchases of treasury stock		-		2		-		-			-			(102	)		-			(102	)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		-		-		-		-			(9	)		-			-			(9	)
Unrealized change in fair value		-		-		-		-			(63	)		-			-			(63	)
Net change in other		-		-		-		-			1			-			-			1
March 31, 2007		190		19	$	634	$	2,062		$	(211	)	$	(613	)	$	2,294		$	4,166

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

Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
(in millions)
(unaudited)

	Three Months Ended
	March 31,
	2008			2007

Net income	$	215		$	212
Other items of comprehensive income (loss)
Oil and gas cash flow hedges
Realized amounts reclassified into earnings		60			(15	)
Less tax provision		(22	)		6
Unrealized change in fair value		-			(100	)
Less tax provision		-			37
Interest rate cash flow hedges
Unrealized change in fair value		(43	)		-
Less tax provision		16			-
Net change in other		(1	)		1
Other comprehensive income (loss)		10			(71	)
Comprehensive income	$	225		$	141

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 NGLs. We have exploration, exploitation and production operations domestically 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 March 31, 2008 (unaudited) and December 31, 2007 and for the three months ended March 31, 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 three-month period ended March 31, 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.

Sale of Argentina Assets – 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. The Argentina operations, financial position and cash flows are not material and have not been reflected as discontinued operations.

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

	Three Months Ended
	March 31,
	2008			2007
	(in millions)
Other Revenues
Electricity sales	$	15		$	23
Gathering, marketing and processing revenues		4			7
Total	$	19		$	30
Other Operating Expense, net
Electricity generation expense	$	15		$	16
Gathering, marketing and processing expense		5			5
Other operating expense, net		1			8
Total	$	21		$	29
Other (Income) Expense, net
Deferred compensation (income) expense	$	(7	)	$	12
Interest income		(6	)		(3	)
Other expense, net		6			4
Total	$	(7	)	$	13

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

	March 31,		December 31,
	2008		2007
	(in millions)
Other Current Assets
Inventories	$	70		$	60
Commodity derivative instruments		24			15
Prepaid expenses and other current assets		21			25
Assets held for sale		-			82
Probable insurance claims		2			2
Total	$	117		$	184
Other Noncurrent Assets
Equity method investments	$	343		$	357
Mutual fund investments		118			124
Probable insurance claims		37			37
Commodity derivative instruments		10			5
Other noncurrent assets		32			33
Total	$	540		$	556
Other Current Liabilities
Accrued and other current liabilities	$	222		$	206
Current income taxes payable		84			52
Current installment of long-term debt		25			25
Asset retirement obligations		11			13
Interest payable		19			18
Interest rate lock derivative instruments		45			1
Deferred gain on asset sale		23			-
Total	$	429		$	315
Other Noncurrent Liabilities
Deferred compensation liability	$	214		$	225
Accrued benefit costs		55			51
Other noncurrent liabilities		60			61
Total	$	329		$	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 did not have a significant impact on our consolidated financial statements. See Note 3 – Fair Value Measurements. We will adopt SFAS No. 157 as it relates to non-financial assets and liabilities on January 1, 2009.

Adoption of SFAS 159 – We adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) as of January 1, 2008. SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. Adoption had no effect on our financial position or results of operations as we made no elections to report selected financial assets or liabilities at fair value.

Adoption of FSP FIN 39-1 – We adopted FSP 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 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 March 31, 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 March 31, 2008, includes the following:

		Fair Value Measurements Using
		Quoted Prices in		Significant Other		Significant					Fair
		Active Markets		Observable Inputs		Unobservable Inputs			Netting		Value
		(Level 1)		(Level 2)		(Level 3)			Adjustment (1)		Measurement
		(in millions)
Financial assets:
Mutual fund investments	$	118	$	-		$	-	$	-		$	118
Commodity derivative instruments		-		49			-		(15	)		34
Financial liabilities:
Commodity derivative instruments		-		(747	)		-		15			(732	)
Interest rate lock derivative instruments		-		(45	)		-		-			(45	)

(1) Amount represents the impact of legally enforceable 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 – We have 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. The discount rate used in the discounted cash flow projections includes a measure of nonperformance risk. 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. Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties and believe that losses from nonperformance are unlikely to be significant. However, we are not able to predict sudden changes in the creditworthiness of our counterparties.

We account for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and 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 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 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 are as follows:

	Three Months Ended
	March 31,
	2008		2007
	(in millions)
Unrealized loss on commodity derivative instruments	$	218	$	-
Realized loss on commodity derivative instruments		19		-
Ineffectiveness gain		-		(1	)
Loss (gain) on commodity derivative instruments	$	237	$	(1	)

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

	Three Months Ended
	March 31,
	2008			2007
	(in millions)
Decrease in crude oil sales	$	(97	)	$	(28	)
Increase in natural gas sales		37			43
Total (decrease) increase in oil and gas sales	$	(60	)	$	15

As of April 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
2nd Qtr 2008	NYMEX WTI		16,500	$	38.33	NYMEX WTI		3,100	$	60.00	$	72.40
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
2nd Qtr 2008	Dated Brent		2,000		88.18	Dated Brent		4,220		45.00		66.65
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		4,700		68.51		79.11
2009	Dated Brent		2,000		87.98	Dated Brent		3,074		45.00		63.04

2010						NYMEX WTI		5,500		69.00		85.65

As of April 23, 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
2nd Qtr 2008	NYMEX HH		170,000	$	5.34	IFERC CIG		14,000	$	6.75	$	8.70
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		120,000		8.74		10.49
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 $180 million of deferred losses (net of taxes) related to the fair values of the commodity derivative instruments previously designated as cash flow hedges and remaining in AOCL at March 31, 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 have entered into two interest rate swaps, or interest rate “locks”, each in the notional amount of $500 million. The locks are based on five and ten year US Treasury rates of 3.55% and 4.15%, respectively, and expire in September 2008. The locks are designated as cash flow hedges and changes in their fair values are reported in AOCL, to the extent the hedges are effective, until the forecasted transactions occur. At that time, we will begin recording the amounts remaining in AOCL as adjustments to interest expense. At March 31, 2008, AOCL included a deferred loss of $28 million, net of tax, related to these interest rate locks.

Note 5 – Capitalized Exploratory Well Costs

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

	Three Months Ended
	March 31, 2008 (1)
		(in millions)
Capitalized exploratory well costs at beginning of period		$	249
Additions to capitalized exploratory well costs pending determination of proved reserves			31
Reclassified to property, plant and equipment based on determination of proved reserves			-
Capitalized exploratory well costs charged to expense			-
Capitalized exploratory well costs at end of period		$	280

(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:

	March 31,		December 31,
	2008		2007
	(in millions)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	203	$	187
Capitalized exploratory well costs that have been capitalized for a period greater than one year after completion of drilling		77		62
Balance at end of period	$	280	$	249
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year after completion of drilling		7		6

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of March 31, 2008:

			Suspended Since
	Total		2007		2006		2005
	(in millions)
Project
Raton South (deepwater Gulf of Mexico)	$	23	$	-	$	23	$	-
Redrock (deepwater Gulf of Mexico)		17		-		17		-
Blocks O and I (West Africa)		19		-		-		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	$	77	$	12	$	46	$	19

Exploratory well costs capitalized for more than one year at March 31, 2008 included seven projects, two of which included activity in the deepwater Gulf of Mexico. One project relates to Raton South (Mississippi Canyon Block 292) and includes $23 million of suspended exploratory well costs. We are currently evaluating a possible sidetrack-appraisal well to be drilled during late 2008 or 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 a successful 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 for the Blocks O and I projects in West Africa. These exploratory well costs totaled $19 million. 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 Block O and Block I projects, we have incurred $160 million in suspended costs related to additional drilling activity in West Africa through March 31, 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:

	Three Months Ended
	March 31, 2008
	(in millions)
Asset retirement obligations at beginning of period	$	144
Liabilities incurred in current period		14
Liabilities settled in current period		(4	)
Revisions		3
Accretion expense		2
Asset retirement obligations at end of period	$	159

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 qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. Net periodic benefit cost related to the retirement and restoration plans was as follows:

	Three Months Ended
	March 31,
	2008			2007
	(in millions)
Service cost	$	3		$	3
Interest cost		3			3
Expected return on plan assets		(3	)		(3	)
Other		-			1
Net periodic benefit cost	$	3		$	4

Note 8 – Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended
	March 31,
	2008			2007
	(in millions)
Stock-based compensation expense	$	9		$	5
Tax benefit recognized		(3	)		(2	)

During the three months ended March 31, 2008, we granted 1,114,288 stock options with a weighted-average grant-date fair value of $20.34 per share and awarded 438,976 shares of restricted stock subject to service conditions with a weighted-average grant-date fair value of $72.98 per share.

Note 9 – Basic and Diluted Earnings Per Share

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

	Three Months Ended March 31,
	2008					2007
				Weighted				Weighted
	Net			Average		Net		Average
	Income			Shares		Income		Shares
	(in millions, except per share amounts)
Net income	$	215			172	$	212		171
Basic Earnings Per Share	$	1.25				$	1.24
Net income	$	215			172	$	212		171
Plus incremental shares from assumed conversions:
Dilutive options, restricted stock awards and shares of common stock in rabbi trust		(4	)		3		-		2
Net income available to common shareholders	$	211			175	$	212		173
Diluted Earnings Per Share	$	1.20				$	1.22

A total of 1.2 million weighted average stock options and restricted shares were antidilutive for first quarter 2008 and were excluded from the calculation of diluted earnings per share. A total of 2.5 million weighted average stock options, restricted shares and shares of our common stock held in a rabbi trust were antidilutive for first quarter 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
	March 31,
	2008		2007
	(in millions)
Current	$	66	$	44
Deferred		35		48
Total income tax provision	$	101	$	92

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 March 31, 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 March 31, 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 – 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 United States, West Africa, the North Sea, Israel, and Other International, Corporate and Marketing. Other International includes Argentina, China, Ecuador and Suriname. The following data was prepared on the same basis as our consolidated financial statements 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 March 31, 2008
Revenues from third parties (1)	$	963		$	529		$	129	$	92	$	40	$	173
Intersegment revenue		-			116			-		-		-		(116	)
Income from equity method investments		62			-			62		-		-		-
Total Revenues		1,025			645			191		92		40		57

DD&A		203			164			9		16		6		8
Loss on commodity derivative instruments		237			209			28		-		-		-
Income (loss) before income taxes		316			145			150		55		31		(65	)

Three Months Ended March 31, 2007
Revenues from third parties (1)	$	697		$	398		$	64	$	55	$	25	$	155
Intersegment revenue		-			96			-		-		-		(96	)
Income from equity method investments		46			-			46		-		-		-
Total Revenues		743			494			110		55		25		59

DD&A		166			140			3		12		4		7
Gain on commodity derivative instruments		(1	)		(1	)		-		-		-		-
Income (loss) before income taxes		304			218			83		32		20		(49	)
Total assets at March 31, 2008 (2)	$	11,282		$	8,276		$	1,472	$	588	$	272	$	674
Total assets at December 31, 2007(2)		10,831			7,918			1,355		562		268		728

(1)

The US reporting unit includes a $48 million decrease to revenues for first quarter 2008 and a $15 million increase to revenues for first quarter 2007 from hedging activities. The West Africa reporting unit includes a $12 million decrease to revenues for first quarter 2008 from hedging activities. Hedging activities had no effect on West Africa revenues first quarter 2007. 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 March 31, 2008 and $761 million at December 31, 2007.

Note 12 – Commitments and Contingencies

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. By order dated April 15, 2008, the April 14, 2008 trial was postponed 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 do not believe that the ultimate disposition of such proceedings will have a material adverse effect on our financial position, results of operations or cash flows.

Note 13 – Recently Issued Pronouncements

SFAS 141(R) and SFAS 160 – In December 2007, the FASB issued SFAS 141(R), “Business Combinations” (“SFAS 141(R)”) and SFAS 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 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.

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 domestic 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 first quarter 2008, net income included an unrealized $218 million mark-to-market loss on commodity derivative instruments.

First quarter 2008 financial results also included the following:

net income of $215 million, as compared with $212 million for first quarter 2007;

diluted earnings per share of $1.20, as compared with $1.22 for first quarter 2007; and

cash flow from operating activities of $506 million, as compared with $422 million for first quarter 2007.

First quarter 2008 operational results included the following:

a 22% overall increase in sales volumes over first quarter 2007;

continued production growth in the Rocky Mountain area of our US operations;

record natural gas sales in Israel;

new Ticonderoga development wells brought online in the deepwater Gulf of Mexico; and

successful high bids on 15 deepwater lease blocks in the Central Gulf of Mexico Lease Sale 206.

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 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; and

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

2008 Capital Expenditures – We have forecasted capital expenditures of approximately $1.9 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 production, development and other projects. US expenditures are forecast at $1.4 billion, international expenditures are forecast at $463 million and corporate expenditures are forecast at $31 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 13 – 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 March 31, 2008
United States (2)		43		393		9	$	71.33	$	8.97	$	55.15
West Africa (3)		15		220		-		88.79		0.27		-
North Sea		9		6		-		100.46		9.65		-
Israel		-		145		-		-		3.04		-
Ecuador (4)		-		23		-		-		-		-
Other International		6		-		-		73.37		-		-
Total Consolidated Operations		73		787		9		78.89		5.34		55.15
Equity Investees (5)		2		-		6		98.55		-		60.78
Total		75		787		15	$	79.43	$	5.34	$	57.47
Three Months Ended March 31, 2007
United States (2)		46		408		-	$	46.42	$	8.24	$	-
West Africa (3)		12		55		-		56.25		0.36		-
North Sea		9		7		-		60.85		6.02		-
Israel		-		103		-		-		2.73		-
Ecuador (4)		-		30		-		-		-		-
Other International		7		1		-		45.24		1.00		-
Total Consolidated Operations		74		604		-		49.73		6.46		-
Equity Investees (5)		2		-		5		59.35		-		39.25
Total		76		604		5	$	49.96	$	6.46	$	39.25

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

(2)

Average realized crude oil and condensate prices reflect reductions of $21.81 per Bbl for first quarter 2008 and $6.85 per Bbl for first quarter 2007 from hedging activities. Average realized natural gas prices reflect increases of $1.05 per Mcf for first quarter 2008 and $1.17 per Mcf for first quarter 2007 from hedging activities. The 2008 price reductions and increases 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 $8.62 per Bbl for first quarter 2008 from hedging activities. The 2008 price reductions resulted from hedge losses that were deferred in AOCL as of December 31, 2007. Hedging activities had no effect on West Africa prices in first quarter 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 173 MMcfpd during first quarter 2008 and 1 MMcfpd during first quarter 2007. 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 of $15 million and $23 million are included in other revenues for first quarter 2008 and 2007, respectively.

(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 March 31,
	2008		2007
	(MBopd)
United States		43		46
West Africa		15		16
North Sea		11		9
Other International		6		8
Total Consolidated Operations		75		79
Equity Investees		2		2
Total		77		81

Revenues from sales of commodities were as follows:

	Three Months Ended
	March 31,
	2008		2007
	(in millions)
Crude oil and condensate sales	$	527	$	333
Natural gas sales		371		334
NGL sales (1)		46		-
Total	$	944	$	667

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

Crude Oil and Condensate Sales – Sales of crude oil and condensate increased a net $194 million, or 58%, during first quarter 2008 as compared with first quarter 2007 due primarily to higher worldwide commodity prices. US sales increased by $88 million, or 46%, from first quarter 2007. However, the effect of commodity price increases was offset by a net decrease in US sales volumes. Growth in the Rocky Mountain area was offset by declining production in the Gulf Coast onshore and Mid-continent areas.

International sales increased $106 million, or 74%, due to higher average realized prices and an increase in West Africa sales volumes due to the timing of hydrocarbon tanker liftings.

Revenues for first quarter 2008 and 2007 included decreases of $97 million and $28 million, respectively, reclassified from AOCL and related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007.

Natural Gas Sales – Natural gas sales increased a net $37 million, or 11%, during first quarter 2008 as compared with first quarter 2007. The increase was driven by both volume and price changes. US sales increased $17 million, or 6%, from first quarter 2007 primarily due to an increase in prices. Our successful drilling program in the Piceance basin along with less severe winter weather in the Rocky Mountain area resulted in increased US production in 2008, which was offset somewhat by declining production in the Gulf Coast onshore and Mid-continent areas. These volume increases were also offset by a reduction for shrink gas associated with the natural gas liquids now being reported separately.

International sales increased $20 million, or 63%, due to record production levels and higher prices in Israel and increased sales from the Alba field in Equatorial Guinea to an LNG plant. These factors were partially offset by lower average realized prices in West Africa.

Revenues for first quarter 2008 and 2007 included increases of $37 million and $43 million, respectively, reclassified from AOCL and related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007.

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
	March 31,
	2008		2007
Net income (in millions):
AMPCO	$	28	$	25
Alba Plant	$	34	$	21
Distributions/dividends (in millions):
AMPCO	$	34	$	21
Alba Plant	$	42	$	32
Production volumes:
Methanol (Mgal)		34		40
Condensate (MBopd)		2		2
LPG (MBpd)		6		6
Sales volumes:
Methanol (Mgal)		34		40
Condensate (MBopd)		2		2
LPG (MBpd)		6		5
Average realized prices:
Methanol (per gallon)	$	1.63	$	1.22
Condensate (per Bbl)	$	98.55	$	59.35
LPG (per Bbl)	$	60.78	$	39.25

For first quarter 2008, net income from AMPCO increased $3 million, or 12%, relative to 2007 due to higher average realized methanol prices offset by a decrease in methanol sales volumes. The decrease in methanol sales volumes was due to a 20 day shutdown of methanol production for compressor maintenance.

For first quarter 2008, net income from Alba Plant increased $13 million, or 62%, relative to 2007 due to higher average realized condensate and LPG prices, offset by the expiration of the Alba Plant tax holiday at the end of 2007.

Costs and Expenses

Production Costs – Production costs were as follows:

			United		West		North				Other Int'l /
	Consolidated		States		Africa		Sea		Israel		Corporate(1)
	(in millions)
Three Months Ended March 31, 2008
Oil and gas operating costs (2)	$	76	$	49	$	9	$	11	$	2	$	5
Workover and repair expense		6		6		-		-		-		-
Lease operating expense		82		55		9		11		2		5
Production and ad valorem taxes		43		33		-		-		-		10
Transportation expense		13		11		-		2		-		-
Total production costs	$	138	$	99	$	9	$	13	$	2	$	15
Three Months Ended March 31, 2007
Oil and gas operating costs (2)	$	75	$	55	$	7	$	6	$	2	$	5
Workover and repair expense		4		4		-		-		-		-
Lease operating expense		79		59		7		6		2		5
Production and ad valorem taxes		25		20		-		-		-		5
Transportation expense		11		8		-		2		-		1
Total production costs	$	115	$	87	$	7	$	8	$	2	$	11

(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 $23 million, or 20%, first quarter 2008 as compared with first quarter 2007. The increase in production and ad valorem taxes was driven primarily by higher worldwide commodity prices and also by an increase in volumes subject to such taxes. US lease operating expense declined from 2007 primarily due to a decrease in insurance costs for our Gulf of Mexico deepwater operations related to a change in insurance coverage made during second quarter 2007. This reduction was offset by expenses relating to increased workover activity and higher costs related to the continuing active drilling program in the Northern region. North Sea oil and gas operating costs increased due to expanded operations.

Selected expenses on a per BOE basis were as follows:

	Three Months Ended
	March 31,
	2008		2007
Oil and gas operating costs	$	3.88	$	4.75
Workover and repair expense		0.33		0.25
Lease operating expense		4.21		5.00
Production and ad valorem taxes		2.23		1.60
Transportation expense		0.68		0.70
Total production costs (1) (2) (3)	$	7.12	$	7.30

(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. The inclusion of these volumes reduced the unit rate by $1.11 per BOE for first quarter 2008 and had no effect on first quarter 2007.

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

Oil and Gas Exploration Expense – Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic expense, staff expense and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense decreased $5 million during first quarter 2008 as compared with first quarter 2007 as a result of a $13 million decrease in dry hole expense, offset by a $3 million increase in seismic expense and a $6 million increase in other exploration expense.

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

	Three Months Ended
	March 31,
	2008		2007
	(in millions, except unit rate)
DD&A expense - property, plant and equipment	$	201	$	164
Accretion of discount on asset retirement obligations		2		2
Total DD&A expense	$	203	$	166
Unit rate per BOE (1) (2)	$	10.42	$	10.55

(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. The inclusion of these volumes reduced the unit rate by $1.32 per BOE for first quarter 2008 and had no effect on first quarter 2007.

Total DD&A expense for first quarter 2008 increased as compared to first quarter 2007 primarily due to the increase in production volumes. The decrease in the unit rate is due to a change in the mix of production.

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

	Three Months Ended
	March 31,
	2008		2007

G&A expense (in millions)	$	60	$	45
Unit rate per BOE (1) (2)	$	3.09	$	2.86

(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. The inclusion of these volumes reduced the unit rate by $0.48 per BOE for first quarter 2008 and had no effect for first quarter 2007.

G&A expense increased $15 million, or 33%, during first quarter 2008 as compared with first quarter 2007. One reason for the increase was higher salaries and wages resulting from an increase in the number of employees to address our increased activities. In addition, we have increased our accruals for incentive compensation to align with current expectations of achievement, and stock-based compensation increased $4 million from first quarter 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
	March 31,
	2008			2007
	(in millions)
Interest expense	$	27		$	31
Capitalized interest		(10	)		(4	)
Interest expense, net	$	17		$	27

Interest expense decreased during first quarter 2008, as compared with first quarter 2007 due to a declining rate of interest applicable to our credit facility from 5.67% at March 31, 2007 to 2.99% at March 31, 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 (Income) 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
	March 31,
	2008			2007
Income tax provision (in millions)	$	101		$	92
Effective rate		32	%		30	%

Our effective tax rate increased during first quarter 2008 as compared with first quarter 2007. This is due to the fact that our pretax income increased significantly, but our favorable permanent adjustments (which reduce income tax expense) did not increase at the same rate. One factor contributing to this effect was that in Equatorial Guinea, our tax holiday for the Alba plant 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 $807 million in cash and cash equivalents at March 31, 2008, compared with $660 million at December 31, 2007. Substantially all of this cash is located in 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.

Fair Value Measurements – As of March 31, 2008, we had a net liability of $698 million 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 prepare a discounted cash flow projection 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 (outflows). We then discount the cash inflows (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 values 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. Generally, 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. See additional information included in Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Cash Flows

Cash flow information is as follows:

	Three Months Ended
	March 31,
	2008			2007
	(in millions)
Total cash provided by (used in):
Operating activities	$	506		$	422
Investing activities		(355	)		(332	)
Financing activities		(4	)		6
Increase in cash and cash equivalents	$	147		$	96

Operating Activities – Net cash provided by operating activities was $506 million for first quarter 2008, as compared with $422 million for first quarter 2007. The increase was due primarily to higher commodity prices.

Investing Activities – Net cash used in investing activities was $355 million for first quarter 2008, as compared with $332 million for first quarter 2007. Investing activities in 2008 consisted of $464 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 $4 million for first quarter 2008, as compared with $6 million provided by financing activities for first quarter 2007. During 2008 and 2007, cash used to pay dividends was offset by cash received from the exercise of stock options. In addition, there were net proceeds from borrowings of $100 million in 2007, while there were no net proceeds from borrowings during 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
	March 31,
	2008		2007
	(in millions)
Capital Expenditures
Unproved property acquisition	$	176	$	3
Exploration expenditures		45		62
Development expenditures		246		210
Corporate and other expenditures		19		9
Total capital expenditures	$	486	$	284

The increase in unproved property acquisition cost relates primarily to deepwater lease blocks acquired in the recent Gulf of Mexico lease sale.

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.

Financing Activities

Long-Term Debt – Our long-term debt totaled $1.9 billion (net of unamortized discount) at March 31, 2008. Maturities range from 2011 to 2097. Our ratio of debt-to-book capital was 27% at March 31, 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 March 31, 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 March 31, 2008 was 2.99%.

Installment Payments Due – We owe $50 million in the form of installment payments to the seller of properties we purchased in 2007. Installments of $25 million each are due on May 12, 2008 and May 11, 2009. The amount due in 2008 is included in short-term borrowings and the amount due in 2009 is included in long-term debt in the consolidated balance sheets. Interest on the unpaid amounts is due quarterly and accrues at a LIBOR rate plus .30%. The interest rate was 5.13% at March 31, 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 payments discussed above, there were no short-term borrowings outstanding at March 31, 2008.

Dividends – We paid a quarterly cash dividend of 12.0 cents per share of common stock during first quarter 2008 and 7.5 cents per share of common stock during first quarter 2007. On April 21, 2008, our Board of Directors declared an increase in our quarterly cash dividend by 50% to 18.0 cents per common share, payable May 19, 2008 to shareholders of record on May 5, 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 $10 million from the exercise of stock options during first quarter 2008 as compared to $13 million during first quarter 2007.

Common Stock Repurchases – During first quarter 2008, we received from employees 24,000 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 first quarter 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 March 31, 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 $698 million. Based on the March 31, 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 March 31, 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 March 31, 2008, was variable-rate debt. We also had $25 million of current installment payments at March 31, 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 March 31, 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 March 31, 2008, AOCL included $31 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 are scheduled to settle during third quarter 2008. See Note 4 – Derivative Instruments and Hedging Activities.

We are also exposed to interest rate risk related to our short-term investments. As of March 31, 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 March 31, 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 (income) 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, 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 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 12 – Commitments and Contingencies.

ITEM 1A. RISK FACTORS

None.

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

					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares that
	Total Number (1)		Average Price		as Part of Publicly		May Yet Be
	of Shares		Paid		Announced Plans		Purchased Under the
Period	Purchased		Per Share		or Programs		Plans or Programs
					(in thousands)
01/01/08 - 01/31/08		4,665	$	80.33		-		-
02/01/08 - 02/29/08		19,715		73.02		-		-
03/01/08 - 03/31/08		-		-		-		-
Total		24,380	$	74.42		-		-

(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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

SIGNATURES

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

		NOBLE ENERGY, INC. (Registrant)
Date	May 1, 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).