Noble Energy, Inc.

Notes to Consolidated Financial Statements

Balance Sheet Information Other balance sheet information is as follows:


	March 31,			December 31,
	2012			2011			June 30, 2012			December 31, 2011
(millions)
Accounts Receivable, Net
Commodity Sales	$	467		$	356		$	319		$	356
Joint Interest Billings		344			313		394			313
Other		117			123		120			123
Allowance for Doubtful Accounts		(9	)		(9	)	(9		)	(9		)
Total	$	919		$	783		$	824		$	783
Other Current Assets
Inventories, Current	$	77		$	78		$	67		$	78
Commodity Derivative Assets, Current		17			10
Deferred Income Taxes, Net, Current (1)		159			41
Commodity Derivative Assets							85			10
Deferred Income Taxes, Net ⁽¹⁾							100			41
Probable Insurance Claims (2)		22			15		31			15
Prepaid Expenses and Other Current Assets, Current		55			36
Prepaid Expenses and Other Current Assets							85			36
Total	$	330		$	180		$	368		$	180
Other Noncurrent Assets
Equity Method Investments	$	376		$	329		$	373		$	329
Mutual Fund Investments		108			99		104			99
Commodity Derivative Assets, Noncurrent		22			37
Commodity Derivative Assets							85			37
Other Assets, Noncurrent		86			83		80			83
Total	$	592		$	548		$	642		$	548
Other Current Liabilities
Production and Ad Valorem Taxes	$	123		$	121		$	119		$	121
Commodity Derivative Liabilities, Current		119			76
Commodity Derivative Liabilities							2			76
Income Taxes Payable		131			127		107			127
Asset Retirement Obligations, Current		41			33
Asset Retirement Obligations							45			33
Interest Payable		41			56		55			56
CONSOL Installment Payment (3)		325			324		327			324
Current Portion of FPSO Lease Obligation		48			45		53			45
Liabilities Associated with Assets Held for Sale							234			—
Other		123			143		118			143
Total	$	951		$	925		$	1,060		$	925
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	237		$	222
Asset Retirement Obligations, Noncurrent		350			344
Accrued Benefit Costs, Noncurrent		90			88
Commodity Derivative Liabilities, Noncurrent		29			7
Deferred Compensation Liabilities							$	224		$	222
Asset Retirement Obligations							298			344
Accrued Benefit Costs							89			88
Commodity Derivative Liabilities							—			7
Other		113			91		72			91
Total	$	819		$	752		$	683		$	752


⁽¹⁾	Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2012 and 2013.


⁽²⁾	Amounts represent the costs incurred to date of the Leviathan-2 appraisal well and expected well abandonment costs in excess of the insurance deductible ~~and~~less insurance proceeds received to date. See Note 9. Asset Retirement Obligations.


⁽³⁾	See Note 3. Acquisitions and Dispositions and Note 4.5. Debt.

Changes in Shareholders’ Equity On April 24, 2012, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500 million shares and (ii) reduce the par value of the Company’s common stock from ~~$3.33~~ 1/$3.33 1/33 per share to ~~$0.01~~$0.01 per share. See

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

the Consolidated Statements of Shareholders' Equity.

Recently Issued Accounting Standards Updates In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-04: Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011. As of March 31, 2012, we have adopted the provisions of ASU 2011-04, which did not impact our consolidated financial statements. The only impact was to our fair value disclosures. See Note 7. Fair Value Measurements and Disclosures.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities~~(ASU~~ (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position and results of operations.

Note 3. Acquisitions and Divestitures

Pending Sale of North Sea Properties On May 30, 2012, we announced that we have entered into an agreement for the sale of our 30% non-operated working interests in the Dumbarton and Lochranza fields, located in the UK sector of the North Sea. We expect to receive $127 million, subject to customary adjustments for net cash flows between the effective date of January 1, 2012 and the closing date, which is expected to occur by the end of the third quarter of 2012. We expect to reverse a deferred tax liability and recognize a corresponding income tax benefit of approximately $103 million when the sale closes in the third quarter of 2012.

We continue to market our remaining North Sea properties. As of June 30, 2012, all the properties in our North Sea geographical segment met the criteria for classification as held for sale in our consolidated balance sheets. Our consolidated statements of operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as discontinued. Upon reclassification as held for sale, depreciation, depletion, and amortization (DD&A) ceased. Our long-term debt is recorded at the consolidated level; therefore no interest expense has been allocated to discontinued operations.

North Sea assets and liabilities classified as held for sale were as follows:



	June 30, 2012
(millions)
Current Assets
Accounts Receivable, Net	$	19
Other Current Assets	11
Total Current Assets	30
Property, Plant and Equipment, Net	294
Total Assets Held for Sale	$	324
Accounts Payable - Trade	$	9
Asset Retirement Obligation	89
Deferred Tax Liability	136
Total Liabilities Related to Assets Held for Sale	$	234

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Summarized results of discontinued operations are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
(millions)
Oil and Gas Sales	$	65	$	112	$	140	$	225
Income Before Income Taxes	39		69		79		137
Income Tax Expense	22		44		47		64
Discontinued Operations, Net of Tax	$	17	$	25	$	32	$	73

Pending Sale of Onshore US Properties In July 2012, the Board of Directors approved the sale of certain crude oil and natural gas properties in western Oklahoma, western Texas, and the Texas Panhandle for $937 million. We subsequently signed sale agreements related to those properties with two purchasers. The combined net book values of these properties as of June 30, 2012, was approximately $765 million, excluding an allocation of US reporting unit goodwill. The transactions have effective dates of April 1, 2012 and are expected to close in the third quarter of 2012, subject to customary closing conditions and adjustments.

Marcellus Shale Joint Venture On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) for the development of Marcellus Shale properties in southwest Pennsylvania and northwest West Virginia. Under the agreement, we acquired a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure, such as pipeline and gathering facilities, for approximately ~~$1.3~~$1.3 billion, including post-closing adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future infrastructure. We have paid a total of ~~$596~~$610 million as of ~~March 31,~~June 30, 2012, and, other than post-closing adjustments, the remainder will be paid in two annual installments. See Note 4.5. Debt.

As part of the joint venture transaction, we agreed to fund one-third of CONSOL’s 50% working interest share of future drilling and completion costs, capped at ~~$400~~$400 million each year, up to approximately ~~$2.1~~$2.1 billion (CONSOL Carried Cost Obligation), which is expected to be paid out over approximately eight years ~~or more.~~. The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below ~~$4.00~~$4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above ~~$4.00~~$4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices.

As a result of the transaction, we recorded the following:



	June 30, 2012
(millions)
Unproved Oil and Gas Properties	$	853
Proved Oil and Gas Properties	386
Investment in CONE Gathering LLC	69
Total Assets Acquired ⁽¹⁾	$	1,308

March 31,
2012
(millions)
Unproved Oil and Gas Properties $ 853
Proved Oil and Gas Properties 386
Investment in CONE Gathering LLC 69
Total Assets Acquired (1)
$ 1,308

⁽¹⁾ ~~Total reflects impact of $17 million imputed discount on CONSOL installment payments.~~

Total reflects impact of $17 million imputed interest on CONSOL installment payments.

We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:

●

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

management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;

●

~~management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices~~estimated future production rates based on our experience with similar properties which we operate; and ~~adjusted for estimated location and quality differentials;~~

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

Table of Contents

●

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

Noble Energy, Inc.

Notes to Consolidated Financial Statements

●

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

We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value measurement.

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

Note 4. Asset Impairments

Pre-tax (non-cash) asset impairment charges were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
(millions)
South Raton (Deepwater Gulf of Mexico)	$	34	$	—	$	34	$	—
Piceance (Onshore US)	39		—		39		—
East Texas (Onshore US)	—		116		—		116
Other (Onshore US)	—		15		—		21
Total	$	73	$	131	$	73	$	137

2012 Due to recent declines in near-term crude oil prices, we determined that the carrying amount of our South Raton development in the deepwater Gulf of Mexico was not recoverable from future cash flows and, therefore, was impaired. In addition, due to recent declines in realized natural gas prices, we determined that the carrying amount of our Piceance development, onshore US, was not recoverable from future cash flows and, therefore, was impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models.

2011 Due to field performance combined with a low natural gas price environment, we determined that the carrying amounts of certain of our onshore US developments, primarily in East Texas, were not recoverable from future cash flows and, therefore, were impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models.

See Note 7. Fair Value Measurements and Disclosures.

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 4.5. Debt

Our debt consists of the following:


	March 31,						December 31,
	2012						2011						June 30, 2012						December 31, 2011
	Debt			Interest Rate			Debt			Interest Rate			Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due October 14, 2016 (1)	$	-			-		$	-			-		$	—		—			$	—		—
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	% (2)		656			1.76	% (2)	656			1.76	%	⁽²⁾	656			1.76	%	⁽²⁾
FPSO Lease Obligation		344			-			355			-		333			—			355			—
5¼% Senior Notes, due April 15, 2014		200			5.25	%		200			5.25	%	200			5.25	%		200			5.25	%
8¼% Senior Notes, due March 1, 2019		1,000			8.25	%		1,000			8.25	%	1,000			8.25	%		1,000			8.25	%
4.15% Senior Notes, due December 15, 2021		1,000			4.15	%		1,000			4.15	%	1,000			4.15	%		1,000			4.15	%
7¼% Senior Notes, due October 15, 2023		100			7.25	%		100			7.25	%	100			7.25	%		100			7.25	%
8% Senior Notes, due April 1, 2027		250			8.00	%		250			8.00	%	250			8.00	%		250			8.00	%
6% Senior Notes, due March 1, 2041		850			6.00	%		850			6.00	%	850			6.00	%		850			6.00	%
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%	84			7.25	%		84			7.25	%
Total		4,484						4,495					4,473						4,495
Unamortized Discount		(23	)					(26	)				(19		)				(26		)
Total Debt, Net of Discount		4,461						4,469					4,454						4,469
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(325	)					(324	)				(327		)				(324		)
FPSO Lease Obligation		(48	)					(45	)				(53		)				(45		)
Long-Term Debt Due After One Year	$	4,088					$	4,100					$	4,074					$	4,100


⁽¹⁾	~~(1)~~ Our Credit Agreement provides for a ~~$3.0~~$3.0 billion unsecured ~~five-year~~five-year revolving credit facility. The Credit Facility is available for general corporate purposes.


⁽²⁾	Imputed ~~rate.~~rate based on the prevailing market rates for similar debt instruments at the date of assessment.

See Note 6.7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our debt.

Note 5.6. Derivative Instruments and Hedging Activities

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

The fixed price swap, two-way collar, and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.

A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.

We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.

~~Table of Contents~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

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

See Note 6.7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.

Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of ~~highly rated~~ major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.

We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.

Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices or higher interest rates, and could incur a loss.

Interest Rate Derivative Instrument In January 2010, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on our anticipated March 2011 debt issuance. During first quarter 2011, the ~~fair value of~~net liability position on the swap ~~increased~~was reduced in our mark to market calculation, and we recognized a corresponding gain of ~~$23~~$23 million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of ~~$40~~$40 million at the time of settlement. Approximately ~~$26~~$26 million, net of tax, was recorded in accumulated other comprehensive loss (AOCL) and is being reclassified to interest expense over the term of the notes. The ineffective portion of the interest rate swap was de minimis.

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Unsettled Derivative Instruments As of ~~March 31,~~June 30, 2012, we had entered into the following crude oil derivative instruments:



				Swaps		Collars
Settlement Period	Type of Contract	Index	Bbls Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of June 30, 2012
2012	Swaps	NYMEX WTI ⁽¹⁾	5,000	$	91.84	$	—	$	—	$	—
2012	Swaps	Dated Brent	8,000	89.06		—		—		—
2012	Three-Way Collars	NYMEX WTI	23,000	—		61.09		83.04		101.66
2012	Three-Way Collars	Dated Brent	3,000	—		70.00		95.83		105.00
2013	Swaps	NYMEX WTI	3,000	87.00		—		—		—
2013	Swaps	Dated Brent	3,000	98.03		—		—		—
2013	Two-Way Collars	NYMEX WTI	5,000	—		—		95.00		115.00
2013	Three-Way Collars	NYMEX WTI	7,000	—		63.57		83.57		109.04
2013	Three-Way Collars	Dated Brent	26,000	—		82.88		100.86		127.32
2014	Swaps	NYMEX WTI	5,000	86.50		—		—		—
2014	Swaps	Dated Brent	8,000	105.94		—		—		—
2014	Three-Way Collars	Dated Brent	10,000	—		85.00		98.50		129.24

Swaps Collars
Settlement
Period
Type of Contract Index
Bbls Per
Day

Weighted
Average
Fixed
Price

Weighted
Average
Short Put
Price

Weighted
Average
Floor
Price

Weighted
Average
Ceiling
Price

Instruments Entered Into as of March 31, 2012
2012 Swaps
NYMEX WTI (1)
5,000 $ 91.84 $ - $ - $ -
2012 Swaps Dated Brent 8,000 89.06 - - -
2012 Three-Way Collars NYMEX WTI 23,000 - 61.09 83.04 101.66
2012 Three-Way Collars Dated Brent 3,000 - 70.00 95.83 105.00
2013 Swaps Dated Brent 3,000 98.03 - - -
2013 Two-Way Collars NYMEX WTI 5,000 - - 95.00 115.00
2013 Three-Way Collars NYMEX WTI 5,000 - 65.00 85.00 113.63
2013 Three-Way Collars Dated Brent 26,000 - 82.88 100.86 127.32
2014 Swaps Dated Brent 3,000 107.15 - - -
2014 Three-Way Collars Dated Brent 10,000 - 85.00 98.50 129.24


⁽¹⁾	West Texas Intermediate

As of ~~March 31,~~June 30, 2012, we had entered into the following natural gas derivative instruments:



				Swaps		Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of June 30, 2012
2012	Swaps	NYMEX HH ⁽¹⁾	30,000	$	5.10	$	—	$	—	$	—
2012	Two-Way Collars	NYMEX HH	40,000	—		—		3.25		5.14
2012	Three-Way Collars	NYMEX HH	110,000	—		4.44		5.25		6.66
2013	Swaps	NYMEX HH	30,000	5.25		—		—		—
2013	Two-Way Collars	NYMEX HH	40,000	—		—		3.25		5.14
2013	Three-Way Collars	NYMEX HH	100,000	—		3.88		4.75		5.63

Swaps Collars
Settlement
Period
Type of Contract Index
MMBtu
Per Day

Weighted
Average
Fixed
Price

Weighted
Average
Short Put
Price

Weighted
Average
Floor
Price

Weighted
Average
Ceiling
Price

Instruments Entered Into as of March 31, 2012
2012 Swaps
NYMEX HH (1)
30,000 $ 5.10 $ - $ - $ -
2012 Two-Way Collars NYMEX HH 40,000 - - 3.25 5.14
2012 Three-Way Collars NYMEX HH 110,000 - 4.44 5.25 6.66
2013 Swaps NYMEX HH 30,000 5.25 - - -
2013 Two-Way Collars NYMEX HH 40,000 - - 3.25 5.14
2013 Three-Way Collars NYMEX HH 100,000 - 3.88 4.75 5.63


⁽¹⁾	Henry Hub

As of June 30, 2012, we had entered into the following natural gas basis swaps:



Settlement Period	Index	Index Less Differential	MMBtu Per Day	Weighted Average Differential
2012	IFERC CIG ⁽¹⁾	NYMEX HH	150,000	$	(0.52	)


⁽¹⁾	Colorado Interstate Gas – Northern System

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

~~As of March 31, 2012, we had entered into the following natural gas basis swaps:~~

Settlement
Period
Index Index Less Differential MMBtu Per Day
Weighted Average
Differential

2012
IFERC CIG (1)
NYMEX HH 150,000 $ (0.52 )

~~(1)~~

~~Colorado Interstate Gas – Northern System~~

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


Fair Value of Derivative Instruments	Fair Value of Derivative Instruments													Fair Value of Derivative Instruments
		Asset Derivative Instruments						Liability Derivative Instruments
		March 31,			December 31,			March 31,			December 31,			Asset Derivative Instruments						Liability Derivative Instruments
		2012			2011			2012			2011			June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
(millions)
Commodity Derivative Instruments		Current Assets	$	17	Current Assets	$	10	Current Liabilities	$	119	Current Liabilities	$	76	Current Assets	$	85	Current Assets	$	10	Current Liabilities	$	2	Current Liabilities	$	76
		Noncurrent Assets		22	Noncurrent Assets		37	Noncurrent Liabilities		29	Noncurrent Liabilities		7	Noncurrent Assets	85		Noncurrent Assets	37		Noncurrent Liabilities	—		Noncurrent Liabilities	7
Total			$	39		$	47		$	148		$	83		$	170		$	47		$	2		$	83

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
(millions)
Realized Mark-to-Market (Gain) Loss	$	1		$	(1	)	$	24		$	(17	)
Unrealized Mark-to-Market (Gain) Loss	(277		)	(142		)	(204		)	160
Total (Gain) Loss on Commodity Derivative Instruments	$	(276	)	$	(143	)	$	(180	)	$	143

Three Months Ended
March 31,

2012 2011
(millions)
Realized Mark-to-Market (Gain) Loss $ 23 $ (17 )
Unrealized Mark-to-Market Loss 73 303
Total Loss on Commodity Derivative Instruments $ 96 $ 286

AOCL at ~~March 31,~~June 30, 2012 included deferred losses of ~~$26~~$26 million, net of tax, related to interest rate derivative instruments. This amount will be reclassified to earnings as an adjustment to interest expense over the terms of our senior notes due April 2014 and March ~~2041.~~2041. Approximately $2$2 million of deferred losses (net of tax) will be reclassified to earnings during the next 12 months and will be recorded as an increase in interest expense.

Note 6.7. Fair Value Measurements and Disclosures

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

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

Commodity Derivative Instruments Our commodity derivative instruments consist of variable to fixed price commodity swaps, two-way and three-way collars, and basis swaps. We estimate the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

account market volatility, market prices and contract terms. See Note 5.6. Derivative Instruments and Hedging Activities.

~~Table of Contents~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.SeeMutual Fund Investmentsabove.

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



	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1) ⁽¹⁾			Significant Other Observable Inputs (Level 2) ⁽²⁾			Significant Unobservable Inputs (Level 3) ⁽³⁾		Adjustment ⁽⁴⁾			Fair Value Measurement
(millions)
June 30, 2012
Financial Assets
Mutual Fund Investments	$	104		$	—		$	—	$	—		$	104
Commodity Derivative Instruments	—			193			—		(23		)	170
Financial Liabilities
Commodity Derivative Instruments	—			(25		)	—		23			(2		)
Portion of Deferred Compensation Liability Measured at Fair Value	(158		)	—			—		—			(158		)
December 31, 2011
Financial Assets
Mutual Fund Investments	$	99		$	—		$	—	$	—		$	99
Commodity Derivative Instruments	—			99			—		(52		)	47
Financial Liabilities
Commodity Derivative Instruments	—			(135		)	—		52			(83		)
Portion of Deferred Compensation Liability Measured at Fair Value	(162		)	—			—		—			(162		)

Fair Value Measurements Using

Quoted Prices in
Active Markets
(Level 1) (1)

Significant Other
Observable Inputs
(Level 2) (2)

Significant
Unobservable
Inputs (Level 3) (3)

Adjustment (4)
Fair Value Measurement
(millions)
March 31, 2012
Financial Assets
Mutual Fund Investments $ 108 $ - $ - $ - $ 108
Commodity Derivative Instruments - 105 - (66 ) 39
Financial Liabilities
Commodity Derivative Instruments - (214 ) - 66 (148 )
Portion of Deferred Compensation
Liability Measured at Fair Value (172 ) - - - (172 )
December 31, 2011
Financial Assets
Mutual Fund Investments $ 99 $ - $ - $ - $ 99
Commodity Derivative Instruments - 99 - (52 ) 47
Financial Liabilities
Commodity Derivative Instruments - (135 ) - 52 (83 )
Portion of Deferred Compensation Liability
Measured at Fair Value (162 ) - - - (162 )


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


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


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


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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Asset Impairments We determined that the carrying amounts of certain assets were not recoverable from future cash flows and, therefore, were impaired. The assets were reduced to their estimated fair values. Information about the impaired assets is as follows:

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements



	Fair Value Measurements Using
Description	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Book Value ⁽¹⁾		Total Pre-tax (Non-cash) Impairment Loss
millions
Three Months Ended June 30, 2012
Impaired Oil and Gas Properties	$	—	$	—	$	172	$	245	$	73
Three Months Ended June 30, 2011
Impaired Oil and Gas Properties	—		—		29		160		131
Six Months Ended June 30, 2012
Impaired Oil and Gas Properties	—		—		172		245		73
Six Months Ended June 30, 2011
Impaired Oil and Gas Properties	—		—		32		169		137

⁽¹⁾ Amount represents net book value at the date of assessment.

The fair values of the properties were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future oil and gas production, commodity prices based on NYMEX commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10%. See Note 4. Asset Impairments.

Additional Fair Value Disclosures

Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a ~~level~~Level 1 measurement on the fair value hierarchy. ~~The carrying amounts of floating-rate debt approximate fair value because the interest rate paid on such debt was set for periods of three months or less.~~ The carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the prevailing market rates for similar ~~instruments.~~debt instruments at the date of assessment, September 30, 2011. As such, we consider the fair value of our ~~floating-rate debt and~~ CONSOL installment payments to be ~~level~~Level 2 measurements on the fair value hierarchy. See Note 4.5. Debt. Fair value information regarding our debt is as follows:



	June 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount ⁽¹⁾	$	4,121	$	4,712	$	4,114	$	4,733

March 31, December 31,
2012 2011
Carrying Amount Fair Value Carrying Amount Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)
$ 4,117 $ 4,606 $ 4,114 $ 4,733

~~(1)~~
⁽¹⁾	Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at ~~March 31,~~June 30, 2012 or December 31, ~~2011.~~2011. See Note 4.5. Debt.

Note 7.8. Capitalized Exploratory Well Costs

We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration ~~expense.~~expense as dry hole cost.

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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


		Three Months Ended March 31, 2012	Six Months Ended June 30, 2012
(millions)
Capitalized Exploratory Well Costs, Beginning of Period	$	696	$	696
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		93	160
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves		-	(9		)
Capitalized Exploratory Well Costs Charged to Expense		-
Capitalized Exploratory Well Costs Charged to Expense ⁽¹⁾			(107		)
Other ⁽²⁾			(19		)
Capitalized Exploratory Well Costs, End of Period	$	789	$	721

⁽¹⁾ Amount primarily represents the Deep Blue exploratory well (deepwater Gulf of Mexico) costs capitalized prior to December 31, 2011. Although hydrocarbons were found in both the initial exploration well and subsequent sidetrack, we and our partners have decided not to proceed with additional appraisal activities at this time.

⁽²⁾ Amount represents the Selkirk exploratory well (North Sea) which, along with our remaining North Sea assets, was reclassified to held for sale at June 30, 2012. See Note 3. Acquisitions and Divestitures.

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year:



	June 30, 2012		December 31, 2011
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	330	$	318
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	391		378
Balance at End of Period	$	721	$	696
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	8		9

March 31, December 31,
2012 2011
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less $ 345 $ 318
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 444 378
Balance at End of Period $ 789 $ 696
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 10 9

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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 commencement of drilling as of ~~March 31, 2012:~~June 30, 2012:



			Suspended Since
	Total		2011		2010		2009 & Prior
(millions)
Country/Project:
Offshore Equatorial Guinea
Blocks O and I	$	155	$	43	$	6	$	106
Offshore Cameroon
YoYo	44		4		2		38
Offshore Israel
Leviathan	62		21		41		—
Leviathan-1 Deep	27		27		—		—
Dalit	22		—		1		21
Deepwater Gulf of Mexico
Gunflint	68		9		3		56
Other
2 projects of $10 million or less each	13		7		6		—
Total	$	391	$	111	$	59	$	221

Suspended Since
Total 2011 2010
2009 &
Prior

(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I $ 114 $ 2 $ 6 $ 106
Offshore Cameroon
YoYo 41 1 2 38
Offshore Israel
Leviathan 86 45 41 -
Dalit 22 - 1 21
Deepwater Gulf of Mexico
Gunflint 70 11 3 56
Deep Blue 75 2 54 19
North Sea
Selkirk 22 - 1 21
Other
3 projects of $10 million or less each 14 6 8 -
Total $ 444 $ 67 $ 116 $ 261

Blocks O and I Blocks O and I are crude oil, natural gas and natural gas condensate discoveries. During ~~the second quarter of~~ 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently ~~finalizing our appraisal of Diega and are~~ evaluating regional development ~~scenarios.~~scenarios that will include Diega, along with the successful Carla appraisal well, which was drilled in the fourth quarter of 2011.

YoYo YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic information and are continuing evaluations for future drilling potential.

Leviathan Leviathan is a 2010 natural gas discovery. We are continuing to evaluate the discovery with the successful drilling of the Leviathan-3 appraisal ~~well. We~~well and will require an additional one or two appraisal wells to further define Leviathan’s natural gas areal ~~extent~~extent. We have project and commercial teams in ~~order~~place and are considering our natural gas commercialization options. Due to ~~determine~~ the ~~best development option including subsea tieback~~scale of the discovery, economic viability depends on the ability to ~~existing shallow water platform, semi-submersible platform, FPSO,~~export via pipeline or LNG. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. Engineering design and planning work are currently underway for a potential first phase of development. In addition, we are working with our existing partners to identify a potential partner who can provide technical and financial support as well as midstream and downstream expertise.

Leviathan-1 Deep In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two ~~additional~~deeper intervals for the existence of crude ~~oil. Results~~oil (Leviathan-1 Deep). In May 2012, due to high well pressure and the mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach the planned objective, we are encouraged by the possibility of an active thermogenic (heat producing) petroleum system at greater depths within the basin. We are continuing our evaluation of Leviathan-1 Deep and will integrate the data from ~~these deeper tests are expected during~~ the ~~second quarter~~Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically to test the deep oil concept. Part of ~~2012.~~the plan will be to secure a rig with the capabilities necessary to reach the target objective.

~~Table of Contents~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

Dalit Dalit is a 2009 natural gas discovery. We are currently working with our partners on a cost-effective development plan.

Gunflint Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. ~~We are currently drilling the first of up to three~~In July 2012, we reached target depth on our Gunflint appraisal wells that we anticipate drilling to fully evaluate the extent of the reservoir. We are also reviewing host platform options including subsea tieback to an existing third-party host and construction of a new facility.

~~Deep Blue~~ Deep Blue (Green Canyon Block 723) was a significant test well which began drilling in 2009. When the Deepwater Moratorium was announced in May 2010, we were required to suspend side track drilling activities. We resumed drilling activities and found additional hydrocarbons in high quality reservoirs in 2011. We have completed the analysis of the data obtained from the side track well and are currently evaluating the drilling results. Additional appraisal locations are currently being evaluated. Front-end conceptual studies have been completed, and we are working ~~with our existing and potential new partners regarding their participation in an appraisal well.~~toward sanctioning of a scalable development project.

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

Note 8.9. Asset Retirement Obligations

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Asset retirement obligations (ARO) 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,						Six Months Ended June 30,
	2012			2011			2012			2011
(millions)
Asset Retirement Obligations, Beginning Balance	$	377		$	253		$	377		$	253
Liabilities Incurred		6			1		23			1
Liabilities Settled		(2	)		(9	)	(2		)	(12		)
Revision of Estimate		3			4		20			6
Accretion Expense		7			5		14			10
Other							(89		)	—
Asset Retirement Obligations, Ending Balance	$	391		$	254		$	343		$	258

Liabilities incurred in 2012 relate primarily to wells drilled offshore Israel and include costs to abandon the Leviathan-2 appraisal well. See Note 2. Basis of Presentation. Revisions relate primarily to changes in estimated costs for future abandonment activities in China. Other includes ARO liabilities associated with North Sea properties held for sale. North Sea ARO liabilities have been included within liabilities associated with assets held for sale. See Note 3. Acquisitions and Divestitures.

Liabilities settled in 2011 related primarily to ~~Deepwater~~deepwater Gulf of Mexico and Gulf of Mexico shelf properties.

Accretion expense is included in ~~depreciation, depletion and amortization (DD&A)~~ DD&Aexpense in the consolidated statements ofoperations.

Note 9.10. Basic and Diluted Earnings Per Share

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


	Three Months Ended March 31,				Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		2012			2011			2012			2011
(millions, except per share amounts)
Net Income	$	263	$	14
Income from Continuing Operations					$	275		$	269		$	524		$	235
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust ⁽¹⁾					(7		)	(4		)	(5		)	—
Income from Continuing Operations Used for Diluted Earnings Per Share Calculation					$	268		$	265		$	519		$	235

Weighted Average Number of Shares Outstanding, Basic		177		176	178			176			178			176
Incremental Shares From Assumed Conversion of Dilutive Stock Options and Restricted Stock		3		2
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock and Shares of Common Stock in Rabbi Trust					2			3			2			2
Weighted Average Number of Shares Outstanding, Diluted		180		178	180			179			180			178
Earnings Per Share, Basic	$	1.48	$	0.08
Earnings Per Share, Diluted		1.47		0.08

Earnings from Continuing Operations Per Share, Basic					$	1.55		$	1.51		$	2.95		$	1.33
Earnings from Continuing Operations Per Share, Diluted					1.49			1.47			2.88			1.31
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above		2		2	3			2			3			3


⁽¹⁾	Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the three months ended June 30, 2012 and 2011 and for the six months ended June 30, 2012 exclude deferred compensation gains,

Table of Contents

net of tax.

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

Note ~~10.~~11. Income Taxes

The income tax provision relating to continuing operations consists of the following:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011
(millions)
Current	$	79		$	12		$	56		$	39		$	100		$	36
Deferred		32			11		59			48			100			54
Total Income Tax Provision	$	111		$	23		$	115		$	87		$	200		$	90
Effective Tax Rate		30	%		62	%	29		%	24		%	28		%	28		%

Our effective tax rate ~~decreased~~ for the first ~~quarter~~six months of 2012 was the same as ~~compared with~~ the first ~~quarter~~six months of 2011. During the ~~first~~second quarter of 2012, we recognized income tax expense of $13 million with respect to a reserve for uncertain tax positions related to prior years.

During the six months of 2011, we increased the valuation allowance against our deferred tax asset for foreign tax credits by ~~$11~~$14 million resulting in a corresponding increase in income tax ~~expense, which was primarily responsible for the difference in the quarterly effective tax rates.~~expense.

~~Years Remaining Open to Examination~~ In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2008, Equatorial Guinea – 2007, Israel – 2008, UK – 2010, the Netherlands – 2009, and China – ~~2006.~~2006.

See Note 3. Acquisitions and Divestitures for income taxes related to discontinued operations.

Note ~~11.~~12. Segment Information

We have operations throughout the world and manage our operations by country. The following information is grouped into ~~five~~four components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Senegal/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); ~~the North Sea (UK and the Netherlands);~~ and Other International and Corporate. Other International includes China, Ecuador ~~(in first quarter~~(through May 2011), and new ventures. As of June 30, 2012, our North Sea geographical segment was reclassified to held for sale. See Note 3. Acquisitions and Divestitures.

Consolidated
United
States

West
Africa

Eastern
Mediter-
ranean

North
Sea

Other Int'l
and
Corporate

(millions)
Three Months Ended March 31, 2012
Revenues from Third Parties $ 1,112 $ 554 $ 383 $ 44 $ 75 $ 56
Income from Equity Method Investees 53 2 51 - - -
Total Revenues 1,165 556 434 44 75 56
DD&A 312 198 73 5 18 18
(Gain) Loss on Commodity Derivative Instruments 96 (9 ) 105 - - -
Income (Loss) Before Income Taxes 374 193 227 32 40 (118 )
Three Months Ended March 31, 2011
Revenues from Third Parties $ 851 $ 505 $ 130 $ 52 $ 114 $ 50
Income from Equity Method Investees 48 - 48 - - -
Total Revenues 899 505 178 52 114 50
DD&A 221 167 10 4 28 12
Loss on Commodity Derivative Instruments 286 192 94 - - -
Income (Loss) Before Income Taxes 37 (37 ) 74 39 68 (107 )

March 31, 2012
Goodwill $ 696 $ 696 $ - $ - $ - $ -
Total Assets 17,064 11,220 2,948 2,107 458 331
December 31, 2011
Goodwill 696 696 - - - -
Total Assets 16,444 11,201 2,728 1,751 544 220

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements



	Consolidated			United States			West Africa			Eastern Mediterranean		Other Int'l & Corporate
(millions)
Three Months Ended June 30, 2012
Revenues from Third Parties	$	934		$	527		$	332		$	29	$	46
Income from Equity Method Investees	32			1			31			—		—
Total Revenues	966			528			363			29		46
DD&A	325			232			62			10		21
Asset Impairments ⁽¹⁾	73			73			—			—		—
Gain on Divestiture	(9		)	(9		)	—			—		—
Gain on Commodity Derivative Instruments⁽²⁾	(276		)	(93		)	(183		)	—		—
Income (Loss) from Continuing Operations Before Income Taxes	390			48			455			5		(118		)
Three Months Ended June 30, 2011
Revenues from Third Parties	$	794		$	553		$	118		$	76	$	47
Income from Equity Method Investees	48			—			48			—		—
Total Revenues	842			553			166			76		47
DD&A	211			187			7			7		10
Asset Impairments ⁽¹⁾	131			131			—			—		—
Gain on Divestiture ⁽³⁾	(25		)	—			—			—		(25		)
Gain on Commodity Derivative Instruments ⁽²⁾	(143		)	(142		)	(1		)	—		—
Income (Loss) from Continuing Operations Before Income Taxes	356			250			116			57		(67		)
Six Months Ended June 30, 2012
Revenues from Third Parties	$	1,970		$	1,080		$	715		$	73	$	102
Income from Equity Method Investees	86			3			83			—		—
Total Revenues	2,056			1,083			798			73		102
DD&A	619			430			135			15		39
Asset Impairments ⁽¹⁾	73			73			—			—		—
Gain on Divestiture	(9		)	(9		)	—			—		—
(Gain) on Commodity Derivative Instruments ⁽²⁾	(180		)	(102		)	(78		)	—		—
Income (Loss) from Continuing Operations Before Income Taxes	724			241			682			37		(236		)
Six Months Ended June 30, 2011
Revenues from Third Parties	$	1,533		$	1,059		$	248		$	128	$	98
Income from Equity Method Investees	96			—			96			—		—
Total Revenues	1,629			1,059			344			128		98
DD&A	404			354			17			11		22
Asset Impairments ⁽¹⁾	137			137			—			—		—
Gain on Divestiture ⁽³⁾	(26		)	(1		)	—			—		(25		)
Loss on Commodity Derivative Instruments ⁽²⁾	143			50			93			—		—
Income (Loss) from Continuing Operations Before Income Taxes	325			213			190			96		(174		)
June 30, 2012
Goodwill	$	696		$	696		$	—		$	—	$	—
Total Assets	16,657			11,188			2,761			2,289		419
December 31, 2011
Goodwill	696			696			—			—		—
Total Assets	16,106			11,201			2,728			1,751		426

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

⁽¹⁾ See Note 4. Asset Impairments.

⁽²⁾ See Note 6. Derivative Instruments and Hedging Activities.

⁽³⁾ Amount relates primarily to the transfer of our Ecuador assets to the Ecuadorian government. See Note 2. Basis of Presentation.

Note ~~12.~~13. Commitments and Contingencies

Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

~~Table of Contents~~COGCC

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

During 2011, we received two Notices of Alleged Violation (NOAV) from the Colorado Oil and Gas Conservation Commission (COGCC) regarding the reporting of the presence of hydrogen sulfide to the COGCC and local government designee within certain areas of our Piceance Basin and Grover field operations. ~~At this time,~~We are in ongoing discussions with the COGCC ~~has not established a proposed penalty for either NOAV. Given the inherent uncertainty~~ in ~~administrative actions of~~an effort to favorably resolve this ~~nature,~~matter but we are unable to predict the ultimate outcome ~~of this action~~ at this time. However, we believe that the final resolution ~~of these proceedings through settlement or adverse judgment~~ will not have a material adverse effect on our financial position, results of operations or cash flows.

Table of Contents

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following major sections:

●

Executive Overview;

●

Operating Outlook;

●

Results of Operations; and

●

Liquidity and Capital Resources.

The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.

EXECUTIVE OVERVIEW

We are a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our ~~strategy~~aim is to achieve growth in value and cash flows through exploration success and the ~~continued expansion~~development of a ~~high quality~~high-quality, diversified portfolio of producing assets that is balanced ~~and diversified among~~between US and international projects, crude oil and natural gas, and near, medium and long-term opportunities.

Our financial results for ~~first~~the second quarter of 2012 included:

net income of $292 million, as compared with $294 million for second quarter 2011;

dry hole cost of $118 million, as compared with $45 million for second quarter 2011;

impairment loss of $73 million, as compared with $131 million for second quarter 2011;

gain on commodity derivative instruments of $276 million (including unrealized mark-to-market gain of $277 million) as compared with a gain on commodity derivative instruments of $143 million (including unrealized mark-to-market gain of $142 million) for second quarter 2011;

diluted earnings per share of $1.58, as compared with $1.61 for second quarter 2011;

cash flow provided by operating activities of $506 million, as compared with $745 million for second quarter 2011;

ending cash balance of $702 million, as compared with $1.5 billion at December 31, 2011;

capital spending, on a cash basis, of $882 million, as compared with $683 million for second quarter of 2011; and

ratio of debt-to-book capital of 36% as compared with 38% at December 31, 2011.

Key highlights for the second quarter 2012 included:

●

~~net income of $263 million, as compared with $14 million for first quarter 2011;~~

horizontal net production within the DJ Basin increased 33% percent from last quarter;

●

loss on commodity derivative instruments of $96 million (including unrealized mark-to-market loss of $73 million) as compared with a loss on commodity derivative instruments of $286 million (including unrealized mark-to-market loss of $303 million) for first quarter 2011;

improved Wattenberg horizontal well estimated ultimate recoveries (EURs) in the extension area;

●

~~diluted earnings per share of $1.47, as compared with $0.08 for first quarter 2011;~~

Marcellus Shale well with extended-reach lateral of 8,500 feet produced at an initial rate of 17.9 MMcf/d;

●

~~cash flow provided by operating activities of $741 million, as compared with $484 million for first quarter 2011;~~

Aseng field, offshore Equatorial Guinea, produced at a record average gross rate of 63 MBbl/d of oil (21 MBbl/d net);

●

~~ending cash balance of $1.1 billion, as compared with $1.5 billion at December 31, 2011;~~

initiated gross production from the Noa field, offshore Israel, at a rate of 100 MMcf/d (41 MMcf/d net);

●

~~capital spending, on a cash basis, of $1 billion, as compared with $578 million for first quarter of 2011; and~~

signed a sales agreement to divest Dumbarton and Lochranza assets in the North Sea;

●

~~ratio of debt-to-book capital of 37% as compared with 38% at December 31, 2011.~~

achieved start-up at the Galapagos project in the deepwater Gulf of Mexico at rates 30% above original estimates; and

identified as high bidder on six deepwater Gulf of Mexico blocks at the Outer-Continental Shelf Sale 222.

Exploration Program Update

~~Operational events for first quarter 2012 included:~~

~~Overall~~

●

~~record total sales volume of 243 MBoe/d, up 10 MBoe/d over the fourth quarter of 2011; and~~

●

~~liquids represent 47% of total sales volumes, up from 40% in the fourth quarter of 2011;~~

~~United States~~

●

~~horizontal production from the DJ Basin averaged 18 MBoe/d net, or 25% of the total DJ Basin volumes;~~

●

~~expanded the Northern Colorado acreage position by 48,000 net acres to 230,000 net acres, where recent Company horizontal Niobrara results indicate recoveries comparable to Wattenberg; and~~

●

~~assumed operatorship in the wet gas area of the Marcellus Shale joint venture acreage;~~

~~International~~

●

~~gross daily crude oil production from the Aseng field, offshore Equatorial Guinea, achieved 60 MBbl/d;~~

●

~~signed a natural gas sales contract with Israel Electric Corporation Limited for 2.7 Tcf of natural gas; and~~

●

~~announced the Tanin discovery offshore Israel.~~

~~Table of Contents~~

~~Exploration Program Update~~

We ~~have~~continue to evaluate and build upon our significant ~~remaining~~ exploration ~~potential~~inventory in the onshore US, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other international new venture locations. We continually evaluate and high-grade our exploration inventory to provide additional growth opportunities and potential new core areas. In addition, each of our existing core areas ~~where we hold acreage positions. Significant~~has significant remaining exploration upside. We continue to leverage existing activities to improve our exploratory programs in these core areas.

We were in the process of drilling and/or evaluating significant exploratory wells ~~were in progress~~ at ~~March 31,~~June 30, 2012 ~~such as Deep Blue and the deep crude oil test at Leviathan-1~~ (See Item 1. Financial Statements – Note 7.8. Capitalized Exploratory Well Costs), and we expect to continue an active exploratory drilling program ~~during~~in the ~~remainder~~future.

Table of ~~2012.~~ Contents

We devote significant capital to our exploration program; approximately 20% of our $3.5 billion capital investment program in 2012 is dedicated to exploration and associated appraisal activities. However, we do not always ~~find proved reserves~~encounter hydrocarbons through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a project is not economically or operationally viable.

We are currently conducting, or planning to conduct, exploratory drilling activities in previously unexplored areas as well as appraisal activities at several of our discoveries. In the event we conclude that one of our ~~discoveries~~exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. As a result, in a future period, dry hole cost could be significant.

For example, during 2012, we recorded total dry hole cost of $118 million primarily related to the Deep Blue exploratory well (deepwater Gulf of Mexico). The Deep Blue well was originally spud in late 2009 and sidetrack operations were underway when the deepwater Gulf of Mexico moratorium was announced. After the moratorium was lifted we were able to resume operations and finish the sidetrack. Although hydrocarbons were found in both the initial exploration well and subsequent sidetrack, we and our partners have decided not to proceed with additional appraisal activities at this time.

In addition to dry hole cost, unfavorable exploration activity on a property being evaluated or changes in exploration plans can lead to impairment of capitalized undeveloped leasehold costs, resulting in additional expense.

Updates of our significant exploration activities are as follows:

DJ Basin(Onshore US) Our DJ Basin ~~(Onshore US)~~ position now includes over 880,000 net acres and provides us with opportunities to significantly expand beyond our core Wattenberg area activities. We continue to acquire 3-D seismic information and appraise our Northern Colorado and Wyoming acreage.

Northeast Nevada (Onshore US) We constantly strive to identify new onshore exploration opportunities with reasonable entry cost, significant running room and the potential to become a new core area. We recently added a 330,000 net acre position in Northeast Nevada, prospective for oil exploration, which we identified through basin scale reconnaissance and innovative geoscience concepts. We are planning to acquire 3-D seismic over portions of the acreage during 2012, to be followed by a vertical well exploratory drilling program in 2013.

Deepwater Gulf of Mexico We hold significant exploration potential in the deepwater Gulf of Mexico. We plan to continue our exploration activities in the second half of 2012 and are evaluating potential new drilling sites, including our Talon and Big Bend prospects. We also participated in the Central Gulf of Mexico Lease Sale 216/222 and were the apparent high bidder on six deepwater blocks. Deepwater royalty suspension provisions are not applicable to these leases.

Offshore West Africa We are continuing our exploration and appraisal efforts offshore West Africa, where we still have numerous opportunities offshore Equatorial Guinea and Cameroon. Our next planned exploratory well will be the Trema well, on the Tilapia block offshore Cameroon, which we expect to spud in the second half of 2012. We will also begin an appraisal program for our Diega and Carla discoveries and plan to spud an appraisal well before the end of 2012.

In July 2012, the Government of Sierra Leone provisionally awarded us participation in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million acres. The terms are subject to negotiations with the Petroleum Directorate of Sierra Leone.

The first appraisal period for the non-operated AGC Profond block, offshore Senegal/Guinea-Bissau, is due to expire in September 2012. The operator and joint venture partners are currently evaluating whether to move into the second appraisal period. If we elect not to participate in the second appraisal period, undeveloped leasehold cost of $40 million will be charged to expense.

Eastern Mediterranean We continue an active exploration program targeting both natural gas and crude oil resources. In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two deeper intervals for the existence of crude oil (Leviathan-1 Deep). In May 2012, due to high well pressure and the mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach the planned objective, we are encouraged by the possibility of an active thermogenic (heat producing) petroleum system at greater depths within the basin. We will integrate the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically to test the deep oil concept. Part of the plan will be to secure a rig with the capabilities necessary to reach the target objective.

We are also processing recently acquired seismic information and evaluating other offshore Israel locations for potential

Table of Contents

exploratory drilling.

In 2011 we announced a significant natural gas discovery at the A-1 well on Block 12, offshore Cyprus. We are in the process of preparing an appraisal plan and reviewing locations for appraisal drilling activities. See Major Development Projects Update - Block 12, below.

Offshore Nicaragua We continue to evaluate our undeveloped acreage for potential drilling sites.

Offshore France We and our partner applied to the French government for an extension of our offshore exploratory license. The period for regulatory review expired without official notification from the French government; therefore, the license was relinquished effective July 15, 2012. The relinquishment had no material impact on our financial position or results of operations.

Major Development Projects Update

During the second quarter of 2012, we continued to advance our major development projects, many of which have resulted from our exploration success. We expect these projects to deliver significant growth in production over the next several years. Updates on our significant development projects are as follows:

Horizontal Niobrara (Onshore US) We have increased our horizontal drilling activity targeting the Niobrara formation in the Wattenberg area, resulting in a significant positive impact on our current production volumes. We expect to drill close to 190 horizontal wells during 2012, more than double the number of horizontal wells that we drilled last year in the area, and we continue to move into areas of higher liquids content. We completed 43 horizontal wells during the second quarter of 2012.

We continue to refine our Wattenberg development strategy to increase our access to additional resources. We continue to evaluate both vertical and areal incremental recoveries, impacts of changes in well spacing and pad design using EcoNode concepts (consolidated well processing facilities), and extended-reach (9,000 feet) lateral wells. We are also testing the Niobrara "C Chalk" and the Codell formation on a horizontal basis.

Additionally, we continue to expand these development activities into Northern Colorado, where our recent horizontal Niobrara results indicate recoveries comparable to those in the Wattenberg area. We have added almost 26,000 net acres to our Northern Colorado position this year, increasing our acreage position to approximately 230,000 net acres. We expect to drill 35-40 horizontal wells, of the planned 190 horizontal wells discussed above, in Northern Colorado, ~~and Wyoming.~~moving to full phase development by the end of the year.

Marcellus Shale (Onshore US) Our joint venture partnership with CONSOL, formed in September 2011, has provided us with a 50% interest in approximately 628,000 net acres in southwest Pennsylvania and northwest West Virgina. Due to the current low natural gas price environment, we and CONSOL have decreased the amount of drilling in the dry gas areas and increased the drilling in the wet gas areas. We assumed operatorship in the wet gas areas early this year.

By applying our DJ Basin experience, we continue to test with longer lateral wells, improved hydraulic fracturing design and optimal well placements. We plan to drill approximately 30 wells in the wet gas area this year, of which six wells were drilled during the second quarter of 2012. We expect to increase activity in the wet gas area with three drilling rigs operating by the end of the year. As we move into new areas, water supply and gas gathering infrastructure are expanding.

Although we have reduced drilling in the dry gas area due to the low natural gas price environment, the dry gas portion of the program continues to deliver economically attractive returns due to strong production performance, high net revenue interests, competitive costs, and access to market. The CONSOL carried cost obligation is currently suspended due to low natural gas prices. See Liquidity and Capital Resources - Contractual Obligations below.

~~Deep Blue~~Galapagos (Deepwater Gulf of Mexico) The Galapagos crude oil development project commenced production during the second quarter of 2012 and is currently producing at a sustained rate of approximately 14,500 Boe/d, net. Galapagos consists of three producing wells (Santa Cruz, Isabela and Santiago) connected to the non-operated Na Kika production platform via subsea tieback. We expect this project to have ~~completed~~strong cash flows and return on our investment. With the ~~analysis~~addition of Galapagos, our current deepwater Gulf of Mexico daily production has increased to approximately 30,000 Boe/d, net, with over 80% oil.

South Raton (Deepwater Gulf of Mexico) During the ~~data obtained from~~second quarter of 2012, the ~~side track~~South Raton crude oil development project commenced production at approximately 3 Mbbl/d, net. South Raton is tied back to a non-operated host facility. Due to the recent decline in near-term crude oil prices, we recognized a $34 million impairment loss for South Raton during the second

Table of Contents

quarter of 2012.

Gunflint (Deepwater Gulf of Mexico) In July 2012, we reached target depth on our Gunflint appraisal well and are currently evaluating the drilling results, a follow up to our significant 2008 Gunflint crude oil discovery. Additional appraisal locations are currently being evaluated. Front-end conceptual studies have been completed, and we are working ~~with our existing and potential new partners regarding their participation in an appraisal well.~~toward sanctioning of a scalable development project.

Alen (Block O, Offshore Equatorial Guinea)The Alen facilities are designed to provide a hub for future gas monetization opportunities, able to process up to 440 MMcf/d gross, of natural gas, which will be reinjected, and 40 MBbl/d, gross, of condensate which will be piped to the Aseng FPSO and sold. The production and injection wells have been completed; platform and subsea fabrication continue on schedule. First production is expected to commence in the fourth quarter of 2013.

Diega and Carla (Blocks I and O, Offshore Equatorial Guinea) The successful Diega appraisal well, drilled in 2011, encountered both crude oil and natural gas. Carla, also drilled in 2011, was a successful oil appraisal well. We are currently evaluating regional development scenarios and formulating a development plan.

Tamar (Offshore Israel) The Tamar natural gas project includes five subsea wells from which natural gas will flow to a new offshore platform. The natural gas will then be delivered via subsea pipeline to the Ashdod onshore terminal. The development will allow for significant expansion as the Israeli natural gas market grows. The development wells have been drilled, and platform fabrication continues as planned. Tamar remains on schedule for commissioning beginning in late 2012 with first sales in the second quarter of 2013. Natural gas sales contracts have been signed with numerous customers. See Recent Developments Offshore Israel below.

We expect the Israeli natural gas market to continue to grow, driven by both power generation and industrial demand, and are considering additional options for the further potential development of Tamar to provide additional natural gas for both in-country and export use; however, we have not yet sanctioned an additional development project at Tamar.

Leviathan (Offshore Israel) In late 2010, we announced a significant natural gas discovery at the Leviathan-1 well in the Levant ~~Basin. Additionally, we~~Basin offshore Israel. We will require one or two appraisal wells to further define Leviathan’s natural gas areal ~~extent in order to determine the best development option. See Major Development Projects Update – Leviathan below.~~extent.

In January 2012, we returned to drilling at the Leviathan-1 well, which was suspended during 2011, in order to evaluate additional intervals for the existence of crude oil. Although the geological likelihood of success is low, the drilling results, which are expected in the second quarter of 2012, will yield valuable information about this new basin.

~~Tanin 1 (Offshore Israel)~~ ~~In February 2012 we announced a natural gas discovery at the Tanin prospect, approximately 13 miles northwest of the Tamar field.~~

~~Additionally, we have acquired approximately 330,000 net acres in the state of Nevada. We are currently planning 3-D seismic testing in 2012 and exploration drilling in 2013.~~

~~Major Development Projects Update~~

During the first quarter of 2012, we continued to advance our major development projects, which we expect to deliver significant growth over the next several years. Updates on our significant development projects are as follows:

~~Horizontal Niobrara (Onshore US)~~ We have increased our horizontal drilling activity targeting the Niobrara formation, completing 30 horizontal wells during the quarter. We recently added another horizontal drilling rig to our program and are currently running six horizontal drilling rigs.

~~Marcellus Shale (Onshore US)~~ During the first quarter of 2012, we took over operatorship of our first rig in the wet gas area of the Marcellus Shale, bringing the total rig count operating in the joint venture properties to seven. We drilled five horizontal wells reaching target depth during the quarter. By the end of the year, we expect to operate three rigs in the wet gas area while our partner CONSOL expects to operate two rigs in the dry gas area.

~~Galapagos (Deepwater Gulf of Mexico)~~ Installation of topside equipment at the host facility and subsea tiebacks for Santa Cruz, Isabela and Santiago have been completed and we are working with the host platform operator to perform final commissioning work. We expect production to commence in the second quarter of 2012.

~~Gunflint (Deepwater Gulf of Mexico)~~ We are currently drilling an appraisal well at Gunflint. We currently anticipate drilling up to two additional appraisal wells to fully evaluate the extent of the reservoir. We are also reviewing host platform options, including subsea tieback to an existing third-party host and construction of a new facility, which will likely lead to sanctioning of a development project.

~~Alen (Offshore Equatorial Guinea)~~ All sub-sea trees have been installed and sub-sea fabrication is underway. The production and injection wells are also on schedule and first production is expected to commence in the fourth quarter of 2013.

~~Diega (Offshore Equatorial Guinea)~~ ~~We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.~~

~~Carla (Offshore Equatorial Guinea)~~ In late 2011, we drilled the Carla well, a successful oil appraisal well in Block O, offshore Equatorial Guinea. We are evaluating drilling results from our Carla discovery well and reviewing development options and formulating a development plan for these areas.

~~Tamar (Offshore Israel)~~ Tamar development drilling and platform fabrication are ongoing. Pipeline installation is essentially complete, and the project remains on schedule for commissioning beginning in late 2012 and first sales in the second quarter of 2013. We also finalized several natural gas sales and purchase agreements during the quarter. See Israel Delivery Commitments below.

~~Noa/Pinnacles (Offshore Israel)~~ The Noa field is being developed as a subsea tieback to the Mari-B platform. Two development wells have been drilled, FEED (front end engineering and design) work has been completed, and installation and fabrication are progressing on schedule. In addition to Noa, we drilled the Pinnacles-1 well and are currently in the process of completing and tying the well back to the Mari-B platform. Noa and Pinnacles will help meet Israeli natural gas demands until the Tamar field begins producing. We expect production from both Noa and Pinnacles to commence in the third quarter of 2012. See Israel Delivery Commitments below.

~~Table of Contents~~

~~Leviathan (Offshore Israel)~~ We have project and commercial teams in place and are considering our natural gas commercialization options. Due to the ~~size~~scale of the ~~field,~~discovery, economic viability depends on the ability to export via pipeline or LNG. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. Engineering design and planning work are currently underway for a potential first phase of ~~development; however,~~development. In addition, we are working with our existing partners to identify a potential partner who can provide technical and financial support as well as midstream and downstream expertise; therefore, we have not yet sanctioned a development project. See Operating Outlook - Israeli Interministerial Committee, below.

Block 12 (Offshore Cyprus) During the fourth quarter of 2011, we drilled a successful natural gas exploration well (A-1) in Block 12. We are in the process of evaluating our commercialization options, including LNG, for the Block 12 natural gas ~~discovery.~~discovery; however, we have not yet sanctioned a development project.

~~Northern Region Transportation Curtailments~~Asset Impairment Charges

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions, mechanical or other reasons. In addition, continued drilling activity in concentrated areas, such as the DJ Basin and Marcellus Shale, can result in production growth outstripping available transportation and gathering capacity.

~~Due to both scheduled and unscheduled curtailments of third party pipeline services for significant equipment repairs and upgrades, we expect our Wattenberg area production to be impacted for~~During the second quarter of 2012, we recorded total impairment charges of $73 million. These charges included: an impairment charge of $39 million related to the Piceance development, onshore US, which was due primarily to recent declines in realized natural gas prices, and an impairment charge of $34 million related to the South Raton development, deepwater Gulf of Mexico, which was due to declines in near-term crude oil prices. See Item 1. Financial Statements - Note 4. Asset Impairments and Operating Outlook - Potential for Future Asset Impairments below.

Divestitures

We occasionally divest non-core, non-strategic properties from our portfolio to generate organizational and operational efficiencies as well as cash for use in our capital investment program. On May 30, 2012, we announced that we have entered into a definitive agreement for the sale of our 30% non-operated working interests in the Dumbarton and Lochranza fields, located in the UK sector of the North Sea, for $127 million, subject to customary adjustments for net cash flows between the effective date of January 1, 2012 and the closing date, which is expected to occur by the end of third quarter 2012.

We are continuing efforts to divest our remaining North Sea properties. Management has committed to a plan to sell the

Table of Contents

remaining assets, individually or as packaged groups, and no further approval by the Board of Directors is required. All criteria for classification of the North Sea properties as held for sale had been met as of June 30, 2012. Therefore, all North Sea properties were reclassified as assets held for sale as of June 30, 2012, and the results of operations for the North Sea geographical segment have been reclassified for all periods presented as discontinued operations. See Item 1. Financial Statements - Note 3. Acquisitions and Divestitures - Pending Sale of North Sea Properties.

We are also in the process of marketing certain non-core onshore US properties and currently soliciting bids. As of June 30, 2012, the Board of Directors and management had not committed to any specific plans to sell the assets, individually or as packaged groups. A sale of any of the asset packages currently being marketed requires approval by our Board of Directors. Therefore, none of these assets was reclassified as held-for-sale at June 30, 2012. See Operating Outlook - Potential for Future Asset Impairments below.

In July 2012, the Board of Directors approved the sale of certain crude oil and natural gas properties in western Oklahoma, western Texas, and the Texas Panhandle for $937 million. We subsequently signed sale agreements related to those properties with two purchasers. The combined net book values of these properties as of June 30, 2012, was approximately $765 million, excluding an allocation of US reporting unit goodwill. The transactions have effective dates of April 1, 2012 and are expected to close in the third quarter of 2012, subject to customary closing conditions and adjustments. The properties include our interests in about 1,150 producing wells on approximately 95,000 net acres. As of the effective date, net daily production was approximately 11,500 Boe/d.

Recent Developments Offshore Israel

Mari-B During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes were delivered at very high rates to support Israel’s growing natural gas and power demands. As a result, we experienced accelerated depletion of the Mari-B field. In January 2012, we announced a cut back in production at Mari-B to prudently manage the reservoir. We are currently working closely with our Israeli customers to manage demand from the Mari-B field and continue production from it.

In order to help meet Israeli natural gas demands until the Tamar field begins producing, we completed the Noa and Pinnacles wells and tied them back to the Mari-B platform. We began selling natural gas from Noa in June 2012 and from Pinnacles in July 2012.

Although Noa and Pinnacles wells are now producing, they will not completely offset the decline in Mari-B production. Therefore, we expect total Israel sales volumes for fiscal year 2012 will be lower than they were in fiscal year 2011. In addition, due to the cost of completing and tying back the Noa and Pinnacles wells, we expect that Israel DD&A expense for fiscal year 2012 will be higher than for fiscal year 2011. Therefore, we expect that our Eastern Mediterranean segment will not be as profitable in 2012 as it was in 2011.

Tamar We and our Tamar partners have entered into Gas Sale and Purchase Agreements (GSPAs) with the Israel Electric Corporation Limited (IEC) and six other Israeli purchasers, including independent power producers, cogeneration facilities and industrial companies, for the sale of natural gas from the Tamar field. During the second quarter of 2012, the Israel Public Utilities Authority - Electricity (PUA) and Israel Anti-Trust Authority reviewed the GSPAs. As a result, we are being required to modify certain terms in the GSPAs including the dates by which the IEC must exercise its increase option and the increase option price indexation. We also must provide each of our remaining purchasers the right, within 90 days of the PUA's decision, to request to shorten the term of the GSPA to seven years or provide them with a partial termination option within a window of time. In addition, we are being required to execute GSPAs on similar terms with additional purchasers, subject to capacity restraints.

After giving effect to the existing GSPA modifications mentioned above, we have agreed to the following:

the sale of approximately 2.7 Tcf of natural gas to IEC over an approximate 15-year period. IEC has the option to increase this amount to 3.5 Tcf, under certain conditions;

the sale of approximately 1.3 Tcf of natural gas to six remaining customers over a 16 to 17 year period. Some of the contracts provide for increase or reduction in total quantities; and

sales prices based on an initial base price subject to price indexation over the life of the contract and with a floor.

The IEC GSPA was amended to comply with the requirements raised by the Israeli regulators and became effective July 25, 2012. All remaining conditions precedent including Israel Anti-Trust Authority, PUA, and government approvals have been satisfied and thereby the IEC GSPA is in full force and effect.

Table of Contents

Leviathan-2 In May 2011, we ended drilling operations at the Leviathan-2 appraisal well when we identified water flowing to the sea floor from the wellbore. We are continuing to monitor the wellbore and there are no indications of any hydrocarbons in the produced water. We have been working with the Israeli government to determine appropriate abandonment activities.

The incident is a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. Our partners have insurance coverage, but may not have sufficient coverage to cover all possible outcomes relating to abandonment of the well and may have to rely on other financial resources. We do not expect any delays in our insurance claim recovery process to have a significant impact on our cash flows or liquidity. See Item 1. Financial Statements – Note 2. Basis of Presentation and Note 9. Asset Retirement Obligations.

See also Operating Outlook - Israeli Interministerial Committee, below.

Recent Developments in the Marcellus Shale

NETL Study ~~Well Impact Fee~~ ~~During~~The US Department of Energy's National Energy Technology Laboratory (NETL) is conducting a comprehensive assessment of the ~~first quarter~~environmental effects of 2012, the Pennsylvania legislature enacted an annual well impact fee which will be used by local governments, counties and state agencies to support the infrastructure and regulatory framework necessary to sustain effective shale gas production at two industry-provided Marcellus Shale test sites in southwestern Pennsylvania. Goals include:

documentation of environmental changes that are coincident with shale gas production;

development of ~~natural~~technology or management practices that mitigate undesigned environmental changes; and

development of monitoring technologies to (1) assess the impact of shale gas ~~resources~~production on air quality and (2)determine if zonal isolation between producing formations and drinking water aquifers is maintained after hydraulic fracturing.

We will monitor the results of the NETL study in ~~the Marcellus Shale. The well impact fee is a variable rate based on natural gas prices and the year a well is drilled. Due~~order to ~~the early stage of our Marcellus Shale development activities, the fee did not have a significant~~assess any potential impact on our ~~results of operations for the first quarter of 2012.~~onshore US development programs.

Butler v. Powers On September 7, 2011, an intermediate appellate court (Superior Court) in Pennsylvania issued an opinion in Butler v. Powers regarding the interpretation of a deed. As a result, traditional views of how ownership of shale gas is determined in that state have been called into question. The issue raised by the case is whether shale gas is different from other natural gas and should be considered part of mineral rights, rather than oil and gas rights, because shale gas is contained inside non-porous shale rock. An appeal of the decision was subsequently filed with the Pennsylvania Supreme ~~Court. The Pennsylvania Supreme~~ Court, ~~recently announced its decision~~which decided to hear the appeal. Written arguments in the case ~~are due by May 15, 2012.~~have been presented.

At this time, no case law or interpretation of existing law has changed, nor has there been an indication that either the Superior Court or the Pennsylvania Supreme Court will seek to change existing law. Based upon our initial review, we believe that any adverse decision in the pending case would have minimal adverse impact upon the assets acquired from CONSOL and our Marcellus Shale joint venture operations.

~~Recent Developments Onshore US~~

Researchers from the U.S. Geological Survey recently reported that they have observed an increase in seismic activity in the Midcontinent region and have indicated that the seismic activity may be attributable to injection wells that handle wastewater from oil and gas drilling activities. The researchers cite a series of examples for which an uptick in seismic activity is observed in areas where the disposal of wastewater through deep-well injection increased significantly. Regulators in Ohio and Arkansas are also looking at a possible connection between minor seismic events and disposal of wastewater in injection wells.

Minor and imperceptible seismic activity is extremely common in areas of oil and gas development. Historically, such activity has rarely caused damage. In addition, there are safeguards in place to reduce the likelihood of seismic activity caused by oil and gas drilling activities, including the disposal of wastewater. For example, we study the seismicity of the areas where we operate and design plans for each well based on our understanding of the specific geology. Steps taken to prevent seismic events include limiting increases in well pressure by reducing either the volume of wastewater pumped into the wells or the rate at which it is pumped. We also comply with requirements for injection well construction, operation, and closure set by the Underground Injection Control (UIC) Program, which was established under the provisions of the Safe Drinking Water Act of 1974.

~~Recent Developments Offshore France~~

We and our partner have applied to the French government for an extension of our offshore exploratory license until November 2015. The French government has thus far not responded officially to this application, even though the regulatory period for reply has passed. The current political climate is not favorable to our application, and we are unable to predict the ultimate outcome. Regardless of the final result, any curtailment of exploration activities offshore France would have no material impact on our financial position or results of operations.

~~Table of Contents~~

~~Recent Developments in West Africa~~

We currently have an interest in the AGC Profond block covering 2.4 million gross (724,000 net) undeveloped acres offshore Senegal/Guinea-Bissau. On March 26, 2012, a new president of Senegal was elected in a peaceful, democratic election. Conversely, on April 13, 2012, the interim government of Guinea-Bissau was deposed by military forces. The military and the opposition subsequently agreed to form a transitional council, but have not announced specific plans. We will continue to monitor these developments, and we currently cannot predict the impact these events may have on our future exploration plans in this area.

~~Israel Delivery Commitments~~

During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes were delivered at very high rates to support Israel’s growing natural gas and power demands. As a result, we experienced accelerated depletion of the Mari-B field. In January 2012, we announced a cut back in production at Mari-B, which is nearing the end of its expected production life, to prudently manage the reservoir. We are currently working closely with our Israeli customers to manage demand from the Mari-B field and continue production from it while wells from Noa and Pinnacles are drilled, completed and tied back to the Mari-B platform. We expect production to commence from Noa and Pinnacles during the third quarter of 2012 and the Tamar field during the second quarter of 2013.

On March 14, 2012, we and our Tamar partners entered into a Gas Sale and Purchase Agreement (GSPA) with the Israel Electric Corporation Limited (IEC). Under the terms of the GSPA, we have agreed to sell approximately 2.7 Tcf of natural gas produced from the Tamar field to IEC over an approximate 15-year period. At IEC’s option, this amount can be increased to 3.5 Tcf, under certain conditions. The term of the GSPA begins upon commissioning of the Tamar project. The sales price is based on an initial base price and will be subject to an inflation adjustment. The GSPA is attached as Exhibit 10.1 to this Quarterly Report on Form 10-Q.

As of April 15, 2012, we and our partners have also signed GSPAs with other Israeli customers, including independent power, cogeneration and manufacturing companies, to supply approximately 1.3 Tcf of natural gas over a 16 to 17 year period beginning in late 2013. These contracts provide for an initial base price, subject to an inflation adjustment, and some of the contracts provide for increases or decreases in total quantities. We continue to negotiate additional GSPAs with other potential customers.

Sales Volumes

On a BOE basis, total sales volumes, excluding sales volumes from discontinued operations, were ~~13%~~10% higher for the ~~first~~second quarter of 2012 as compared with the ~~first~~second quarter of 2011, and our mix of sales volumes was 47% global liquids, ~~23%~~21% international natural gas, and ~~30%~~32% US natural gas. US sales volumes increased due to continued acceleration of our horizontal drilling programs in Wattenberg along with our Marcellus Shale program, which began at the end of the third quarter of 2011. International crude oil sales volumes were higher in Equatorial Guinea due to the commencement of crude oil production at Aseng in the fourth quarter of 2011. Israel natural gas sales volumes were lower as we have reduced the rate of production from the Mari-B field in order to manage the reservoir. See ~~Israel Delivery Commitments above and~~ Results of Operations – Revenues below.

Commodity Price Changes and Hedging

Total consolidated average realized crude oil prices for the ~~first three months~~second quarter of 2012 ~~increased 14%~~decreased 5% as compared with the ~~first three months~~second quarter of 2011. ~~The increase was driven by the continued global economic recovery and continued threats to the global oil supply system.~~

US natural gas prices remain ~~weak. Average~~weak; US average realized natural gas prices for the ~~first three months~~second quarter of 2012 decreased ~~36%~~50% as compared with the ~~first three months~~second quarter of 2011 ~~primarily~~.

Price decreases were due to ~~abundant supply~~a slowdown in the global economic recovery, influenced by uncertainty over the Eurozone debt crisis, and ~~above average levels of natural gas~~an increase in ~~storage.~~supply. As long as ~~US natural gas~~ development activity continues at, or near, the current level and there is no significant increase in demand, ~~production growth will continue to outstrip growth in transportation and storage capacity, likely resulting in~~ downward pressure on ~~natural gas~~commodity prices ~~(See~~will continue. See Potential for Future Asset Impairments ~~below).~~below.

Table of Contents

We have hedged approximately 41% of our expected global crude oil production and 39% of our expected domestic natural gas production for the remainder of ~~2012.~~2012. See Item 1. Financial Statements – Note 5.6. Derivative Instruments and Hedging Activities.

OPERATING OUTLOOK

Our expected crude oil, natural gas and NGL production for 2012 may be impacted by several factors including:

●

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

●

~~timing of major development project completion and initial production;~~

●

~~ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;~~

●

~~ramp-up of development activity in the Marcellus Shale;~~

●

natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations, in the North Sea and the Mari-B field in Israel, where we reduced production to manage the reservoir (See Israel Delivery Commitments, above);

●

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

~~Table of Contents~~

●

Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries of natural gas from Egypt and commencement of production from the Noa field and Pinnacles project, offshore Israel;

●

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

●

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

●

~~potential winter storm-related volume curtailments in the Rocky Mountain and/or Marcellus Shale areas of our US operations;~~

●

~~potential pipeline and processing facility capacity constraints in the Rocky Mountain and/or Marcellus Shale areas of our US operations (see Northern Region Transportation Curtailments above);~~

●

~~potential drilling and/or hydraulic fracturing permit delays due to future regulatory changes;~~

●

~~potential purchases of producing properties and/or divestments of non-core operating assets; and~~

●

~~potential shut-in of US producing properties if storage capacity becomes unavailable.~~

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

timing of major development project completion and initial production;

ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;

pace of increase of development activity in the Marcellus Shale;

natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations and the Mari-B field in Israel, where we reduced production to manage the reservoir (See Recent Developments Offshore Israel, above);

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

Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries of natural gas from Egypt and production rates from the Noa field and Pinnacles project, offshore Israel;

variations in West Africa sales volumes due to potential FPSO downtime and timing of liftings;

impact of pending sales of certain onshore US and North Sea properties, expected to close by the end of third quarter 2012;

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

potential winter storm-related volume curtailments in the Wattenberg, Rocky Mountain, and/or Marcellus Shale areas of our US operations;

unseasonably high temperatures in the Wattenberg and/or Rocky Mountain areas of our US operations which may cause restrictions or interruptions in mid-stream processing facilities;

potential pipeline and processing facility capacity constraints in the Wattenberg, Rocky Mountain, and/or Marcellus Shale areas of our US operations;

potential drilling and/or hydraulic fracturing permit delays due to future regulatory changes;

potential purchases of producing properties and/or divestments of non-core operating assets; and

potential shut-in of US producing properties if storage capacity becomes unavailable.

2012 Capital Investment Program

Our total capital investment program for 2012 is estimated at $3.5 billion. The capital investment program allocates approximately 50% to onshore US and the remainder to offshore deepwater Gulf of Mexico, Eastern Mediterranean, and West Africa. Exploration and appraisal activity within these geographic areas is expected to receive approximately 20% of total capital.

We expect that the remainder of the 2012 capital investment program will be funded from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as an issuance of long-term debt. Funding ~~may~~will also be provided by proceeds from divestment of non-core assets. See Liquidity and Capital Resources – Financing Activities below.

We will evaluate the level of capital spending and remain flexible throughout the year based on the following factors, among others:

●

commodity prices, including price realizations on specific crude oil and natural gas production including the impact of NGLs;

●

cash flows from operations;

●

operating and development costs and possible inflationary pressures;

●

permitting activity in the deepwater Gulf of Mexico;

●

drilling results;

CONSOL Carried Cost Obligation (See Contractual Obligations below);

property acquisitions and divestitures;

●

~~CONSOL Carried Cost Obligation (See Contractual Obligations below);~~

Table of Contents

availability and cost of financing;

●

~~property acquisitions and divestitures;~~

potential legislative or regulatory changes regarding the use of hydraulic fracturing;

●

~~availability of financing;~~

potential changes in the fiscal regimes of the US and other countries in which we operate; and

●

~~potential legislative or regulatory changes regarding the use of hydraulic fracturing;~~

●

~~potential changes in the fiscal regimes of the US and other countries in which we operate; and~~

●

impact of new laws and regulations, including implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act, on our business practices.

~~Marketing of North Sea and Onshore US Assets~~

We occasionally divest non-core, non-strategic properties from our portfolio to generate organizational and operational efficiencies as well as cash for use in our capital investment program. We are in the process of marketing our North Sea properties along with certain non-core onshore US properties and are currently soliciting bids. However, at this time, the Board of Directors and management have not committed to any specific plans to sell the assets, individually or as packaged groups. See Potential for Future Asset Impairments below.

Potential for Future Asset Impairments

~~The~~Global crude oil prices are volatile and decreased during the second quarter of 2012. In addition, US natural gas prices are volatile and the natural gas market remains weak. A ~~decrease from the March 31, 2012 forward~~further decline in future NYMEX crude oil or natural gas prices could result in additional impairment charges. Certain of our onshore US properties have significant natural gas reserves and therefore are sensitive to declines in natural gas prices. These properties are at risk of impairment if future NYMEX Henry Hub natural gas prices experience further decline. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in an ~~impairment of properties that are sensitive to declines in natural gas prices.~~impairment.

Additionally, we are currently marketing certain non-core onshore US properties. If the properties are reclassified as assets held for sale, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell.

~~The~~ In addition, we would allocate a portion of goodwill to any non-core onshore US ~~properties discussed above have~~property held for sale that constitutes a ~~combined net book value of approximately $1 billion at March 31, 2012.~~

business, which could potentially decrease any gain or increase any loss recorded on the sale.

~~Table of Contents~~

Israeli Interministerial Committee

In 2011, the Interministerial Committee to Examine Government Policy Regarding the Natural Gas Industry in Israel (the Committee) was charged with the task of proposing a government policy for developing the natural gas economy. Objectives include the following:

●

ensuring energy security in the economy;

providing a framework for substantial resource exports;

designating a certain percentage of production from each field for the domestic natural gas market;

●

~~providing a framework for substantial resource exports;~~

maintaining competition in the different sectors of the local economy;

●

~~designating a certain percentage of production from each field for the domestic natural gas market;~~

maximizing economic and political benefits; and

●

~~maintaining competition in the different sectors of the local economy;~~

leveraging environmental advantages with respect to the use of natural gas.

●

~~maximizing economic and political benefits; and~~

●

~~leveraging environmental advantages with respect to the use of natural gas.~~

The Committee was also asked to examine, among other items, the desired policy to maintain reserves to supply local demand and export of natural gas. The Committee issued Interim Recommendations on April 5, 2012, which included, among others:

●

requiring a minimum 25-year supply of gas to the domestic market;

●

allowing for a redetermination of market needs after the year 2018;

●

requiring regulatory approval for export;

●

determining that an Israeli natural gas export facility be under Israeli control and within the jurisdiction of Israel’s economic waters;

●

taking steps to increase competition in the natural gas market; and

●

requiring infrastructure redundancy, physical connection of all reservoirs to the domestic market, third party access to infrastructure, and the development of statutory procedures to define infrastructures.

~~The Committee's timeline includes a public hearing on May 20, 2012 and submission of~~We expect the Committee to issue a final report ~~on June 7,~~during the third quarter of 2012. We also expect that the Israeli government will enact laws and regulation in response to the Committee's recommendations.

We are participating in the process and monitoring the ~~activities~~progress of the Committee and the impact of its ~~Interim Recommendations.~~recommendations. However, at this time, we cannot predict the ultimate outcome of the Committee’s ~~Interim Recommendations~~recommendations or the possible impact any resulting laws or regulations could have on our business. Certain changes in Israel’s market, fiscal, and/or regulatory regimes occurring as a result of the Committee’s recommendations could delay or reduce the profitability of our Tamar and/or Leviathan development projects and render future exploration and development projects uneconomic.

~~EPA Final Emissions Standards~~Impact of Dodd-Frank Act

On April 18, 2012, the U.S. Environmental Protection Agency (EPA) announced that it has finalized standards related to emissions associated with crude oil and natural gas production, including natural gas wells that are hydraulically fractured. The required technologies and processes, while reducing emissions, will also enable companies to collect additional natural gas that can be sold. The EPA’s final standards also address emissions from storage tanks and other equipment.

The ~~final~~Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was passed by Congress and

Table of Contents

signed into law in July 2010, contains significant derivatives regulation, including requirements that certain transactions be cleared on exchanges and that cash collateral (commonly referred to as “margin”) be posted for such transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, such as us, and it includes a number of defined terms used in determining how this exception applies to particular derivative transactions and the parties to those transactions. As required by the Act, the Commodities Futures and Trading Commission (CFTC) has promulgated numerous rules ~~establish a phase-in period that will ensure that manufacturers have time~~ to make and broadly distribute the required emissions reduction technology. During the first phase, until January 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green completions,” technologies that are already widely deployed at wells. In 2015, all newly fractured wells will be required to use green completions.define these terms.

We are currently evaluating the ~~EPA’s~~provisions of the CFTC's final rules and assessing ~~the~~their impact on our ~~business.~~ commodity hedging program. At this time, we believe that we will be able to satisfy the requirements for the commercial end-user clearing exception and continue to engage in transactions which hedge commercial risk and are free of mandated clearing requirements.

It is possible that the CFTC, in conjunction with prudential regulators may mandate that financial counterparties entering into swap transactions with end-users must do so with collateral support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral. If this should occur, we intend to manage our credit relationships to minimize collateral requirements.

The ~~reduction~~CFTC's final rules will also have an impact on our hedging counterparties. For example, our counterparties will be required to post collateral and assume compliance burdens resulting in additional costs. We expect that much of ~~greenhouse gas emissions (GHG) is already one~~the increased costs will be passed on to us, thereby decreasing the relative effectiveness of our ~~Company's priorities~~hedges and ~~we have been working to improve~~ our methods to reduce GHGs through operational and business practices. We use green completions or flaring on a number of our wells to comply with COGCC rules. Additionally we've undertaken emission reduction projects such as our US Vapor Recovery Unit (VRU) program, where we have installed VRUs to capture gas that would otherwise be flared on a substantial number of our tank batteries.

profitability.

Risk and Insurance Program

Our business is subject to all of the operating risks normally associated with the exploration, production, gathering, processing and transportation of crude oil and natural gas, including hurricanes, blowouts, well cratering, fire, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals, any of which could result in damage to, or destruction of, crude oil and natural gas wells or formations or production facilities and other property, environmental pollution, injury to persons, or loss of life. As protection against financial loss resulting from many, but not all of these operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of ~~production)~~production income), employer’s liability, comprehensive general liability and worker’s compensation insurance. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our potential risks of loss and the cost and availability of insurance and revise our insurance program accordingly. We have limited or no insurance coverage for certain risks such as war or political risk. In addition, coverage is generally limited or not available to us for pollution events that are considered gradual.

In certain international locations (including Israel and Equatorial Guinea) we carry business interruption insurance for loss of ~~revenue~~production income arising from physical damage to our facilities caused by fire and natural disasters. The coverage is subject to customary deductibles, waiting periods and recovery limits.

~~Table of Contents~~

In the Gulf of Mexico, we self-insure for windstorm related exposures. Our Gulf of Mexico assets are primarily subsea operations; therefore, our windstorm exposure is limited. In addition, the cost of windstorm insurance continues to be very expensive and coverage amounts are limited. We believe it is more cost-effective for us to self-insure these assets.

As is customary with industry practice, crude oil and natural gas well owners generally indemnify drilling rig contractors against certain risks, such as those arising from property and environmental losses, pollution from sources such as oil spills, or contamination resulting from well blowout or fire or other uncontrolled flow of hydrocarbons. Most of our US and international drilling contracts contain such indemnification clauses. In addition, crude oil and natural gas well owners typically assume all costs of well control in the event of an uncontrolled well. We currently carry more than $700 million insurance protection, ~~for~~depending on our ~~net share of any~~ownership interest, for potential financial losses occurring as a result of events such as the Deepwater Horizon Incident. This protection consists of ~~$550~~more than $500 million of well control, pollution cleanup and consequential damages coverage and ~~$326~~more than $200 million of additional pollution cleanup and consequential damages coverage, which also covers third-party personal injury and death. Consequently if we were to experience an accident similar to the Deepwater Horizon Incident, our total coverage for cleanup and consequential damages would cover a gross loss of at least $876 million depending on our ownership interest and subject to reduction for claims related to well control and third-party damages.

We have contracts with third-party service providers to perform hydraulic fracturing operations for us. The master service agreements signed by hydraulic fracturing providers contain indemnification provisions similar to those noted above. Our liability insurance policies do not contain any specific exclusions for liabilities from hydraulic fracturing operations and we believe our policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. We do not have insurance for gradual pollution nor do we have coverage for penalties or fines that may be assessed by a governmental authority.

Table of Contents

We expect the future availability and cost of insurance to be impacted by the various catastrophic events ~~which occurred in 2011.~~and large losses that insurers have incurred over the past several years. Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for claims of damages from oil spills. We anticipate that ongoing changes in the types of coverage available in the insurance market may result in lower effective coverages and/or the incurrence of higher premiums to achieve past levels of coverage.

We continue to monitor the legislative and regulatory response to the Deepwater Horizon Incident of 2010 and other recent international incidents in Brazil and the North Sea, and their impact on the insurance market and our overall risk profile. We anticipate that, at a minimum, less effective liability coverage will be available at a higher cost. Accordingly, we may adjust our risk and insurance program to provide protection at insured levels that reflect our perception of the cost of risk relative to frequency and severity of the exposure.

~~Insurance Recoveries~~ In May 2011, we ended drilling operations at the Leviathan-2 appraisal well offshore Israel when we identified water flowing to the sea floor from the wellbore. We are continuing to monitor the wellbore and there are no indications of any hydrocarbons in the produced water. Drilling did not reach the depth of the targeted gas intervals discovered in the Leviathan-1 well. We are working with the Israeli government to determine appropriate abandonment activities.

The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. Our partners have insurance coverage, but may not have sufficient coverage to cover all possible outcomes and may have to rely on other financial resources. We do not expect any delays in our insurance claim recovery process to have a significant impact on our cash flows or liquidity. See Item 1. Financial Statements – Note 2. Basis of Presentation.

Our business entails inherent risks. We have a risk assessment program that analyzes safety and environmental hazards and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We have a robust prevention program and continue to manage our risks and operations such that we believe the likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by insured limits or our non-operating partners are not fully insured, it could have a material adverse impact on our financial condition, results of operations and cash flows. See Executive Overview - Recent Developments Offshore Israel.

Recently Issued Accounting Standards ~~Update~~Updates

See Item 1. Financial Statements – Note 2. Basis of Presentation.

RESULTS OF OPERATIONS

In the discussion below, prior year amounts have been reclassified to reflect the North Sea segment as discontinued operations. See Discontinued Operations, below.

Revenues

Revenues were as follows:

Increase
(Decrease)
2012 2011 from Prior Year
(millions)
Three Months Ended March 31,
Oil, Gas and NGL Sales $ 1,112 $ 830 34 %
Income from Equity Method Investees 53 48 10 %
Other Revenues - 21 (100 %)
Total $ 1,165 $ 899 30 %



					Increase (Decrease) from Prior Year
	2012		2011		Increase (Decrease) from Prior Year
(millions)
Three Months Ended June 30,
Oil, Gas and NGL Sales	$	934	$	783	19	%
Income from Equity Method Investees	32		48		(33	)%
Other Revenues	—		11		(100	)%
Total	$	966	$	842	15	%

Six Months Ended June 30,
Oil, Gas and NGL Sales	$	1,970	$	1,500	31	%
Income from Equity Method Investees	86		96		(10	)%
Other Revenues	—		33		(100	)%
Total	$	2,056	$	1,629	26	%

~~Table of Contents~~

Changes in revenues are discussed below.

Table of Contents

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

	Sales Volumes								Average Realized Sales Prices
	Crude Oil & Condensate		Natural Gas		NGLs		Total		Crude Oil & Condensate		Natural Gas		NGLs
	(MBbl/d)		(MMcf/d)		(MBbl/d)		(MBoe/d) (1)		(Per Bbl)		(Per Mcf)		(Per Bbl)		Sales Volumes					Average Realized Sales Prices
Three Months Ended March 31, 2012
															Crude Oil & Condensate (MBbl/d)	Natural Gas (MMcf/d)		NGLs (MBbl/d)	Total (MBoe/d) ⁽¹⁾	Crude Oil & Condensate (Per Bbl)		Natural Gas (Per Mcf)		NGLs (Per Bbl)
Three Months Ended June 30, 2012															Three Months Ended June 30, 2012
United States		42		433		17		131	$	101.21	$	2.62	$	41.62	46	431		16	134	$	94.49	$	2.10	$	33.06
Equatorial Guinea (2)		35		230		-		73		118.04		0.27		-	34	215		—	70	104.55		0.27		—
Israel		-		108		-		18		-		4.51		-	—	60		—	10	—		5.44		—
North Sea		6		5		-		7		122.44		7.88		-
China		5		-		-		5		126.10		-		-	5	—		—	5	115.41		—		—
Total Consolidated Operations		88		776		17		234		110.80		2.22		41.62	85	706		16	219	99.67		1.82		33.06
Equity Investees (3)		2		-		7		9		110.09		-		68.02	1	—		4	5	109.98		—		61.47
Total Operations		90		776		24		243	$	110.78	$	2.22	$	49.34
Three Months Ended March 31, 2011
Total Continuing Operations															86	706		20	224	$	99.81	$	1.82	$	38.87
Three Months Ended June 30, 2011															Three Months Ended June 30, 2011
United States		37		382		14		114	$	92.25	$	4.07	$	47.80	37	378		15	115	$	101.99	$	4.21	$	50.03
Equatorial Guinea (2)		13		248		-		55		103.49		0.27		-	11	233		—	50	114.80		0.27		—
Israel		-		140		-		23		-		4.19		-	—	174		—	29	—		4.81		—
North Sea		11		8		-		12		106.26		7.30		-
China		4		-		-		4		95.28		-		-	3	—		—	3	109.96		—		—
Total Consolidated Operations		65		778		14		208		97.15		2.91		47.80	51	785		15	197	105.23		3.18		50.03
Equity Investees (3)		2		-		5		7		103.93		-		75.71	2	—		5	7	115.23		—		75.83
Total Operations		67		778		19		215	$	97.32	$	2.91	$	55.43
Total Continuing Operations															53	785		20	204	$	105.58	$	3.18	$	56.65

Six Months Ended June 30, 2012															Six Months Ended June 30, 2012
United States															44	432		16	132	$	97.70	$	2.36	$	37.46
Equatorial Guinea ⁽²⁾															35	222	��	—	72	111.38		0.27		—
Israel															—	84		—	14	—		4.84		—
China															5	—		—	5	120.93		—		—
Total Consolidated Operations															84	738		16	223	$	104.70	$	2.01	$	37.46
Equity Investees ⁽³⁾															2	—		5	7	110.05		—		65.57
Total Continuing Operations															86	738		21	230	$	104.80	$	2.01	$	44.50
Six Months Ended June 30, 2011															Six Months Ended June 30, 2011
United States															37	380		14	114	$	97.15	$	4.14	$	48.98
Equatorial Guinea ⁽²⁾															12	240		—	52	108.57		0.27		—
Israel															—	157		—	26	—		4.54		—
China															4	—		—	4	102.61		—		—
Total Consolidated Operations															53	777		14	196	100.14		3.02		48.98
Equity Investees ⁽³⁾															2	—		5	7	109.89		—		74.16
Total Continuing Operations															55	777		19	203	$	100.46	$	3.02	$	56.06


⁽¹⁾	Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price differentials, the price for a barrel of oil equivalent for natural gas is significantly less than the price for a barrel of oil.


⁽²⁾	Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an ~~LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.~~

Table of Contents

LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.


⁽³⁾	Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees below.

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

	Commodity Price Increase (Decrease)
	2012					2011
	Crude Oil & Condensate			Natural Gas		Crude Oil & Condensate			Natural Gas		Commodity Price Increase (Decrease)
	(Per Bbl)			(Per Mcf)		(Per Bbl)			(Per Mcf)		2012					2011
Three Months Ended March 31,
											Crude Oil & Condensate			Natural Gas		Crude Oil & Condensate			Natural Gas
											(Per Bbl)			(Per Mcf)		(Per Bbl)			(Per Mcf)
Three Months Ended June 30,
United States	$	(2.40	)	$	0.28	$	(2.75	)	$	0.76	$	(0.26	)	$	0.41	$	(6.67	)	$	0.67
Equatorial Guinea		(7.84	)		-		-			-	(5.02		)	—		—			—
Total Consolidated Operations		(4.26	)		0.16		(1.56	)		0.37	(2.16		)	0.25		(4.82		)	0.32
Total Operations		(4.17	)		0.16		(1.52	)		0.37
Total Continuing Operations											(2.14		)	0.25		(4.64		)	0.32

Six Months Ended June 30,
United States											$	(1.28	)	$	0.35	$	(4.72	)	$	0.71
Equatorial Guinea											(6.45		)	—		—			—
Total Consolidated Operations											(3.34		)	0.20		(3.29		)	0.35
Total Continuing Operations											(3.26		)	0.20		(3.15		)	0.35


⁽³⁾	Other International includes various international new ventures such as offshore Nicaragua.

Exploration expense for the second quarter and first ~~three~~six months of 2012 included the following:

dry hole cost related primarily to the Deep Blue exploratory well (deepwater Gulf of Mexico). Although Deep Blue was successful in locating hydrocarbons, we decided not to develop the prospect due to near-term lease expiration as well as other considerations;

acquisition of seismic information for the deepwater Gulf of Mexico lease sale; and

staff expense associated with new ventures and corporate expenditures.

●

~~acquisition of seismic information for the deepwater Gulf of Mexico; and~~

●

~~staff expense associated with new ventures and corporate expenditures.~~

Exploration expense for the second quarter and first ~~three~~six months of 2011 included the following:

dry hole cost associated with exploratory drilling in the US Rocky Mountain area and offshore Senegal/Guinea-Bissau;

acquisition of seismic information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, and international new ventures; and

staff expense associated with new ventures and corporate expenditures.

●

~~dry hole cost associated with exploratory drilling in the US Rocky Mountain area;~~

Table of Contents

●

~~acquisition of seismic information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, and international new ventures; and~~

●

~~staff expense associated with new ventures and corporate expenditures.~~

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

Three Months Ended March 31,
2012 2011
DD&A Expense (millions) (1)
$ 312 $ 221
Unit Rate per BOE (2)
$ 14.60 $ 11.81



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
DD&A Expense (millions) ⁽¹⁾	$	325	$	211	$	619	$	404
Unit Rate per BOE ⁽²⁾	$	16.37	$	11.80	$	15.26	$	11.38


⁽¹⁾	For DD&A expense by geographical area, see Item 1. Financial Statements – Note ~~11.~~12. Segment Information.


⁽²⁾	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

Total DD&A expense for the second quarter and first ~~three~~six months of 2012 increased as compared with 2011 due to the following:

●

~~an increase of approximately $33 million due primarily to~~ higher sales volumes in the DJ Basin onshore US and the addition of DD&A expense related to the Marcellus Shale joint venture;

●

~~an increase of approximately $61 million due to the startup of the Aseng field which includes the Aseng FPSO in its depreciation base; and~~

the start up of Galapagos and South Raton in the deepwater Gulf of Mexico;

●

~~the impact of negative reserves revisions at December 31, 2011, due to revised performance expectations in the North Sea and China;~~

the startup of the Aseng field which includes the Aseng FPSO in its depreciation base;

partially offset by:

●

~~lower sales volumes in non-core onshore US and deepwater Gulf of Mexico areas resulting from natural field decline; and~~

●

~~lower North Sea sales volumes.~~

lower sales volumes in non-core onshore US and deepwater Gulf of Mexico areas resulting from natural field decline.

Changes in the unit rate per BOE for the second quarter and first ~~three~~six months of 2012 as compared with 2011 were due to changes in the mix of production, primarily due to volumes from the start-up of the Aseng field, which has a higher DD&A rate.

~~Table of Contents~~

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
G&A Expense (millions)	$	96	$	82	$	193	$	164
Unit Rate per BOE ⁽¹⁾	$	4.84	$	4.57	$	4.77	$	4.61

Three Months Ended
March 31,

2012 2011
G&A Expense (millions) $ 98 $ 83
Unit Rate per BOE (1)
$ 4.60 $ 4.43


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

G&A expense for the second quarter and first ~~three~~six months of 2012 increased as compared with 2011 primarily due to additional expenses relating to personnel, office, and information technology costs in support of our major development projects and increased exploration activities.

Asset Impairment Expense Asset impairment expense was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
(millions)
Asset Impairments	$	73	$	131	$	73	$	137

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

Table of Contents

Other Operating (Income) Expense, Net Other operating (income) expense, net was as follows:


	Three Months Ended March 31,				Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		2012			2011			2012			2011
(millions)
Deepwater Gulf of Mexico Moratorium Expense	$	-	$	18	$	—		$	1		$	—		$	19
Electricity Generation Expense		-		17	—			9			—			26
Gain on Divestitures					(9		)	(25		)	(9		)	(26		)
Other, Net		12		1	7			4			19			(1		)
Total	$	12	$	36	$	(2	)	$	(11	)	$	10		$	18

See Item 1. Financial Statements – Note 2. Basis of Presentation.

Other (Income) Expense

Other (income) expense was as follows:


	Three Months Ended March 31,					Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011		2012			2011			2012			2011
(millions)
Loss on Commodity Derivative Instruments	$	96		$	286
(Gain) Loss on Commodity Derivative Instruments						$	(276	)	$	(143	)	$	(180	)	$	143
Interest, Net of Amount Capitalized		32			16	27			21			59			37
Other Non-Operating (Income) Expense, Net		(1	)		8	(3		)	(9		)	(3		)	—
Total	$	127		$	310	$	(252	)	$	(131	)	$	(124	)	$	180

(Gain) Loss on Commodity Derivative Instruments ~~Loss~~(Gain) loss on commodity derivative instruments is a result of mark-to-market accounting. See Item 1. Financial Statements – Note 5.6. Derivative Instruments and Hedging Activities and Note 6.7. Fair Value Measurements and Disclosures.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
(millions, except unit rate)
Interest Expense	$	69		$	49		$	138		$	90
Capitalized Interest	(42		)	(28		)	(79		)	(53		)
Interest Expense, Net	$	27		$	21		$	59		$	37
Unit Rate per BOE ⁽¹⁾	$	1.35		$	1.19		$	1.44		$	1.05

Three Months Ended
March 31,

2012 2011
(millions, except unit rate)
Interest Expense $ 69 $ 41
Capitalized Interest (37 ) (25 )
Interest Expense, Net $ 32 $ 16
Unit Rate per BOE (1)
$ 1.49 $ 0.86


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

Interest expense prior to the reduction for capitalized interest increased for the second quarter and first ~~three~~six months of 2012 as compared with ~~2011.~~2011. The increase mainly resulted from our ~~November~~December 2011 debt issuance, an additional month of interest for our February 2011 debt issuance and interest related to our Aseng FPSO lease obligation.

The increase in capitalized interest is mainly due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and offshore Israel.

Other Non-Operating (Income) Expense, Net Other non-operating (income) expense, net includes deferred compensation (income) expense, interest income, transaction (gains) losses, and other (income) expense. See Item 1. Financial Statements – Note 2. Basis of ~~Presentation~~.Presentation.

Table of Contents

Income Tax Provision

See Item 1. Financial Statements – Note ~~10.~~11. Income Taxes for a discussion of the change in our effective tax rate for the second quarter and first ~~three~~six months of 2012 as compared with ~~2011.~~2011.

Discontinued Operations

Summarized results of discontinued operations were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
millions
Oil and Gas Sales	$	65	$	112	$	140	$	225
Less:
Production Expense	11		18		25		32
DD&A Expense	14		24		32		52
Other Operating (Income) Expense, Net	1		1		4		4
Income Before Income Taxes	39		69		79		137
Income Tax Expense	22		44		47		64
Income From Discontinued Operations	$	17	$	25	$	32	$	73

Key Statistics:
Daily Production
Crude Oil & Condensate (MBbl/d)	6		10		6		10
Natural Gas (MMcf/d)	4		6		5		7
Average Realized Price
Crude Oil & Condensate (Per Bbl)	$	109.66	$	119.61	$	116.14	$	112.47
Natural Gas (Per Mcf)	8.84		8.28		8.29		7.74

Our long-term debt is recorded at the consolidated level and is not reflected by each component. Thus, we have not allocated interest expense to discontinued operations.

See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

In seeking to effectively fund and monetize our major development projects, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the commodity price cycle. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects while also maintaining the capability to execute a robust exploration program and financially attractive periodic mergers and acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives. We also utilize a commodity price hedging program to reduce the impacts of commodity price ~~uncertainty~~volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and operations.

Our current line-up of major development projects, as well as our planned exploration and appraisal drilling activities, may result in capital expenditures exceeding cash flows from operating activities during the near term. However, we expect that new incremental production from our current projects, some of which are expected to commence as early as 2013, combined with higher production resulting from our Horizontal Niobrara and Marcellus Shale development programs, will result in a substantial increase in cash flows from operating activities. We believe we are well-positioned to fund these long-term growth plans. See Available Liquidity, below.

Table of Contents

In addition, we are currently evaluating potential development scenarios for our significant natural gas discoveries offshore Eastern Mediterranean, including Leviathan and Cyprus Block 12. The magnitude of these discoveries presents financial and technical challenges for us due to the large-scale development requirements. Potential development scenarios include the construction of LNG terminals, floating LNG, subsea pipeline or other options. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. As a result, we will likely seek partners to provide technical and financial support as well as midstream and downstream expertise.

Traditional sources of our liquidity are cash on hand, cash flows from operations, ~~and~~ available borrowing capacity under our credit ~~facility. Occasional~~facility, and proceeds from sales of ~~non-strategic crude oil and natural gas~~non-core properties, ~~as well~~such as our ~~periodic~~pending sales of certain North Sea and onshore US properties. We may also access to debt ~~and~~and/or capital markets ~~may~~for additional financing, such as an issuance of long-term debt, for our large development projects. We also ~~provide cash~~have the option to ~~support opportunities.~~increase our Credit Facility's overall commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders.

Our financial capacity, coupled with our balanced and diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity.

Available Liquidity Information regarding cash and debt balances was as follows:

March 31, December 31,
2012 2011
(millions, except percentages)
Cash and Cash Equivalents $ 1,143 $ 1,455
Amount Available to be Borrowed Under Credit Facility (1)
3,000 3,000
Total Liquidity $ 4,143 $ 4,455

Total Debt (2)
$ 4,484 $ 4,495
Total Shareholders' Equity 7,533 7,265
Ratio of Debt-to-Book Capital (3)
37 % 38 %



	June 30,			December 31,
	2012			2011
(millions, except percentages)
Cash and Cash Equivalents	$	702		$	1,455
Amount Available to be Borrowed Under Credit Facility ⁽¹⁾	3,000			3,000
Total Liquidity	$	3,702		$	4,455
Total Debt ⁽²⁾	$	4,473		$	4,495
Total Shareholders' Equity	7,805			7,265
Ratio of Debt-to-Book Capital ⁽³⁾	36		%	38		%


⁽¹⁾	See Credit Facility below.

~~(2)~~
⁽²⁾	Total debt includes Aseng FPSO lease obligation and remaining CONSOL installment payments and excludes unamortized debt ~~discount~~.discount.


⁽³⁾	We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.

Cash and Cash Equivalents We had approximately ~~$1.1 billion~~$702 million in cash and cash equivalents at ~~March 31,~~June 30, 2012, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately ~~$760~~$630 million of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if ~~repatriated~~.repatriated. We currently expect to use a significant amount of cash during 2012 to fund international projects, including the planned developments in West Africa and the Eastern Mediterranean.

Credit Facility We have an unsecured revolving credit facility that matures on October 14, 2016. The commitment is ~~$3.0~~$3.0 billion through the maturity date of the credit facility. See Financing Activities – Long-Term Debt below.

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

Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of ~~March 31,~~June 30, 2012, the fair value of our commodity derivative assets was ~~$39~~$170 million and the fair value of our commodity derivative liabilities was ~~$148~~$2 million (after consideration of netting agreements). See Item 1. Financial Statements – Note 5.6. Derivative Instruments and Hedging Activities for a discussion of derivative counterparty credit risk and Note 6.7. Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of derivative instruments.

Table of Contents

European Debt Crisis The European debt crisis ~~is ongoing and~~ continues to have a negative impact on the European economy, with risks to the global ~~banking~~financial system and overall global ~~economy and financial system. During the first quarter of~~economy. On June 21, 2012, Moody's Investors Service ~~announced rating actions affecting numerous financial institutions, and~~downgraded the credit ratings of ~~a number~~many international banks due to their exposure to the continuing European debt crisis which is causing extreme volatility and weakening of ~~European~~the global financial markets. Many of the banks ~~were placed on review for downgrade.~~

~~Some of~~receiving credit rating downgrades are counterparties in our commodity ~~derivatives counterparties,~~hedging program, as well as ~~some of our~~ lenders in our ~~$3.0~~$3.0 billion Credit ~~Facility, are international banks. These institutions could potentially be affected by the European debt crisis and be unable to participate in our drawdowns. In addition,~~Facility. Further credit downgrades of these institutions could result in a change in our counterparties with whom we execute hedging transactions according to our internal risk guidelines.

We In addition, with continued Eurozone instability, some of our Credit Facility banks more stressed by the crisis may be reluctant to increase their lending commitments to us should we desire to expand our Credit Facility capacity. At this time, we believe our current balance sheet and financial flexibility enhance our ability to react to Eurozone events as they unfold.

Counterparty Credit Risk ~~Accounts Receivable~~ ~~Some~~We monitor the creditworthiness of our ~~purchasers and~~trade creditors, joint venture partners, hedging counterparties, and financial institutions on an ongoing basis. Some of these entities are not as creditworthy as we are and may experience credit downgrades, as noted above, or liquidity problems. ~~For example, Standard & Poor’s Ratings Services recently placed IEC’s credit rating on CreditWatch negative.~~

~~Counterparty~~Credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales or reimbursement of joint venture costs.

The current uncertain economic and commodity price environment increases the risk of a sudden negative change in liquidity, which could impair a party's ability to perform under the terms of a contract. We are unable to predict sudden changes in a party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these risks may be limited and we could incur significant financial losses.

In addition, nonoperating partners often must obtain financing for their share of capital cost for development projects. For example, our Eastern Mediterranean partners must obtain financing for their share of significant development expenditures at Tamar and Leviathan, which potentially includes an LNG project and/or major underwater pipeline. A ~~partner’s~~partner's inability to obtain financing could result in a delay of one of our joint development projects.

Credit enhancements have been obtained from some parties in the ~~way~~form of parental guarantees or letters of ~~credit, including our largest crude oil purchaser;~~credit; however, not all of our ~~trade~~counterparty credit is protected through guarantees or credit support. Nonperformance by a trade creditor, or joint venture partner, hedging counterparty or financial institution could result in significant financial losses.

Contractual Obligations

CONSOL Carried Cost ObligationThe CONSOL Carried Cost Obligation represents our agreement to fund up to approximately $2.1 billion of CONSOL’s future drilling and completion costs. The CONSOL Carried Cost Obligation is expected to extend over approximately eight ~~years or more.~~years. It is capped at $400 million in each calendar year and is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Therefore, specific payment dates for the funding of the CONSOL Carried Cost Obligation cannot be determined at this time. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices. Based on the ~~March 31,~~June 30, 2012 Henry Hub natural gas price curve, we forecast our CONSOL Carried Cost Obligation will beremain suspended ~~throughout~~for the ~~remainder of the 2012 fiscal year.~~next 12 months.

Cash Flows

Cash flow information is as follows:


	Three Months Ended March 31						Six Months Ended June 30,
	2012			2011			2012			2011
(millions)
Total Cash Provided By (Used in)
Operating Activities	$	741		$	484		$	1,247		$	1,229
Investing Activities		(1,032	)		(575	)	(1,925		)	(1,184		)
Financing Activities		(21	)		429		(75		)	401
Increase (Decrease) in Cash and Cash Equivalents	$	(312	)	$	338		$	(753	)	$	446

Operating Activities Net cash provided by operating activities for the first ~~three~~six months of 2012 ~~increased~~ remained flat as compared with 2011 ~~primarily due to higher revenues, which benefitted from increases in crude oil prices and production. The increase in cash flow was partially~~. Higher liquids sales volumes were offset by ~~lower~~decreases in natural gas sales volumes and prices and increases in production expenses, general and administrative expense and interest expense. See Item 1. Financial Statements – Consolidated Statements

Table of Contents

of Cash Flows.

Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions. Capital spending for property, plant and equipment increased by ~~$440~~$639 million during the first ~~three~~six months of 2012 as compared with 2011, primarily due to increased major project development activity in the Wattenberg area, the Marcellus Shale, offshore West Africa, and offshore Israel. We also invested ~~$14~~$35 million in CONE during the first ~~quarter 2012.~~six months of 2012. In addition, we received $10 million proceeds from US onshore divestitures during the first six months of 2012 as compared with $77 million proceeds, $73 million of which related to our transfer of Ecuador assets to the government of Ecuador, during the first six months of 2011.

~~Table of Contents~~

Financing Activities Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first ~~three~~six months of 2012, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($39 million). We used cash to pay dividends on our common stock ~~($39 million)~~($79 million), make principal payments related to the Aseng FPSO capital lease obligation ~~($8 million)~~($22 million) and repurchase shares of our common stock ($($13 ~~million)~~million).

In comparison, during the first ~~three~~six months of 2011, funds were provided by net cash proceeds from borrowings under our revolving credit facility ($($120 ~~million)~~million) and the issuance of 6% senior notes due 2041 ($($836 ~~million)~~million). Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ~~($31 million)~~($35 million). We used a portion of the proceeds from the issuance of senior notes to repay amounts outstanding under our credit facility ($($470 ~~million)~~million). We also used cash to settle an interest rate lock ($($40 ~~million)~~million), pay dividends on our common stock ~~($32 million)~~($64 million) and repurchase shares of our common stock ($($16 ~~million)~~million).

See Item 1. Financial Statements – Consolidated Statements of Cash Flows.

Investing Activities

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


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011		2012		2011
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition	$	73	$	15	$	14	$	42	$	87	$	57
Exploration		129		122	92		106		221		228
Development		735		374	719		500		1,454		874
Corporate and Other		12		34	13		54		25		88
Total	$	949	$	545	$	838	$	702	$	1,787	$	1,247
Other
Investment in Equity Method Investee	$	14	$	-	$	21	$	—	$	35	$	—
Increase in FPSO Lease Obligation		-		34	—		17		—		51

2012 Unproved property acquisition costs ~~were mainly~~primarily related to an acquisition that strengthened our position in the DJ Basin along with other miscellaneous onshore US lease acquisitions. The increase in development costs is due to increased capital spending on major development projects located in the DJ Basin, Marcellus Shale, offshore Equatorial Guinea and offshore Israel.

2011 Unproved property acquisition costs for the first ~~three~~six months of 2011 related to onshore US lease acquisitions.

~~See Item 1. Financial Statements – Note 3. Acquisitions.~~

Financing Activities

Long-Term Debt Our principal source of liquidity is an unsecured revolving credit facility that matures October 14, 2016. We did not engage in any activities under the Credit Facility, or other short-term borrowing arrangements during the first ~~quarter~~six months of ~~2012.~~2012.

Table of Contents

The Credit Facility (i) provides for an initial commitment of ~~$3.0~~$3.0 billion with an option to increase the overall commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, (ii) will mature on October 14, 2016, (iii) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (iv) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (v) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.

At ~~March 31,~~June 30, 2012, there were no borrowings outstanding under the Credit Facility, leaving ~~$3.0~~$3.0 billion available for use. We expect to use the Credit Facility to fund our capital investment program, and we periodically borrow amounts under provision (iv) above for working capital purposes. See Item 1. Financial Statements – Note 4.5. Debt.

Our outstanding fixed-rate debt, ~~including~~excluding the ~~remaining CONSOL installment payments,~~Aseng FPSO lease obligation and unamortized debt discount, totaled ~~almost $4.1~~approximately $4.1 billion at ~~March 31, 2012.~~June 30, 2012. The weighted average interest rate on fixed-rate debt was ~~5.56%~~5.57%, with maturities ranging from 2012 to 2097. Approximately 21% of our fixed rate debt will mature within the next five years.

~~Table of Contents~~

Our ratio of debt-to-book capital was 37% at March 31, 2012 as compared with 38% at December 31, 2011. 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.

Dividends We paid total cash dividends of 2244 cents per share of our common stock during the first ~~three~~six months of 2012 and 1836 cents per share during the first ~~three~~six months of ~~2011.~~2011. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

Exercise of Stock Options We received cash proceeds from the exercise of stock options of ~~$27~~$26 million during the first ~~three~~six months of 2012 and ~~$23~~$26 million during the first ~~three~~six months of ~~2011.~~2011.

Common Stock Repurchases We receive shares of common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received ~~131,868~~132,484 shares with a value of ~~$13~~$13 million during the first ~~three~~six months of 2012 and ~~178,499~~180,538 shares with a value of ~~$16~~$16 million during the first ~~three~~six months of ~~2011.~~ 2011.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

~~Table of Contents~~

Commodity Price Risk

~~Item 3.~~

~~Quantitative and Qualitative Disclosures About Market Risk~~

~~Commodity Price Risk~~

Derivative Instruments Held for Non-Trading Purposes We are ~~are~~ exposed to market risk in the normal course of business operations, and the ~~uncertainty~~volatility 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,~~June 30, 2012, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude oil and natural gas sales. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net ~~payable~~receivable position with a fair value of ~~$109 million.~~$168 million. Based on the ~~March 31,~~June 30, 2012 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would ~~increase~~decrease the fair value of our net commodity derivative ~~payable~~receivable by approximately ~~$20~~$19 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would ~~increase~~decrease the fair value of our net commodity derivative ~~payable~~receivable by approximately $5$4 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 5.6. Derivative Instruments and Hedging Activities.

Interest Rate Risk

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

At ~~March 31,~~June 30, 2012, we had approximately ~~$4.1~~$4.1 billion (excluding the Aseng FPSO lease obligation and unamortized debt discount) of long-term debt outstanding. All debt outstanding was fixed-rate debt with a weighted average interest rate of ~~5.56%~~5.57%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss. See Item 1. Financial Statements – Note 4.5. Debt.

We occasionally enter into interest rate derivative instruments such as forward contracts or swap agreements to hedge exposure

Table of Contents

to interest rate risk. Changes in fair value of interest rate derivative instruments used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At ~~March 31,~~June 30, 2012, AOCL included ~~$26~~$26 million, net of tax, related to interest rate derivative instruments. This amount is currently being reclassified to earnings as adjustments to interest expense over the terms of our

5¼% senior notes due April 15, 2014 and 6% senior notes due March 1, 2041. See Item 1. Financial Statements – Note 5.6. Derivative Instruments and Hedging Activities.

We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of ~~March 31,~~June 30, 2012, our cash and cash equivalents totaled approximately ~~$1.1 billion,~~$702 million, approximately ~~83%~~59% of which was invested in money market funds and short-term investments with major financial institutions. A hypothetical 25 basis point change in the floating interest rates applicable to the amount invested as of ~~March 31,~~June 30, 2012 would result in a change in annual interest income of approximately $2$1 million.

Foreign Currency Risk

The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as foreign deferred tax liabilities in certain foreign tax jurisdictions, are denominated in a foreign currency. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative, and tax liabilities. This risk may be mitigated to the extent commodity prices increase in response to a devaluation of the US dollar.

~~Transaction gains or~~Net transaction losses were ~~not material~~$9 million for the second quarter of 2012 and $6 million for the six months ended June 30, 2012, and were de minimis for 2011. The losses were primarily related to the changes in ~~any of~~exchange rates between the ~~periods presented~~US dollar and Israeli new shekel. Transaction (gains) losses are included in other (income) expense, net in the consolidated statements of operations.

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

~~Table of Contents~~

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;

●

the impact of governmental fiscal terms and/or regulation, such as that involving the protection of the environment or marketing of production, as well as other regulations; and

●

access to resources.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included herein, if any, and included in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, and our Annual Report on Form 10-K for the year ended December 31, 2011, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2011 is available on our

Table of Contents

website at www.nobleenergyinc.com.

Item 4.

Controls and Procedures

Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, are effective. There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

COGCC ~~Item 1.~~

~~Legal Proceedings~~

See Item 1. Financial Statements –Note ~~12.~~13. Commitments and Contingencies.

~~Item 1A.~~

Item 1A. Risk Factors

~~Risk Factors~~

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 or Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, ~~2011.~~2011.

~~Table of Contents~~

~~Item 2.~~

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

The following table sets forth, for the periods indicated, the Company’s share repurchase activity:



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(in thousands)
04/01/2012 - 04/30/2012	295	$	94.26	—	—
05/01/2012 - 05/31/2012	219	97.04		—	—
06/01/2012 - 06/30/2012	102	81.63		—	—
Total	616	$	93.16	—	—

Period
Total Number of
Shares
Purchased (1)

Average
Price Paid
Per Share

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs

Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs

(in thousands)
01/01/12 - 01/31/12 68,223 $ 100.13 - -
02/01/12 - 02/29/12 57,994 101.25 - -
03/01/12 - 03/31/12 5,651 99.74 - -
Total 131,868 $ 100.61 - -


⁽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

~~Item 3.~~

~~Defaults Upon Senior Securities~~

None.

~~Item 4.~~

~~Mine Safety Disclosures~~

Item 4. Mine Safety Disclosures

Not applicable.

~~Item 5.~~

~~Other Information~~

Item 5. Other Information

Table of Contents

None.

~~Item 6.~~

~~Exhibits~~

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.

Table of Contents

Signatures

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



			NOBLE ENERGY, INC.
			(Registrant)

Date	~~April~~	July 26, 2012	/s/ Kenneth M. Fisher
			Kenneth M. Fisher Senior Vice President, Chief Financial Officer

Table of Contents

Index to Exhibits

~~Exhibit~~

Exhibit Number		Exhibit

3.1		Certificate of Incorporation asof the Registrant (as amended through May ~~16, 2005, of the Registrant (filed as Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference).~~25, 2012), filed herewith.

3.2		By-Laws of Noble Energy, Inc. as amended through June 1, 2009 (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 17, 2009) filed February 20, 2009 and incorporated herein by reference).

~~10.1~~		Gas Sale and Purchase Agreement dated March 14, 2012, by and between Noble Energy Mediterranean Ltd. and Isramco Negev 2 Limited Partnership, Delek Drilling Limited Partnership, Avner Oil Exploration Limited Partnership, and Dor Gas Exploration Limited Partnership (Sellers) and The Israel Electric Corporation Limited (Purchaser), filed herewith. (1)

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.LAB		XBRL Label Linkbase Document

101.PRE		XBRL Presentation Linkbase Document

101.DEF		XBRL Definition Linkbase Document

~~(1)~~

~~Pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission.~~



Delaware		73-0785597
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)
100 Glenborough Drive, Suite 100
Houston, Texas		77067
(Address of principal executive offices)		(Zip Code)
(281) 872-3100 (Registrant’s telephone number, including area code)



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

	Common Stock		Additional Paid in Capital			Acumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Total Shareholders' Equity
December 31, 2011	$	656	$	2,497		$	(100	)	$	(638	)	$	4,850		$	7,265
Net Income		-		-			-			-			263			263
Stock-based Compensation		-		16			-			-			-			16
Exercise of Stock Options		2		25			-			-			-			27
Tax Benefits Related to Exercise of Stock Options		-		12			-			-			-			12
Restricted Stock Awards, Net		1		(1	)		-			-			-			-
Dividends (22 cents per share)		-		-			-			-			(39	)		(39	)
Changes in Treasury Stock, Net		-		-			-			(13	)		-			(13	)
Net Change in Other		-		-			2			-			-			2
March 31, 2012	$	659	$	2,549		$	(98	)	$	(651	)	$	5,074		$	7,533

December 31, 2010	$	651	$	2,385		$	(104	)	$	(624	)	$	4,540		$	6,848
Net Income		-		-			-			-			14			14
Stock-based Compensation		-		14			-			-			-			14
Exercise of Stock Options		2		21			-			-			-			23
Tax Benefits Related to Exercise of Stock Options		-		8			-			-			-			8
Restricted Stock Awards, Net		1		(1	)		-			-			-			-
Dividends (18 cents per share)		-		-			-			-			(32	)		(32	)
Changes in Treasury Stock, Net		-		-			-			(16	)		-			(16	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		-			15			-			-			15
Net Change in Other		-		-			2			-			-			2
March 31, 2011	$	654	$	2,427		$	(87	)	$	(640	)	$	4,522		$	6,876



Part I. Financial Information	3

Item 1. Financial Statements	3

Consolidated Statements of Operations	3

Consolidated Statements of Comprehensive Income	4

Consolidated Balance Sheets	5

Consolidated Statements of Cash Flows	6

Consolidated Statements of Shareholders' Equity	7

Notes to Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19 26

Item 3. Quantitative and Qualitative Disclosures About Market Risk	35 48

Item 4. Controls and Procedures	36 50

Part II. Other Information	36 50

Item 1. Legal Proceedings	36 50

Item 1A. Risk Factors	36 50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37 50

Item 3. Defaults Upon Senior Securities	37 50

Item 4. Mine Safety Disclosures	37 50

Item 5. Other Information	37 50

Item 6. Exhibits	37 51

Signatures	37 52

Index to Exhibits	38 53



	June 30, 2012			December 31, 2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	702		$	1,455
Accounts Receivable, Net	824			783
Other Current Assets	368			180
Assets Held for Sale	324			—
Total Current Assets	2,218			2,418
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	18,440			17,703
Property, Plant and Equipment, Other	322			294
Total Property, Plant and Equipment, Gross	18,762			17,997
Accumulated Depreciation, Depletion and Amortization	(5,337		)	(5,215		)
Total Property, Plant and Equipment, Net	13,425			12,782
Goodwill	696			696
Other Noncurrent Assets	642			548
Total Assets	$	16,981		$	16,444
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	1,279		$	1,343
Other Current Liabilities	1,060			925
Total Current Liabilities	2,339			2,268
Long-Term Debt	4,074			4,100
Deferred Income Taxes, Noncurrent	2,080			2,059
Other Noncurrent Liabilities	683			752
Total Liabilities	9,176			9,179
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued	—			—
Common Stock - Par Value $0.01 and $3.33 1/3 per share; 500 Million and 250 Million Shares Authorized; 198 Million and 197 Million Shares Issued, Respectively	2			656
Additional Paid in Capital	3,224			2,497
Accumulated Other Comprehensive Loss	(97		)	(100		)
Treasury Stock, at Cost; 19 Million Shares	(651		)	(638		)
Retained Earnings	5,327			4,850
Total Shareholders’ Equity	7,805			7,265
Total Liabilities and Shareholders’ Equity	$	16,981		$	16,444



	Common Stock			Additional Paid in Capital			Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Total Shareholders' Equity
December 31, 2011	$	656		$	2,497		$	(100	)	$	(638	)	$	4,850		$	7,265
Net Income	—			—			—			—			556			556
Stock-based Compensation	—			34			—			—			—			34
Exercise of Stock Options	—			26			—			—			—			26
Tax Benefits Related to Exercise of Stock Options	—			13			—			—			—			13
Dividends (44 cents per share)	—			—			—			—			(79		)	(79		)
Changes in Treasury Stock, Net	—			—			—			(13		)	—			(13		)
Change in Par Value	(654		)	654						—			—			—
Net Change in Other	—			—			3			—			—			3
June 30, 2012	$	2		$	3,224		$	(97	)	$	(651	)	$	5,327		$	7,805

December 31, 2010	$	651		$	2,385		$	(104	)	$	(624	)	$	4,540		$	6,848
Net Income	—			—			—			—			308			308
Stock-based Compensation	—			29			—			—			—			29
Exercise of Stock Options	2			24			—			—			—			26
Tax Benefits Related to Exercise of Stock Options	—			9			—			—			—			9
Dividends (36 cents per share)	—			—			—			—			(64		)	(64		)
Changes in Treasury Stock, Net	—			—			—			(16		)	—			(16		)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value	—			—			15			—			—			15
Net Change in Other	1			(1		)	3			—			—			3
June 30, 2011	$	654		$	2,446		$	(86	)	$	(640	)	$	4,784		$	7,158


⁽²⁾	Amount relates to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of ~~Mexico in 2011.~~Mexico.


⁽³⁾	Amounts represent increases (decreases) in the fair value of shares of our common stock held in a rabbi trust.

					Increase
					(Decrease)
	2012		2011		from Prior Year
(millions)
Three Months Ended March 31,
Oil, Gas and NGL Sales	$	1,112	$	830		34	%
Income from Equity Method Investees		53		48		10	%
Other Revenues		-		21		(100	%)
Total	$	1,165	$	899		30	%


	Sales Revenues										Sales Revenues
	Crude Oil & Condensate		Natural Gas			NGLs			Total		Crude Oil & Condensate			Natural Gas			NGLs			Total
(millions)
Three Months Ended March 31, 2011	$	569	$	203		$	58		$	830
Three Months Ended June 30, 2011											$	490		$	226		$	67		$	783
Changes due to
Increase in Sales Volumes		211		2			16			229
Increase (Decrease) in Sales Volumes											323			(23		)	5			305
(Decrease) in Sales Prices											(44		)	(86		)	(24		)	(154		)
Three Months Ended June 30, 2012											$	769		$	117		$	48		$	934

Six Months Ended June 30, 2011											$	951		$	425		$	124		$	1,500
Changes due to
Increase (Decrease) in Sales Volumes											568			(19		)	20			569
Increase (Decrease) in Sales Prices		110		(48	)		(9	)		53	69			(136		)	(32		)	(99		)
Three Months Ended March 31, 2012	$	890	$	157		$	65		$	1,112
Six Months Ended June 30, 2012											$	1,588		$	270		$	112		$	1,970

	Three Months Ended				Increase
	March 31,				(Decrease)
	2012		2011		from Prior Year
(millions)
Production Expense	$	179	$	142		26	%
Exploration Expense		63		70		(10	%)
Depreciation, Depletion and Amortization		312		221		41	%
General and Administrative		98		83		18	%
Other Operating (Income) Expense, Net		12		36		(67	%)
Total	$	664	$	552		20	%

	Total per BOE (1)		Total		United States		Equatorial Guinea		Israel		North Sea		Other Int'l, Corporate
(millions, except unit rate)
Three Months Ended March 31, 2012
Lease Operating Expense (2)	$	5.53	$	118	$	71	$	23	$	4	$	13		$	7
Production and Ad Valorem Taxes		1.76		38		26		-		-		-			12
Transportation and Gathering Expense		1.10		23		21		-		-		1			1
Total Production Expense	$	8.39	$	179	$	118	$	23	$	4	$	14		$	20
Three Months Ended March 31, 2011
Lease Operating Expense (2)	$	4.89	$	92	$	62	$	9	$	3	$	12		$	6
Production and Ad Valorem Taxes		1.71		32		25		-		-		-			7
Transportation and Gathering Expense		0.94		18		16		-		-		2			-
Total Production Expense	$	7.54	$	142	$	103	$	9	$	3	$	14		$	13



	Total per BOE ⁽¹⁾		Total		United States		Equatorial Guinea		Israel		Other Int'l, Corporate
(millions, except unit rate)
Three Months Ended June 30, 2012
Lease Operating Expense ⁽²⁾	$	5.02	$	100	$	68	$	20	$	3	$	9
Production and Ad Valorem Taxes	2.21		44		33		—		—		11
Transportation and Gathering Expense	1.27		25		24		—		—		1
Total Production Expense	$	8.50	$	169	$	125	$	20	$	3	$	21
Three Months Ended June 30, 2011
Lease Operating Expense ⁽²⁾	$	4.67	$	83	$	60	$	14	$	4	$	5
Production and Ad Valorem Taxes	2.10		39		28		—		—		11
Transportation and Gathering Expense	0.88		15		14		—		—		1
Total Production Expense	$	7.65	$	137	$	102	$	14	$	4	$	17

Six Months Ended June 30, 2012
Lease Operating Expense ⁽²⁾	$	5.07	$	205	$	139	$	43	$	7	$	16
Production and Ad Valorem Taxes	2.01		81		59		—		—		22
Transportation and Gathering Expense	1.16		48		45		—		—		3
Total Production Expense	$	8.24	$	334	$	243	$	43	$	7	$	41
Six Months Ended June 30, 2011
Lease Operating Expense ⁽²⁾	$	4.61	$	163	$	122	$	23	$	7	$	11
Production and Ad Valorem Taxes	1.96		70		52		—		—		18
Transportation and Gathering Expense	0.87		31		30		—		—		1
Total Production Expense	$	7.44	$	264	$	204	$	23	$	7	$	30


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

	Total		United States		West Africa (1)		Eastern Mediter-ranean (2)		North Sea		Other Int'l, Corporate (3)
(millions)
Three Months Ended March 31, 2012
Dry Hole Cost	$	1	$	-	$	1	$	-	$	-	$	-
Seismic		28		26		-		-		-		2
Exploration Expense		27		4		2		1		3		17
Other		7		6		1		-		-		-
Total Exploration Expense	$	63	$	36	$	4	$	1	$	3	$	19
Three Months Ended March 31, 2011
Dry Hole Cost	$	22	$	22	$	-	$	-	$	-	$	-
Seismic		26		16		-		-		-		10
Exploration Expense		18		5		1		-		-		12
Other		4		4		-		-		-		-
Total Exploration Expense	$	70	$	47	$	1	$	-	$	-	$	22



	Total		United States			West Africa ⁽¹⁾		Eastern Mediterranean ⁽²⁾		Other Int'l, Corporate ⁽³⁾
(millions)
Three Months Ended June 30, 2012
Dry Hole Cost	$	117	$	116		$	1	$	—	$	—
Seismic	17		13			—		—		4
Exploration Expense	28		4			2		1		21
Other	5		4			—		—		1
Total Exploration Expense	$	167	$	137		$	3	$	1	$	26
Three Months Ended June 30, 2011
Dry Hole Cost	$	23	$	(2	)	$	25	$	—	$	—
Seismic	13		7			1		3		2
Exploration Expense	24		7			2		—		15
Other	7		7			—		—		—
Total Exploration Expense	$	67	$	19		$	28	$	3	$	17

Six Months Ended June 30, 2012
Dry Hole Cost	$	118	$	116		$	2	$	—	$	—
Seismic	46		39			—		—		7
Exploration Expense	52		8			4		2		38
Other	11		10			1		—		—
Total Exploration Expense	$	227	$	173		$	7	$	2	$	45
Six Months Ended June 30, 2011
Dry Hole Cost	$	45	$	20		$	25	$	—	$	—
Seismic	39		23			1		3		12
Exploration Expense	42		12			3		—		27
Other	11		11			—		—		—
Total Exploration Expense	$	137	$	66		$	29	$	3	$	39


⁽¹⁾	West Africa includes Equatorial Guinea, Cameroon, and Senegal/Guinea-Bissau.

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
							(in thousands)
01/01/12 - 01/31/12		68,223	$	100.13		-		-
02/01/12 - 02/29/12		57,994		101.25		-		-
03/01/12 - 03/31/12		5,651		99.74		-		-
Total		131,868	$	100.61		-		-