Edgar Filing: NOBLE ENERGY INC

NBL-2014.6.30-10Q

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)



Delaware		73-0785597
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)
1001 Noble Energy Way
Houston, Texas		77070
(Address of principal executive offices)		(Zip Code)
(281) 872-3100 (Registrant’s telephone number, including area code)

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

Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller

reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company”

in Rule 12b-2 of the Exchange Act.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No ý

As of June 30, 2014, there were 361,732,310 shares of the registrant’s common stock,

par value $0.01 per share, outstanding.

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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	23

Item 3. Quantitative and Qualitative Disclosures About Market Risk	41

Item 4. Controls and Procedures	42

Part II. Other Information	43

Item 1. Legal Proceedings	43

Item 1A. Risk Factors	43

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3. Defaults Upon Senior Securities	44

Item 4. Mine Safety Disclosures	44

Item 5. Other Information	44

Item 6. Exhibits	44

Signatures	45

Index to Exhibits	46

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Part I. Financial Information

Item 1. Financial Statements

Noble Energy, Inc.

Consolidated Statements of Operations

(millions, except per share amounts)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues
Oil, Gas and NGL Sales	$	1,338		$	1,112		$	2,665		$	2,196
Income from Equity Method Investees	45			37			97			96
Total	1,383			1,149			2,762			2,292
Costs and Expenses
Production Expense	248			210			481			398
Exploration Expense	59			90			133			151
Depreciation, Depletion and Amortization	413			368			837			734
General and Administrative	127			104			266			216
(Gain) Loss on Divestitures	(44		)	4			(42		)	(12		)
Asset Impairments	34			—			131			—
Other Operating Expense, Net	17			12			23			20
Total	854			788			1,829			1,507
Operating Income	529			361			933			785
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments	236			(161		)	311			(89		)
Interest, Net of Amount Capitalized	52			33			99			58
Other Non-Operating Expense, Net	8			3			13			12
Total	296			(125		)	423			(19		)
Income from Continuing Operations Before Income Taxes	233			486			510			804
Income Tax Provision	41			128			118			214
Income from Continuing Operations	192			358			392			590
Discontinued Operations, Net of Tax	—			19			—			49
Net Income	$	192		$	377		$	392		$	639

Earnings Per Share, Basic
Income from Continuing Operations	$	0.53		$	1.00		$	1.09		$	1.64
Discontinued Operations, Net of Tax	—			0.05			—			0.14
Net Income	$	0.53		$	1.05		$	1.09		$	1.78
Earnings Per Share, Diluted
Income from Continuing Operations	$	0.52		$	0.99		$	1.07		$	1.63
Discontinued Operations, Net of Tax	—			0.05			—			0.13
Net Income	$	0.52		$	1.04		$	1.07		$	1.76

Weighted Average Number of Shares Outstanding
Basic	361			359			361			358
Diluted	366			363			365			362

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

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Noble Energy, Inc.

Consolidated Statements of Comprehensive Income

(millions)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net Income	$	192		$	377		$	392		$	639
Other Items of Comprehensive Income
Net Change in Pension and Other	5			5			10			11
Less Tax Benefit	(1		)	(2		)	(4		)	(4		)
Other Comprehensive Income	4			3			6			7
Comprehensive Income	$	196		$	380		$	398		$	646

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

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Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)



	June 30, 2014			December 31, 2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	958		$	1,117
Accounts Receivable, Net	1,004			947
Other Current Assets	312			547
Total Current Assets	2,274			2,611
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	24,088			22,243
Property, Plant and Equipment, Other	600			517
Total Property, Plant and Equipment, Gross	24,688			22,760
Accumulated Depreciation, Depletion and Amortization	(7,712		)	(7,035		)
Total Property, Plant and Equipment, Net	16,976			15,725
Goodwill	621			627
Other Noncurrent Assets	704			679
Total Assets	$	20,575		$	19,642
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	1,369		$	1,354
Other Current Liabilities	866			988
Total Current Liabilities	2,235			2,342
Long-Term Debt	5,160			4,566
Deferred Income Taxes, Noncurrent	2,483			2,441
Other Noncurrent Liabilities	1,143			1,109
Total Liabilities	11,021			10,458
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 per share; 500 Million Shares Authorized; 402 Million and 400 Million Shares Issued, respectively	4			4
Additional Paid in Capital	3,566			3,463
Accumulated Other Comprehensive Loss	(111		)	(117		)
Treasury Stock, at Cost; 38 Million Shares	(674		)	(659		)
Retained Earnings	6,769			6,493
Total Shareholders’ Equity	9,554			9,184
Total Liabilities and Shareholders’ Equity	$	20,575		$	19,642

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

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Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)



	Six Months Ended June 30,
	2014			2013
Cash Flows From Operating Activities
Net Income	$	392		$	639
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	837			736
Asset Impairments	131			—
Dry Hole Cost	2			23
Deferred Income Taxes	24			108
Income from Equity Method Investees, Net of Dividends	(3		)	(18		)
(Gain) Loss on Commodity Derivative Instruments	311			(89		)
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	(83		)	9
Gain on Divestitures	(42		)	(67		)
Stock Based Compensation	45			38
Other Adjustments for Noncash Items Included in Income	38			33
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable	55			(193		)
Increase in Accounts Payable	126			131
Decrease in Current Income Taxes Payable	(86		)	(81		)
Increase (Decrease) in Other Current Liabilities	25			(33		)
Other Operating Assets and Liabilities, Net	(15		)	8
Net Cash Provided by Operating Activities	1,757			1,244
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(2,321		)	(1,929		)
Additions to Equity Method Investments	(40		)	(23		)
Proceeds from Divestitures	146			114
Other	—			3
Net Cash Used in Investing Activities	(2,215		)	(1,835		)
Cash Flows From Financing Activities
Exercise of Stock Options	41			31
Excess Tax Benefits from Stock-Based Awards	17			12
Dividends Paid, Common Stock	(116		)	(96		)
Purchase of Treasury Stock	(15		)	(14		)
Proceeds from Credit Facilities	600			—
Repayment of Senior Notes	(200		)	—
Repayment of Capital Lease Obligation	(28		)	(23		)
Net Cash Provided by (Used in) Financing Activities	299			(90		)
Decrease in Cash and Cash Equivalents	(159		)	(681		)
Cash and Cash Equivalents at Beginning of Period	1,117			1,387
Cash and Cash Equivalents at End of Period	$	958		$	706

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

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Noble Energy, Inc.

Consolidated Statements of Shareholders' Equity

(millions)

(unaudited)



	Common Stock ⁽¹⁾		Additional Paid in Capital ⁽¹⁾		Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Total Shareholders' Equity
December 31, 2013	$	4	$	3,463	$	(117	)	$	(659	)	$	6,493		$	9,184
Net Income	—		—		—			—			392			392
Stock-based Compensation	—		45		—			—			—			45
Exercise of Stock Options	—		41		—			—			—			41
Tax Benefits Related to Exercise of Stock Options	—		17		—			—			—			17
Dividends (32 cents per share)	—		—		—			—			(116		)	(116		)
Changes in Treasury Stock, Net	—		—		—			(15		)	—			(15		)
Net Change in Pension and Other	—		—		6			—			—			6
June 30, 2014	$	4	$	3,566	$	(111	)	$	(674	)	$	6,769		$	9,554

December 31, 2012	$	4	$	3,302	$	(113	)	$	(648	)	$	5,713		$	8,258
Net Income	—		—		—			—			639			639
Stock-based Compensation	—		38		—			—			—			38
Exercise of Stock Options	—		31		—			—			—			31
Tax Benefits Related to Exercise of Stock Options	—		12		—			—			—			12
Dividends (27 cents per share)	—		—		—			—			(96		)	(96		)
Changes in Treasury Stock, Net	—		—		—			(14		)	—			(14		)
Net Change in Pension and Other	—		—		7			—			—			7
June 30, 2013	$	4	$	3,383	$	(106	)	$	(662	)	$	6,256		$	8,875


⁽¹⁾	Amounts reflect impact of 2-for-1 stock split which occurred during the second quarter of 2013.

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

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 1. Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our core operating areas are onshore US, primarily in the DJ Basin and Marcellus Shale, in the deepwater Gulf of Mexico, offshore Eastern Mediterranean, and offshore West Africa.

Note 2. Basis of Presentation

Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at June 30, 2014 and December 31, 2013 and for the three and six months ended June 30, 2014 and 2013 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. Operating results for the three and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2013.

Consolidation Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. In addition, we use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.

Discontinued Operations In 2012, we initiated a strategy to exit the North Sea geographical area through sales of our non-operated working interests in the assets. The North Sea geographical segment was classified as held for sale and the operations were reflected as discontinued operations in 2012 and 2013.

The most significant North Sea assets were sold during 2012 and 2013. However, we have been unable to locate purchasers for the remaining assets, and a sale is no longer considered probable. Therefore, during first quarter 2014, we reclassified the remaining North Sea assets to held and used, and the North Sea geographical segment is included in continuing operations in first and second quarters 2014. In addition, we recorded impairments for the North Sea assets in both the first and second quarters of 2014. See Note 4. Asset Impairments.

North Sea revenues and operating expenses for the six months ended June 30, 2014, except for the impairments recorded in the first and second quarters 2014, were de minimis. See Note 3. Divestitures, Note 4. Asset Impairments, and Note 7. Fair Value Measurements and Disclosures.

Common Stock Split On April 22, 2013, Noble Energy’s Board of Directors approved a 2-for-1 split of its common stock to be effected in the form of a stock dividend. The stock dividend was distributed on May 28, 2013 to shareholders of record as of May 14, 2013. Earnings per share and common shares outstanding are reported giving retrospective effect to the common stock split.

Recently Issued Accounting Standards In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. We elected to early adopt ASU 2014-08 on a prospective basis, and the adoption did not have a material impact on our consolidated financial statements.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. We are

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

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



	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2014		2013		2014		2013
Production Expense
Lease Operating Expense	$	154	$	140	$	299	$	257
Production and Ad Valorem Taxes	53		43		102		86
Transportation and Gathering Expense	41		27		80		55
Total	$	248	$	210	$	481	$	398
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense ⁽¹⁾	$	8	$	3	$	12	$	14
Other (Income) Expense, Net	—		—		1		(2		)
Total	$	8	$	3	$	13	$	12


⁽¹⁾	Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Balance Sheet Information Other balance sheet information is as follows:



(millions)	June 30, 2014			December 31, 2013
Accounts Receivable, Net
Proceeds Receivable from China Asset Sale ⁽¹⁾	$	150		$	—
Commodity Sales	464			495
Joint Interest Billings	310			382
Other	91			81
Allowance for Doubtful Accounts	(11		)	(11		)
Total	$	1,004		$	947
Other Current Assets
Inventories, Materials and Supplies	$	94		$	96
Inventories, Crude Oil	23			25
Deferred Income Taxes, Net	63			62
Assets Held for Sale	74			292
Prepaid Expenses and Other Current Assets	58			72
Total	$	312		$	547
Other Noncurrent Assets
Equity Method Investments	$	484		$	437
Mutual Fund Investments	121			114
Commodity Derivative Assets	2			16
Other Assets	97			112
Total	$	704		$	679
Other Current Liabilities
Production and Ad Valorem Taxes	$	111		$	103
Commodity Derivative Liabilities	199			65
Income Taxes Payable	77			156
Asset Retirement Obligations	141			39
Interest Payable	61			63
Current Portion of Long Term Debt⁽²⁾	—			200
Current Portion of Capital Lease⁽²⁾	59			58
Liabilities Associated with Assets Held for Sale	14			111
Other	204			193
Total	$	866		$	988
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	276		$	253
Asset Retirement Obligations	563			547
Accrued Benefit Costs	108			155
Commodity Derivative Liabilities	89			10
Other	107			144
Total	$	1,143		$	1,109


⁽¹⁾	The sale was completed on June 30, 2014; bank transfer of the proceeds was completed on July 2, 2014.


⁽²⁾	See Note 6. Debt.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 3. Divestitures

Onshore US Properties During the first six months of 2014, we sold certain non-core onshore US crude oil and natural gas properties. The information regarding the assets sold is as follows:



	Three Months Ended June 30,			Six Months Ended June 30,
(millions)	2014			2014
Sales Proceeds	$	18		$	110
Less
Net Book Value of Assets Sold	(11		)	(118		)
Goodwill Allocated to Assets Sold	—			(6		)
Asset Retirement Obligations Associated with Assets Sold	—			20
Gain on Divestitures	$	7		$	6

China On June 30, 2014, we closed the sale of our China assets. We determined the sale of our China assets did not meet the criteria for discontinued operations presentation under ASU 2014-08. See Note 2. Basis of Presentation - Recently Issued Accounting Standards. The information regarding the China assets sold is as follows:



	Six Months Ended June 30,
(millions)	2014
Sales Proceeds ⁽¹⁾	$	186
Less
Net Book Value of Assets Sold	(149		)
Other Closing Adjustments	(2		)
Gain on Divestiture	$	35

⁽¹⁾Proceeds included $36 million cash received prior to June 30, 2014 and $150 million cash received on July 2, 2014, which was recorded as accounts receivable at June 30, 2014.

Offshore Israel Properties Assets held for sale as of June 30, 2014, include two natural gas discoveries, offshore Israel. We expect to divest these assets pursuant to an agreement we and our partners reached with the Israeli Antitrust Authority in March 2014 on various antitrust matters. The agreement is subject to final approval of the Israeli government.

North Sea Properties During the first six months of 2013, we sold non-operated working interests in properties located in the North Sea. The sales resulted in a $55 million gain based on net sales proceeds of $54 million. See Note 2. Basis of Presentation - Discontinued Operations.

Summarized results of discontinued operations are as follows:



	Six Months Ended June 30,
(millions)	2013
Oil and Gas Sales	$	21
Income Before Income Taxes	4
Income Tax Expense	10
Operating Loss, Net of Tax	(6		)
Gain on Sale, Net of Tax	55
Discontinued Operations, Net of Tax	$	49

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 4. Asset Impairments

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



	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2014		2013		2014		2013
US Properties, Primarily Shelf and Deepwater Gulf of Mexico	$	18	$	—	$	23	$	—
Mari-B (Offshore Israel)	14		—		14		—
McCulloch and Other North Sea Properties	2		—		94		—
Total	$	34	$	—	$	131	$	—

US and Offshore Israel In the US and offshore Israel, the asset carrying values of certain oil and natural gas assets increased when we recorded associated increases in asset retirement obligations. We determined that the recorded asset carrying values of some of these assets were not recoverable from future cash flows and recorded impairment expense. US properties included the currently-producing Raton natural gas well, as well as the Conquest and Gemini fields, which are being abandoned.

North Sea In March 2014, the operator of one of our remaining North Sea fields notified the working interest owners that expected field abandonment costs would be higher than originally projected. The operator also notified the working interest owners that it would begin working with the appropriate regulatory agency for approval of cessation of production and subsequent field abandonment sooner than anticipated.

As a result of this new information, we adjusted the asset retirement obligation to reflect the updated estimate of abandonment costs and timing. We assessed the asset for impairment and determined that it was impaired. The impairment charge was included in consolidated income from continuing operations.

See Note 2. Basis of Presentation and Note 7. Fair Value Measurements and Disclosures.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 5. Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil and natural gas prices on the majority of our production. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.

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

Unsettled Commodity Derivative Instruments As of June 30, 2014, we had entered into the following crude oil derivative instruments:



				Swaps		Collars
Settlement Period	Type of Contract	Index ⁽¹⁾	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, 2014
2014	Swaps	NYMEX WTI	37,000	$	92.67	$	—	$	—	$	—
2014	Swaps	Dated Brent	13,000	103.21		—		—		—
2014	Three-Way Collars	NYMEX WTI	12,000	—		75.67		90.67		100.88
2014	Three-Way Collars	Dated Brent	8,000	—		84.38		98.25		121.56
2015	Swaps	NYMEX WTI	27,000	88.80		—		—		—
2015	Swaps	Dated Brent	9,000	100.16		—		—		—
2015	Three-Way Collars	NYMEX WTI	20,000	—		70.50		87.55		94.41
2015	Three-Way Collars	Dated Brent	13,000	—		76.92		96.00		108.49
2016	Swaps	NYMEX WTI	6,000	87.95		—		—		—
2016	Swaps	Dated Brent	9,000	97.98		—		—		—
2016	Three-Way Collars	NYMEX WTI	3,000	—		72.00		85.00		94.82
2016	Three-Way Collars	Dated Brent	6,000	—		80.00		95.00		105.87


⁽¹⁾	West Texas Intermediate

As of June 30, 2014, we had entered into the following natural gas derivative instruments:



				Swaps		Collars
Settlement Period	Type of Contract	Index ⁽¹⁾	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, 2014
2014	Swaps	NYMEX HH	60,000	$	4.24	$	—	$	—	$	—
2014	Three-Way Collars	NYMEX HH	230,000	—		2.83		3.75		4.98
2015	Swaps	NYMEX HH	140,000	4.30		—		—		—
2015	Three-Way Collars	NYMEX HH	150,000	—		3.59		4.25		5.06


⁽¹⁾	Henry Hub

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments The fair values of commodity derivative instruments in our consolidated balance sheets were as follows:



Fair Value of Derivative Instruments
	Asset Derivative Instruments						Liability Derivative Instruments
	June 30, 2014			December 31, 2013			June 30, 2014			December 31, 2013
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments	Current Assets	$	—	Current Assets	$	1	Current Liabilities	$	199	Current Liabilities	$	65
	Noncurrent Assets	2		Noncurrent Assets	16		Noncurrent Liabilities	89		Noncurrent Liabilities	10
Total		$	2		$	17		$	288		$	75

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



	Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2014			2013			2014		2013
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	$	238		$	(118	)	$	292	$	(69	)
Natural Gas	(2		)	(43		)	19		(20		)
Total (Gain) Loss on Commodity Derivative Instruments	236			(161		)	311		(89		)
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	46			6			73		14
Natural Gas	3			(8		)	10		(23		)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	49			(2		)	83		(9		)
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	192			(124		)	219		(83		)
Natural Gas	(5		)	(35		)	9		3
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	$	187		$	(159	)	$	228	$	(80	)

AOCL Accumulated other comprehensive loss (AOCL) at June 30, 2014 included deferred losses of $23 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 term of our senior notes due March 2041. The amount of deferred losses (net of tax) which will be reclassified to earnings during the next 12 months, and recorded as an increase in interest expense, is de minimis.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 6. Debt

Debt consists of the following:



	June 30, 2014					December 31, 2013
(millions, except percentages)	Debt			Interest Rate		Debt			Interest Rate
Credit Facility, due October 3, 2018	$	600		1.41	%	$	—		—	%
Capital Lease and Other Obligations	353			—		359			—
5¼% Senior Notes, due April 15, 2014 ⁽¹⁾	—			—	%	200			5.25	%
8¼% Senior Notes, due March 1, 2019	1,000			8.25	%	1,000			8.25	%
4.15% Senior Notes, due December 15, 2021	1,000			4.15	%	1,000			4.15	%
7¼% Senior Notes, due October 15, 2023	100			7.25	%	100			7.25	%
8% Senior Notes, due April 1, 2027	250			8.00	%	250			8.00	%
6% Senior Notes, due March 1, 2041	850			6.00	%	850			6.00	%
5¼% Senior Notes, due November 15, 2043	1,000			5.25	%	1,000			5.25	%
7¼% Senior Debentures, due August 1, 2097	84			7.25	%	84			7.25	%
Total	5,237					4,843
Unamortized Discount	(18		)			(19		)
Total Debt, Net of Discount	5,219					4,824
Less Amounts Due Within One Year
5¼% Senior Notes, due April 15, 2014, net of discount ⁽¹⁾	—					(200		)
Capital Lease Obligations	(59		)			(58		)
Long-Term Debt Due After One Year	$	5,160				$	4,566


⁽¹⁾	We repaid the Senior Notes on their due date.

Credit Facility Our Credit Agreement provides for a $4.0 billion unsecured revolving credit facility (Credit Facility), which is available for general corporate purposes. The Credit Facility (i) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) 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.

See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Note 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 may include: variable to fixed price commodity swaps, two-way collars, and/or three-way collars. 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 and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 5. Derivative Instruments and Hedging Activities.

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. See Mutual Fund Investments above.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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, 2014
Financial Assets
Mutual Fund Investments	$	121		$	—		$	—	$	—		$	121
Commodity Derivative Instruments	—			11			—		(9		)	2
Financial Liabilities
Commodity Derivative Instruments	—			(297		)	—		9			(288		)
Portion of Deferred Compensation Liability Measured at Fair Value	(194		)	—			—		—			(194		)
December 31, 2013
Financial Assets
Mutual Fund Investments	$	114		$	—		$	—	$	—		$	114
Commodity Derivative Instruments	—			28			—		(11		)	17
Financial Liabilities
Commodity Derivative Instruments	—			(86		)	—		11			(75		)
Portion of Deferred Compensation Liability Measured at Fair Value	(176		)	—			—		—			(176		)


⁽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 netting provisions within our master 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 Information about impaired assets is as follows:



	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, 2014
Impaired Oil and Gas Properties	$	—	$	—	$	8	$	42	$	34
Three Months Ended June 30, 2013
Impaired Oil and Gas Properties	—		—		—		—		—
Six Months Ended June 30, 2014
Impaired Oil and Gas Properties	$	—	$	—	$	14	$	145	$	131
Six Months Ended June 30, 2013
Impaired Oil and Gas Properties	—		—		—		—		—

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

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

The fair value of impaired oil and gas properties was determined as of the date of the assessment using a discounted cash flow model based on management’s expectations of future crude oil and natural gas production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent future price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate of 10%. First and second quarter 2014 impairments were due to increases in asset carrying values associated with increases in asset retirement obligations (ARO). ARO increases were due to higher cost and change in timing of abandonment activities. See Note 4. Asset Impairments.

Additional Fair Value Disclosures

Debt The fair value of public, fixed-rate 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 1 measurement on the fair value hierarchy.

The carrying amount of our Credit Facility at June 30, 2014 approximates fair value because the interest rate paid on such debt is set for periods of three months or less. As such, we consider the fair values of our Credit Facility to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt.

Fair value information regarding our debt is as follows:



	June 30, 2014				December 31, 2013
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total Debt, Net of Unamortized Discount ⁽¹⁾	$	4,866	$	5,617	$	4,465	$	4,959


⁽¹⁾	Excludes capital lease and other obligations.

Note 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 charged to exploration expense as dry hole cost.

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



(millions)	Six Months Ended June 30, 2014
Capitalized Exploratory Well Costs, Beginning of Period	$	1,301
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	195
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale	(80		)
Capitalized Exploratory Well Costs Charged to Expense	(2		)
Capitalized Exploratory Well Costs, End of Period	$	1,414

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:



(millions)	June 30, 2014		December 31, 2013
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	517	$	568
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	897		733
Balance at End of Period	$	1,414	$	1,301
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	13		13

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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 June 30, 2014:



			Suspended Since
(millions)	Total		2012 - 2013		2010 - 2011		2009 & Prior		Progress
Country/Project:
Offshore Equatorial Guinea
Diega (including Carmen)	$	111	$	6	$	52	$	53	Evaluating regional development scenarios for this 2008 crude oil discovery
Carla	149		137		12		—		Evaluating regional development scenarios for this 2011 crude oil discovery
Felicita	38		3		6		29		Evaluating regional development plans for this 2008 condensate and natural gas discovery
Yolanda	19		2		3		14		Evaluating regional development plans for this 2007 condensate and natural gas discovery
Offshore Cameroon
YoYo	46		3		9		34		Working with the government to assess commercialization of this 2007 condensate and natural gas discovery
Offshore Israel
Leviathan	180		70		110		—		Targeting to sanction initial phase of development for this 2010 natural gas discovery by early 2015
Leviathan-1 Deep	76		49		27		—		Well did not reach the target interval; we are developing future drilling plans to test this deep oil concept
Dalit	25		3		2		20		Submitted a development plan to the government to develop this 2009 natural gas discovery as a tie-in to existing infrastructure
Dolphin 1	24		2		22		—		Reviewing regional development scenarios for this 2011 natural gas discovery
Offshore Cyprus
Cyprus	109		52		57		—		Submitted an appraisal plan to the Cyprus government to develop this 2011 natural gas discovery; planning additional appraisal activities including interpretation of seismic data
Falkland Islands
Scotia	71		71		—		—		Analyzing recently acquired seismic data
Other
Projects less than $20 million	49		39		4		6		Continuing to drill and evaluate appraisal wells
Total	$	897	$	437	$	304	$	156

Note 9. Asset Retirement Obligations

ARO consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:



	Six Months Ended June 30,
(millions)	2014			2013
Asset Retirement Obligations, Beginning Balance	$	586		$	402
Liabilities Incurred	22			2
Liabilities Settled	(43		)	(10		)
Revision of Estimate	120			7
Accretion Expense ⁽¹⁾	19			14
Asset Retirement Obligations, Ending Balance	$	704		$	415

⁽¹⁾Accretion expense is included in DD&A expense in the consolidated statements of operations.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

For the six months ended June 30, 2014

Liabilities incurred were due to new wells and facilities and included $13 million for onshore US and $9 million for Eastern Mediterranean.

Liabilities settled primarily related to onshore US property abandonments and non-core, onshore US assets sold.

Revisions were primarily due to an increase of $67 million related to a non-operated North Sea field due to an increase in costs and a change in timing recorded during the first quarter of 2014. See Note 4. Asset Impairments. Additional revisions were due to changes in cost and timing estimates and primarily included $21 million for DJ Basin, $16 million for Equatorial Guinea, $9 million for Eastern Mediterranean, and $7 million for deepwater Gulf of Mexico.

For the six months ended June 30, 2013

Liabilities incurred were due to new wells and facilities for onshore development. Liabilities settled in 2013 relate primarily to non-core onshore US properties that were sold. See Note 3. Divestitures.

Note 10. 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 June 30,				Six Months Ended June 30,
(millions, except per share amounts)	2014		2013		2014		2013
Income from Continuing Operations	$	192	$	358	$	392	$	590

Weighted Average Number of Shares Outstanding, Basic	361		359		361		358
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	5		4		4		4
Weighted Average Number of Shares Outstanding, Diluted	366		363		365		362
Earnings from Continuing Operations Per Share, Basic	$	0.53	$	1.00	$	1.09	$	1.64
Earnings from Continuing Operations Per Share, Diluted	0.52		0.99		1.07		1.63
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	3		5		4		5

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 11. Income Taxes

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



	Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2014			2013			2014			2013
Current	$	34		$	71		$	94		$	108
Deferred	7			57			24			106
Total Income Tax Provision	$	41		$	128		$	118		$	214
Effective Tax Rate	17.6		%	26.4		%	23.1		%	26.6		%

Our effective tax rate (ETR) for the three months and six months ended June 30, 2014 decreased as compared with the three and six months ended June 30, 2013 primarily due to our ability to benefit from previously unrecognized foreign tax credits, increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate and a decrease in our Israeli oil profits tax.

In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2010, Equatorial Guinea – 2008 and Israel – 2009.

See Note 3. Divestitures for income taxes associated with discontinued operations.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 12. Segment Information

We have operations throughout the world and manage our operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, and Sierra Leone); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes China, the North Sea, Falkland Islands, Nicaragua and new ventures. The North Sea geographical segment is included in continuing operations in 2014 and discontinued operations in 2013.



(millions)	Consolidated			United States			West Africa		Eastern Mediterranean		Other Int'l & Corporate
Three Months Ended June 30, 2014
Revenues from Third Parties	$	1,338		$	842		$	339	$	113	$	44
Income from Equity Method Investees	45			—			45		—		—
Total Revenues	1,383			842			384		113		44
DD&A	413			311			72		15		15
Gain on Divestitures	(44		)	(8		)	—		—		(36		)
Asset Impairments	34			18			—		14		2
Income (Loss) from Continuing Operations Before Income Taxes	233			199			204		44		(214		)
Three Months Ended June 30, 2013
Revenues from Third Parties	$	1,112		$	683		$	290	$	101	$	38
Income from Equity Method Investees	37			—			37		—		—
Total Revenues	1,149			683			327		101		38
DD&A	368			258			63		27		20
Loss on Divestitures	4			—			4		—		—
Asset Impairments	—			—			—		—		—
Income (Loss) from Continuing Operations Before Income Taxes	486			320			268		44		(146		)
Six Months Ended June 30, 2014
Revenues from Third Parties	$	2,665		$	1,684		$	662	$	225	$	94
Income from Equity Method Investees	97			—			97		—		—
Total Revenues	2,762			1,684			759		225		94
DD&A	837			619			148		29		41
Gain on Divestitures	(42		)	(6		)	—		—		(36		)
Asset Impairments	131			23			—		14		94
Income (Loss) from Continuing Operations Before Income Taxes	510			382			465		121		(458		)
Six Months Ended June 30, 2013
Revenues from Third Parties	$	2,196		$	1,399		$	563	$	152	$	82
Income from Equity Method Investees	96			—			96		—		—
Total Revenues	2,292			1,399			659		152		82
DD&A	734			524			117		55		38
Gain on Divestitures	(12		)	(12		)	—		—		—
Asset Impairments	—			—			—		—		—
Income (Loss) from Continuing Operations Before Income Taxes	804			563			499		59		(317		)
June 30, 2014
Total Assets	$	20,575		$	14,175		$	3,152	$	2,762	$	486
December 31, 2013
Total Assets	19,598			13,094			3,199		2,753		552

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 13. Commitments and Contingencies

CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation).

The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Due to low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 until February 28, 2014. Due to recent increases in Henry Hub natural gas prices, we began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014. Based on the June 30, 2014 NYMEX Henry Hub natural gas price curve and current development plans, we forecast we will incur approximately $240 million under the CONSOL Carried Cost Obligation for the year ended December 31, 2014.

Marcellus Shale Firm Transportation Agreements In February 2014, we signed Precedent Agreements for Firm Transportation (the Agreements) to flow 150,000 MMBtu per day of our Marcellus Shale natural gas production to Gulf Coast markets. The Agreements, which are expected to be executed in the second half of 2014, are for transportation services on new pipeline extensions, to be constructed by, and connecting to, an existing third-party system. The pipeline extensions are expected to be complete and operational in June of 2017. Our financial commitment totals approximately $765 million, undiscounted, over a 15-year period. The Agreements are subject to various conditions, including regulatory approval of the pipeline extension projects.

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.

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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. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. 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 worldwide explorer and producer of crude oil, natural gas and natural gas liquids. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified, portfolio of assets with investment flexibility between: onshore unconventional developments and offshore organic exploration leading to major development projects; US and international development projects; and production mix among crude oil, natural gas, and NGLs. We currently focus our efforts in five core operating areas: the DJ Basin and Marcellus Shale (onshore US), deepwater Gulf of Mexico, offshore West Africa, and offshore Eastern Mediterranean, where we have strategic competitive advantage and which we believe generate superior returns. We also seek to enter potential new core areas, and we are currently conducting exploration activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, and Cyprus.

Our financial results for second quarter 2014 included:


•	net income of $192 million as compared with $377 million for second quarter 2013;


•	loss on commodity derivative instruments of $236 million (including $187 million non-cash portion of loss) as compared with a gain on commodity derivative instruments of $161 million (including $159 million non-cash portion of gain) for second quarter 2013;


•	asset impairment charges of $34 million, as compared with zero for second quarter 2013;


•	diluted earnings per share of $0.52, as compared with $1.04 for second quarter 2013;


•	cash flow provided by operating activities of $828 million, as compared with $539 million for second quarter 2013;


•	ending cash balance of $958 million, as compared with $1.1 billion at December 31, 2013;


•	capital spending, on a cash basis, of $1.2 billion for both the second quarter 2013 and 2014;


•	gain of $35 million on China asset sale;


•	repayment of $200 million senior notes in April 2014;


•	total liquidity of $4.4 billion at June 30, 2014, as compared with $5.1 billion at December 31, 2013; and


•	ratio of debt-to-book capital of 35% at June 30, 2014, as compared with 35% at December 31, 2013.

Our operating results for second quarter 2014 included:


•	delivered record horizontal production of 112 MBoe/d from the DJ Basin and Marcellus Shale, 56% higher than second quarter of last year;


•	increased wet gas type curves 10% for wells in the Majorsville area of the Marcellus Shale;


•	announced plans to form a master limited partnership (MLP) with CONSOL for our jointly owned midstream assets in the Marcellus Shale;


•	exploration discovery made at the Katmai prospect located in the deepwater Gulf of Mexico;


•	acquired interest in 17 exploration lease blocks in the Atwater Valley area of the Gulf of Mexico and spud initial prospect, Bright;


•	increased Leviathan resource estimate as the result of additional information from the ongoing Leviathan appraisal program;


•	signed two regional export Letters of Intent for natural gas sales to customers in Egypt; and


•	closed China asset sale, receiving $186 million in proceeds.

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Exploration Program Update

We have numerous exploration opportunities remaining in our core areas and are also engaged in new venture activity in both our US and international locations.

We were in the process of drilling and/or evaluating significant exploratory wells at June 30, 2014 (See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs), and expect to continue an active exploratory drilling program in the future.

A portion of our 2014 capital investment program is dedicated to exploration and associated appraisal activities, including leasehold acquisitions. However, we do not always 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 development project is not economically or operationally viable.

In the event we conclude that one of our 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. Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Operating Outlook – Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below.

Updates on significant exploration activities are as follows:

Northeast Nevada We are currently analyzing results from our first exploratory vertical well and conducting a long term production test. We plan to drill additional exploratory wells later in 2014.

Deepwater Gulf of Mexico During second quarter 2014, we acquired working interests in 17 deepwater exploration leases in the Gulf of Mexico. Each of the leases resides in the Atwater Valley protraction area. We acquired a 50% working interest in 13 leases and an average 26% working interest in four leases.

As part of the transaction, we are participating with a 50% non-operated working interest in the Bright prospect, which is currently being drilled on Atwater Valley Block 362 in a water depth of approximately 5,600 feet. The initial exploratory well, targeting multiple reservoirs, is anticipated to be drilled to a total depth of 13,500 feet. In addition to the Bright prospect, there are multiple follow-on exploration opportunities that have been identified on these newly acquired leases.

We are also currently drilling the Katmai exploratory well (Green Canyon Block 40, 50% operated working interest) in water depth of approximately 2,100 feet. We recently announced a commercial crude oil discovery at Katmai, and expect to reach a total depth of 28,300 feet during the third quarter of 2014.

Offshore West Africa We are currently acquiring 3D seismic data across Blocks O and I, offshore Equatorial Guinea, and may potentially drill an exploratory well offshore Cameroon in the fourth quarter of 2014. Additionally, we are reprocessing 3D seismic data over our YoYo mining concession, offshore Cameroon.

Offshore Eastern Mediterranean We are processing and evaluating recently acquired 3D seismic data over offshore Israel and Cyprus and continue to study locations for potential exploratory wells, with opportunities offshore in both Israel and Cyprus.

Offshore Falkland Islands We continue to process and evaluate 3D seismic data over the northern and southern areas and prepare for our first operated exploratory well planned for 2015.

Major Development Project Updates

We continue to advance our major development projects, which we expect to deliver incremental production over the next several years. Updates on major development projects are as follows:

Sanctioned Ongoing Development Projects

A "sanctioned" development project is one for which a final investment decision has been made.

DJ Basin (Onshore US) We continue to operate at a high level of horizontal drilling activity with continued growth from strong well performance, new wells brought online, and expanded natural gas and crude oil infrastructure. We have accelerated our extended reach lateral well program to approximately 30% of our wells to be drilled in 2014. During the quarter, we spud 80 horizontal wells, of which 27 were extended reach lateral wells, and 85 wells initiated production. Our 2014 drilling program includes over 90 extended reach lateral wells. Currently, 10 drilling rigs are active across the basin.

Marcellus Shale (Onshore US) We continue to delineate the wet gas acreage, while our partner, CONSOL Energy, Inc. (CONSOL), continues to develop the dry gas acreage. During the quarter, we and our partner drilled 48 wells, and 35 wells initiated production. The joint venture is currently operating ten drilling rigs.

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Due to an increase in Henry Hub natural gas prices, our funding of certain drilling and completion costs under the CONSOL Carried Cost Obligation commenced as of March 1, 2014. See Liquidity and Capital Resources – Contractual Obligations below.

In June 2014, we and our joint venture partner, CONSOL, submitted a confidential draft Registration Statement on Form S-1 to the U.S. Securities and Exchange Commission relating to a proposed master limited partnership (MLP). The MLP will own, operate, and develop our jointly-owned natural gas midstream assets in the Marcellus Shale.

Gunflint (Deepwater Gulf of Mexico) In 2013, we sanctioned the development plan for the 2008 Gunflint crude oil discovery, utilizing a subsea tieback to an existing host facility, and are targeting first production in 2016.

Big Bend (Deepwater Gulf of Mexico) The 2012 Big Bend crude oil discovery is located in the Rio Grande area of the deepwater Gulf of Mexico. In October 2013, we sanctioned a development plan, utilizing a subsea tieback to a third party host facility. First production is targeted for late 2015.

Tamar Expansion (Offshore Israel) The Tamar compression project, which is expected to increase capacity by 200 MMcf/d at the Ashdod onshore terminal, is progressing, and we expect operational start-up in the second half of 2015.

We are continuing to work with the Israeli government to obtain regulatory approval of our development plan for the Tamar Southwest discovery, which is intended to utilize current Tamar infrastructure. Continuing delays in securing regulatory approvals have placed the project at risk of delay. We have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to provide future flow rate assurance for our overall Tamar project.

In May 2014, we announced that we had entered into a non-binding Letter of Intent (LOI) for the supply of natural gas from the Tamar field to existing natural gas liquefaction (LNG) facilities in Egypt.

Unsanctioned Development Projects (As of June 30, 2014)

Dantzler (Deepwater Gulf of Mexico) The 2013 Dantzler crude oil discovery is located in the Rio Grande area of the deepwater Gulf of Mexico and is a co-development opportunity with Big Bend. During the second quarter, we spud the first Dantzler appraisal well (45% operated working interest) and expect drilling results during the third quarter of 2014.

Leviathan (Offshore Israel) In the first half of 2014, we made significant progress on the development of the Leviathan field, following approval of Israel's natural gas export policy, an agreement with Israel's Anti-trust Authority, and receipt of the Development and Production Leases for Leviathan.

In May 2014, we announced that the existing Leviathan partners terminated the non-binding memorandum of understanding regarding the sale of interest in the Leviathan licenses to Woodside Petroleum.

The initial phase of the Leviathan project is designed to provide significant quantities of natural gas to Israel and regional markets. In June 2014, we announced that we had entered into a non-binding LOI for the supply of natural gas from the Leviathan field to existing LNG facilities in Egypt.

We are currently considering various project finance options for Leviathan. Sanctioning of the initial phase of development at Leviathan is targeted by the end of 2014 or early 2015, with first production from the field currently planned for the end of 2017 or early 2018.

See also Update on Israel's Natural Gas Economy, below.

Cyprus Project (Offshore Cyprus) We are planning additional appraisal activities, including interpretation of seismic data and spudding another well to further determine the ultimate recoverable resources on Block 12 and optimize field development planning. In addition, our application for renewal of the production sharing contract for two additional years was approved in May 2014.

Diega and Carla (Offshore Equatorial Guinea) We are currently evaluating regional development scenarios for Diega and Carla and targeting to sanction a Diega development project in 2015.

See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs for additional information on costs incurred related to these projects.

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Non-Core Divestiture Program

We have continued our non-core asset divestiture program with the sale of our China assets on June 30, 2014. Sales of certain smaller onshore US property packages were completed during the first six months of 2014 or are expected to be completed this year. Divestitures of non-core properties allow us to allocate capital and human resources to high-value and high-growth areas. See Item 1. Financial Statements – Note 3. Divestitures and Operating Outlook - Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below.

We are currently winding up local business activities in countries of former operations. At this time, we do not believe that any of the activities associated with these areas will have a material effect on our financial position, results of operations or cash flows.

Update on Israel's Natural Gas Economy

Israel Antitrust Authority During 2014, we and our partners reached an agreement with the Israeli government on various antitrust matters. As a result of the agreement, we will divest two natural gas discoveries. We have initiated an active program to locate a buyer and other actions required to complete the plan to sell the assets. The assets are reported within assets held for sale in our consolidated balance sheet at June 30, 2014.

The agreement also granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. As a result, we plan to further our domestic natural gas marketing activities. The agreement is subject to final approval by the Israeli government.

On March 26, 2014, the Israel Ministry of Finance (Ministry) issued a memorandum indicating its intent to amend the Petroleum Profits Law in light of the Israeli government's 2013 decision to permit the export of natural gas from Israel. The purpose of the proposed amendments is mainly to regulate the method of taxing petroleum export transactions, and, in particular, exports of natural gas. As a part of the Ministry's draft recommendation, several methodologies could be used to establish the transfer price for natural gas sales, depending on various circumstances. We are currently evaluating the recommendation and proposed amendments.

The recent Israel-Gaza conflict has resulted in loss of life and destruction of property. See our Annual Report on Form 10-K for the year ended December 31, 2013 - Item 1A. Risk Factors - Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.

Update on Hydraulic Fracturing

Potential Rulemaking Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations, and some have proposed rules.

A measure to ban hydraulic fracturing was on the ballot in the City of Loveland in northern Colorado in June of 2014. Industry worked with the community to defeat that initiative. Also during 2014, we have been actively campaigning against statewide ballot initiatives that would unreasonably restrict or limit crude oil and natural gas development in Colorado. There are currently two remaining initiatives that have survived titling and Supreme Court review and are in a position to collect sufficient signatures to be placed on the November 2014 ballot. These are:


•	an initiative to amend the state constitution to establish an environmental bill of rights; and


•	an initiative to amend the state constitution to impose a 2000-foot statewide drilling setback from occupied structures, unless a waiver is obtained from the landowner.

Petitioners have until August 4, 2014 to gather 86,105 verified signatures and we will work with the State of Colorado to ensure any signatures submitted on these initiatives are properly verified. The ultimate passage and implementation of one or both of these initiatives could have a negative impact on our business. In particular, a statewide drilling setback will likely delay or otherwise limit our drilling and development activities in certain parts of the DJ Basin. This could result in a reduction in our proved reserves and negatively impact our results of operations, cash flows, and stock price.

In Nevada, state regulators are in the process of promulgating rules to govern hydraulic fracturing and new crude oil and natural gas development. We have actively participated in that process and do not believe it will have a material impact on our activities. We will continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations.

Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.

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Regulations

On February 23, 2014, the Colorado Air Quality Control Commission (Commission) adopted a number of revisions to its oil and gas industry regulations. The revisions include the full adoption of US Environmental Protection Agency's Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution (also known as NSPS Quad O) with corresponding complementary control measures. The control measures set forth requirements for identifying and repairing leaks, undertaking record keeping, and submitting reports. The revisions also include the first ever regulation of methane emissions from the industry. In collaboration with the Environmental Defense Fund and other oil and gas operators, we provided testimony and evidence to the Commission in support of the adopted revisions. The adopted revised regulations were published in the Colorado Register on March 25, 2014, Volume 37, No. 6, and are effective as of April 14, 2014. Copies of these regulations are available at http://www.sos.state.co.us/CCR. We do not currently believe costs incurred to implement these regulations will be material to our earnings or cash flows.

Sales Volumes

The execution of our strategy has delivered a diversified production growth most recently due to our Tamar natural gas field and Alen condensate project coming online in 2013 along with accelerated activity in onshore US unconventional developments. On a BOE basis, total sales volumes were 11% higher for the second quarter of 2014 as compared with the second quarter of 2013, and our mix of sales volumes was 46% global liquids, 27% international natural gas, and 27% US natural gas. See Results of Operations – Revenues, below.

Commodity Price Changes

Average realized natural gas prices increased 5% in the US and 13% in Israel for second quarter of 2014 as compared with the second quarter of 2013. Average realized crude oil prices increased 5% in the US and 7% in Equatorial Guinea for the second quarter of 2014 as compared with the second quarter of 2013.

Recently Issued Accounting Standards

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

OPERATING OUTLOOK

2014 Production Our expected crude oil, natural gas and NGL production for 2014 may be impacted by several factors including:


•	changes to drilling plans in the DJ Basin and the Marcellus Shale;


•	Israeli demand for electricity, which affects demand for natural gas as fuel for power generation and industrial market growth, and which is impacted by unseasonable weather;


•	potential downtime at key assets including: Galapagos and Swordfish, deepwater Gulf of Mexico; Tamar, offshore Israel; and Aseng and Alen, offshore Equatorial Guinea;


•	natural field decline in the deepwater Gulf of Mexico and the Alba and Aseng fields offshore Equatorial Guinea; and


•	potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico which can shut-in or reduce production.

2014 Capital Investment Program Total capital expenditures are estimated at $4.8 to $5.0 billion for 2014. We expect to invest approximately 70% of the program in onshore US development and approximately 30% of the program in global deepwater activities.

The 2014 capital investment program is estimated to exceed operating cash flows and is expected to be funded from cash flows from operations, cash on hand, and borrowings under our unsecured revolving credit facility (Credit Facility) and/or other financing. Funding may also be provided by proceeds from divestment of non-core assets or farm-out of working interests in exploration prospects. See Liquidity and Capital Resources – Financing Activities.

We will continue to evaluate the level of capital spending and remain flexible throughout the year. For further discussion, see Executive Overview – Update on Hydraulic Fracturing, above, regarding potential legislative or regulatory changes in the use of hydraulic fracturing, and Liquidity and Capital Resources – Contractual Obligations, below, regarding the CONSOL Carried Cost Obligation.

Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense

Exploration Activities We have an active exploratory drilling program. In the event we conclude that an exploratory well 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. For example, in the Falkland Islands we are processing recently acquired seismic data. We will conduct seismic interpretation and basin modeling during the remainder of 2014 in order to determine our future drilling program. Integration of seismic information with the results of the Scotia exploratory well will allow us to assess the economic viability of this prospect. If we were to determine, based on the results of seismic interpretation and/or

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additional drilling activities, that the Scotia prospect is not economically viable, the costs we have incurred (approximately $73 million to date) would be written off to dry hole expense.

Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, while we continue to mature our prospect portfolio, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms.

One particular deepwater Gulf of Mexico lease, which we acquired under regulations in effect prior to the Deepwater Gulf of Mexico Moratorium, is set to expire on July 31, 2014. We have been working to mature this prospect by conducting various activities, including the licensing and processing of 3-D seismic data and interpretation of geophysical information, which have resulted in the identification of a potential hydrocarbon-bearing formation below 25,000 feet. We reviewed the criteria for a lease suspension of operations (SOO), which may be granted by regulatory authorities, and believe we satisfy each of the required conditions. We submitted an application for the SOO, evidencing satisfaction of the required conditions, on July 7, 2014. If an SOO is granted, we intend to continue processing of subsalt imaging and developing an exploration plan, targeting a 2017 exploratory well spud date. Although we believe we have satisfied the required conditions for the SOO, there is no certainty an extension will be obtained prior to the lease expiration. The lease had a net book value of approximately $41 million at June 30, 2014. If we are unable to obtain an extension, we must relinquish the lease, abandon our exploration plans, and write off the book value to exploration expense.

Producing Properties Commodity prices remain volatile. A decline in future crude oil or natural gas prices could result in impairment charges. 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 along with operating and development costs, market outlook on forward commodity prices, and interest 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.

Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico has been shut-in due to mechanical issues. We have conducted remediation work; however, return to production has been delayed due to work being performed at the non-operated host facility. We expect to begin producing later in third quarter 2014. No impairment is currently indicated; however, we will monitor production and reserves when South Raton is brought back online and continue to assess the field for possible impairment. South Raton had a net book value of approximately $123 million at June 30, 2014.

In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may be difficult to estimate costs as rigs and services become more expensive in periods of higher demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment.

Divestments We are currently marketing certain non-core onshore US properties, including our assets in the Piceance Basin of western Colorado. If properties are reclassified as assets held for sale in the future, 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. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale.

In addition, certain assets offshore Israel were classified as held for sale at June 30, 2014. No impairments are indicated at this time. However, failure to achieve acceptable sale terms or delays in closing sales of these properties could result in impairment and/or loss on sale.

Potential Change in Pennsylvania Tax Structure The State of Pennsylvania has been addressing a potential budget deficit. As a result, Pennsylvania lawmakers have been considering various alternatives for generating additional revenues, including additional taxes on crude oil and natural gas production. Additional taxes could be in the form of a severance tax, which would be assessed on the value of the natural gas produced. A severance tax, if imposed, may or may not replace the current local impact fee, which is assessed on a per well basis at a rate determined primarily by the age of the well, under a law signed in 2012.

We are currently unable to predict whether a severance tax will be imposed by the State of Pennsylvania. However, additional taxes on our crude oil, condensate or natural gas production could have a negative impact on our results of operations and cash flows.

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RESULTS OF OPERATIONS

In the discussion below, the North Sea geographical segment is reflected as discontinued operations for the first six months of 2013. During first quarter 2014, the remaining unsold North Sea assets were reclassified to held and used, and their operations are included in continuing operations for 2014. See also Discontinued Operations, below.

Revenues

Revenues were as follows:



					Increase/(Decrease) from Prior Year
(millions)	2014		2013		Increase/(Decrease) from Prior Year
Three Months Ended June 30,
Oil, Gas and NGL Sales	$	1,338	$	1,112	20	%
Income from Equity Method Investees	45		37		22	%
Total	$	1,383	$	1,149	20	%

Six Months Ended June 30,
Oil, Gas and NGL Sales	$	2,665	$	2,196	21	%
Income from Equity Method Investees	97		96		1	%
Total	$	2,762	$	2,292	21	%

Changes in revenues are discussed below.

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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 (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, 2014
United States	65	469	22	166	$	99.39	$	4.24	$	34.66
Equatorial Guinea ⁽²⁾	34	248	—	75	108.08		0.27		—
Israel	—	218	—	37	—		5.57		—
Other International ⁽³⁾	5	—	—	5	104.70		—		—
Total Consolidated Operations	104	935	22	283	102.53		3.50		34.66
Equity Investees ⁽⁴⁾	2	—	6	7	108.31		—		64.86
Total Continuing Operations	106	935	28	290	$	102.62	$	3.50	$	40.70
Three Months Ended June 30, 2013
United States	58	404	15	140	$	94.29	$	4.04	$	30.05
Equatorial Guinea ⁽²⁾	31	252	—	73	101.44		0.27		—
Israel	—	220	—	37	—		4.92		—
Other International ⁽³⁾	4	—	—	4	97.92		—		—
Total Consolidated Operations	93	876	15	254	96.84		3.18		30.05
Equity Investees⁽⁴⁾	1	—	5	6	99.48		—		62.93
Total Continuing Operations	94	876	20	260	$	96.87	$	3.18	$	38.48

Six Months Ended June 30, 2014
United States	65	476	20	165	$	98.22	$	4.52	$	39.10
Equatorial Guinea ⁽²⁾	34	245	—	74	106.92		0.27		—
Israel	—	218	—	37	—		5.59		—
Other International ⁽³⁾	5	—	—	5	104.48		—		—
Total Consolidated Operations	104	939	20	281	101.39		3.66		39.10
Equity Investees ⁽⁴⁾	2	—	6	7	106.50		—		69.70
Total Continuing Operations	106	939	26	288	$	101.47	$	3.66	$	45.71
Six Months Ended June 30, 2013
United States	60	406	15	143	$	95.02	$	3.68	$	34.63
Equatorial Guinea ⁽²⁾	29	249	—	70	106.20		0.27		—
Israel	—	166	—	28	—		5.00		—
Other International ⁽³⁾	4	—	—	4	103.66		—		—
Total Consolidated Operations	93	821	15	245	98.87		2.91		34.63
Equity Investees ⁽⁴⁾	2	—	6	8	105.38		—		69.03
Total Continuing Operations	95	821	21	253	$	98.98	$	2.91	$	44.02

⁽¹⁾

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

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⁽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, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.


⁽³⁾	Other International includes primarily China.


⁽⁴⁾	Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees, below.

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



	Sales Revenues
(millions)	Crude Oil & Condensate		Natural Gas		NGLs		Total
Three Months Ended June 30, 2013	$	817	$	253	$	42	$	1,112
Changes due to
Increase in Sales Volumes	100		17		19		136
Increase in Sales Prices	54		27		9		90
Three Months Ended June 30, 2014	$	971	$	297	$	70	$	1,338

Six Months Ended June 30, 2013	$	1,667	$	432	$	97	$	2,196
Changes due to
Increase in Sales Volumes	186		62		30		278
Increase in Sales Prices	46		128		17		191
Six Months Ended June 30, 2014	$	1,899	$	622	$	144	$	2,665

Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales increased during second quarter and first six months of 2014 as compared with 2013 due to the following:


•	higher sales volumes in the DJ Basin attributable to our horizontal drilling program;


•	additional sales volumes from the Alen condensate project, offshore Equatorial Guinea, which began producing in late second quarter 2013 and averaged 11 MBoe/d during the first six months of 2014;


•	higher sales volumes from the deepwater Gulf of Mexico of approximately 2 MBoe/d for the second quarter of 2014 as compared with 2013; and


•	higher realized prices for crude and condensate, both in the DJ Basin and offshore Equatorial Guinea;

partially offset by:


•	negative volume impact of severe winter weather and downtime for facility upgrades in the DJ Basin; and


•	lower sales volumes from the Aseng project, offshore Equatorial Guinea, due to natural production declines.

Natural Gas Sales – Revenues from natural gas sales increased during the second quarter and first six months of 2014 as compared with 2013 due to the following:


•	increases in total consolidated average realized prices of 10% primarily due to increased demand from cooler weather and higher-than-expected inventory withdrawals in the US; and


•	higher sales volumes in the Marcellus Shale of 231 MMcf/d for second quarter 2014 and 218 MMcf/d for the first six months of 2014, as compared with 108 MMcf/d and 104 MMcf/d, respectively for 2013, primarily attributable to our horizontal drilling program and continued ramp-up of activity;

partially offset by:


•	lower sales volumes due to non-core onshore US properties divested during 2013 and first six months of 2014; and


•	lower sales volumes due to natural field decline from the Mari-B, Noa and Pinnacles fields, offshore Israel.

NGL Sales – The majority of our US NGL production is currently from the DJ Basin. Additional NGL production from the Marcellus Shale added 2 MBbl/d during second quarter and first six months of 2014 as compared with 2013, primarily due to increased production from the wet gas acreage. NGL sales in the DJ Basin increased by 5 MBbl/d during the second quarter of 2014 as compared with 2013, and recent sales of our non-core onshore US properties have slightly reduced sales volumes as compared with second quarter 2013. Additionally, sales prices have increased 13% for the first six months of 2014, compared to the first six months of 2013.

Income from Equity Method Investees We have a 45% interest in Atlantic Methanol Production Company, LLC, which owns and operates a methanol plant and related facilities, and a 28% interest in Alba Plant LLC, which owns and operates a liquefied petroleum gas processing plant. Both plants are located onshore on Bioko Island in Equatorial Guinea.

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Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, our share of dividends is reported within cash flows from operating activities and our share of investments is reported within cash flows from investing activities.

Operating Costs and Expenses

Operating costs and expenses were as follows:



							Increase from Prior Year
(millions)	2014			2013			Increase from Prior Year
Three Months Ended June 30,
Production Expense	$	248		$	210		18	%
Exploration Expense	59			90			(34	)%
Depreciation, Depletion and Amortization	413			368			12	%
General and Administrative	127			104			22	%
Gain on Divestitures	(44		)	4			N/M
Asset Impairments	34			—			—	%
Other Operating (Income) Expense, Net	17			12			42	%
Total	$	854		$	788		8	%

Six Months Ended June 30,
Production Expense	$	481		$	398		21	%
Exploration Expense	133			151			(12	)%
Depreciation, Depletion and Amortization	837			734			14	%
General and Administrative	266			216			23	%
Gain on Divestitures	(42		)	(12		)	N/M
Asset Impairments	131			—			—	%
Other Operating (Income) Expense, Net	23			20			N/M
Total	$	1,829		$	1,507		21	%

N/M – Amount is not meaningful.

Changes in operating costs and expenses are discussed below.

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Production Expense Components of production expense were as follows:



(millions, except unit rate)	Total per BOE ⁽¹⁾		Total		United States		Equatorial Guinea		Israel		Other Int'l, Corporate ⁽²⁾
Three Months Ended June 30, 2014
Lease Operating Expense ⁽³⁾	$	5.99	$	154	$	88	$	36	$	14	$	16
Production and Ad Valorem Taxes	2.06		53		45		—		—		8
Transportation and Gathering Expense	1.60		41		40		—		—		1
Total Production Expense	$	9.65	$	248	$	173	$	36	$	14	$	25
Three Months Ended June 30, 2013
Lease Operating Expense ⁽³⁾	$	6.04	$	140	$	90	$	27	$	19	$	4
Production and Ad Valorem Taxes	1.87		43		35		—		—		8
Transportation and Gathering Expense	1.17		27		27		—		—		—
Total Production Expense	$	9.08	$	210	$	152	$	27	$	19	$	12

Six Months Ended June 30, 2014
Lease Operating Expense ⁽³⁾	$	5.89	$	299	$	176	$	67	$	26	$	30
Production and Ad Valorem Taxes	2.01		102		85		—		—		17
Transportation and Gathering Expense	1.57		80		78		—		—		2
Total Production Expense	$	9.47	$	481	$	339	$	67	$	26	$	49
Six Months Ended June 30, 2013
Lease Operating Expense ⁽³⁾	$	5.78	$	257	$	179	$	47	$	20	$	11
Production and Ad Valorem Taxes	1.94		86		69		—		—		17
Transportation and Gathering Expense	1.24		55		54		—		—		1
Total Production Expense	$	8.96	$	398	$	302	$	47	$	20	$	29


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


⁽²⁾	Other International includes primarily China.


⁽³⁾	Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.

For the second quarter and first six months of 2014, total production expense increased as compared with 2013 due to the following:


•	increased lease operating expense in the DJ Basin and Marcellus Shale due to increased development activity and higher production;


•	increased lease operating expense offshore Equatorial Guinea primarily due to the start up of the Alen field in the second half of 2013;


•	increased lease operating expense offshore Israel primarily due to the start up of the Tamar field, which began producing at the end of first quarter 2013;


•	increased production and ad valorem taxes in the DJ Basin and Marcellus Shale due to higher production volumes and higher average prices; and


•	increased transportation and gathering expense in the DJ Basin and Marcellus Shale due to higher production volumes from ongoing development activities;

partially offset by:


•	decreased lease operating expense from sales of non-core onshore US properties in 2013; and


•	decreased lease operating expense from natural field decline from the Mari-B field, offshore Israel.

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Exploration Expense Components of exploration expense were as follows:



(millions)	Total		United States		West Africa ⁽¹⁾		Eastern Mediter- ranean ⁽²⁾		Other Int'l, Corporate ⁽³⁾
Three Months Ended June 30, 2014
Dry Hole Cost	$	—	$	—	$	—	$	—	$	—
Seismic	9		8		—		1		—
Staff Expense	33		10		2		3		18
Other	17		17		—		—		—
Total Exploration Expense	$	59	$	35	$	2	$	4	$	18
Three Months Ended June 30, 2013
Dry Hole Cost	$	23	$	15	$	8	$	—	$	—
Seismic	25		7		2		6		10
Staff Expense	30		5		3		—		22
Other	12		12		—		—		—
Total Exploration Expense	$	90	$	39	$	13	$	6	$	32

Six Months Ended June 30, 2014
Dry Hole Cost	$	2	$	2	$	—	$	—	$	—
Seismic	32		15		—		2		15
Staff Expense	68		18		4		5		41
Other	31		31		—		—		—
Total Exploration Expense	$	133	$	66	$	4	$	7	$	56
Six Months Ended June 30, 2013
Dry Hole Cost	$	23	$	15	$	8	$	—	$	—
Seismic	50		13		2		6		29
Staff Expense	58		12		4		2		40
Other	20		21		—		—		(1		)
Total Exploration Expense	$	151	$	61	$	14	$	8	$	68


⁽¹⁾	West Africa includes Equatorial Guinea, Cameroon, and Sierra Leone.


⁽²⁾	Eastern Mediterranean includes Israel and Cyprus.


⁽³⁾	Other International includes the Falkland Islands and Nicaragua.

Exploration expense for the second quarter and first six months of 2014 included:


•	seismic expense related to 3D seismic testing in the DJ Basin and Falkland Islands; and


•	staff expense associated with new ventures and corporate expenditures.

Exploration expense for the second quarter and first six months of 2013 included the following:


•	dry hole cost related primarily to the deeper exploration objective of the second Gunflint appraisal well, deepwater Gulf of Mexico, and the side track portion of the Carla I-7 appraisal well, offshore Equatorial Guinea;


•	other international seismic expense related to 3D seismic testing in the Falkland Islands; and


•	staff expense associated with new ventures and corporate expenditures.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
DD&A Expense (millions) ⁽¹⁾	$	413	$	368	$	837	$	734
Unit Rate per BOE ⁽²⁾	$	16.07	$	15.93	$	16.49	$	16.53


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


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

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Total DD&A expense for the second quarter and first six months of 2014 increased as compared with 2013 due to the following:


•	increase in the DJ Basin and the Marcellus Shale due to higher sales volumes associated with increased development activity;


•	increase in the deepwater Gulf of Mexico due to a new well producing at Ticonderoga and the addition of the Neptune spar at Swordfish; and


•	increase offshore Equatorial Guinea primarily due to the start up of the Alen field in the second half of 2013;

partially offset by:


•	decrease due to sales of non-core onshore US properties in 2013; and


•	decrease offshore Israel related to the start up of the Tamar field at the end of first quarter 2013 which has a lower DD&A rate.

The increase in the unit rate per BOE for the second quarter of 2014 as compared with 2013 was due primarily to the change in mix of production. Higher-cost production volumes in the deepwater Gulf of Mexico were offset by lower cost volumes produced at Tamar, offshore Israel, which replaced higher cost volumes produced from the Mari-B, Noa and Pinnacles fields. The unit rate per BOE remained flat for the first six months of 2014 as compared with 2013.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
G&A Expense (millions)	$	127	$	104	$	266	$	216
Unit Rate per BOE ⁽¹⁾	$	4.93	$	4.48	$	5.24	$	4.86


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

G&A expense for the second quarter and first six months of 2014 increased as compared with 2013 primarily due to additional expenses relating to personnel and office space in support of our major development projects and increased exploration activities. For example, our total number of employees increased from 2,190 at December 31, 2012, to 2,527 at December 31, 2013 and to just over 2,600 at June 30, 2014. An increase in the number of participants in our 401(k) savings plan, as a result of the planned termination of the defined benefit pension plan, resulted in an increase in payroll burden.

Asset Impairment Expense Asset impairment expense was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2014		2013		2014		2013
Asset Impairments	$	34	$	—	$	131	$	—

See Item 1. Financial Statements – Note 2. Basis of Presentation, Note 4. Asset Impairments and Note 7. Fair Value Measurements and Disclosures.

Other (Income) Expense

Other (income) expense was as follows:



	Three Months Ended June 30,					Six Months Ended June 30,
(millions)	2014		2013			2014		2013
(Gain) Loss on Commodity Derivative Instruments	$	236	$	(161	)	$	311	$	(89	)
Interest, Net of Amount Capitalized	52		33			99		58
Other Non-Operating Expense, Net	8		3			13		12
Total	$	296	$	(125	)	$	423	$	(19	)

(Gain) Loss on Commodity Derivative Instruments (Gain) Loss on commodity derivative instruments is a result of mark-to-market accounting. Many factors impact a gain or loss on commodity derivative instruments including: increases and decreases in the commodity forward price curves compared to our executed hedging arrangements; increases in hedged future volumes; and the mix of hedge arrangements between NYMEX WTI, Dated Brent and NYMEX Henry Hub commodities. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities and Note 7. Fair Value Measurements and Disclosures.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
(millions, except unit rate)
Interest Expense, Gross	$	78		$	68		$	159		$	135
Capitalized Interest	(26		)	(35		)	(60		)	(77		)
Interest Expense, Net	$	52		$	33		$	99		$	58
Unit Rate per BOE ⁽¹⁾	$	2.01		$	1.44		$	1.95		$	1.31

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

The increase in interest expense, gross, is due to the issuance of new senior debt in November 2013 and recent borrowings under our Credit Facility.

The decrease in capitalized interest is primarily due to the completion of longer cycle time major projects, such as Alen, offshore West Africa, and Tamar, offshore Israel, and the current concentration of development activity onshore US, which has more rapid well construction time, partially offset by higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and offshore Israel.

Income Tax Provision

See Item 1. Financial Statements – Note 11. Income Taxes for a discussion of the change in our effective tax rate for the second quarter and first six months of 2014 as compared with 2013.

Discontinued Operations

The North Sea geographical segment is reflected as discontinued operations for the first six months of 2013. During first quarter 2014, the remaining unsold North Sea assets were reclassified to held and used, and their operations are included in continuing operations for 2014.

Summarized results of discontinued operations were as follows:



	Three Months Ended June 30,			Six Months Ended June 30,
		2013			2013
(millions)
Oil and Gas Sales		$	12		$	21
Expenses		7			17
Income Before Income Taxes		5			4
Income Tax Expense		3			10
Operating (Income) Loss, Net of Tax		2			(6		)
Gain on Sale, Net of Tax		17			55
Income From Discontinued Operations		$	19		$	49

Key Statistics:
Daily Production
Crude Oil & Condensate (MBbl/d)		1			1
Natural Gas (MMcf/d)		3			3
Average Realized Price
Crude Oil & Condensate (Per Bbl)		$	103.21		$	107.63
Natural Gas (Per Mcf)		11.40			10.63

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. Divestitures.

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LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the volatile commodity price cycle. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a robust exploration program and maintaining capacity to capitalize on financially attractive periodic mergers and acquisitions activity.

We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering competitive returns and a growing dividend. We utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business.

We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our Credit Facility, and proceeds from sales of non-core properties. We may also access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Credit Facility or to refinance scheduled debt maturities. On April 15, 2014, we repaid $200 million of scheduled current maturities. See Item 1. Financial Statements – Note 6. Debt and Credit Facility, below.

Expanded development in the DJ Basin and Marcellus Shale, investment in our recently sanctioned major development projects, and our planned exploration and appraisal drilling activities are estimated to result in near term capital expenditures exceeding cash flows from operating activities. The extent to which capital investment will exceed operating cash flows depends on our success in sanctioning future development projects, the results of our exploration activities, and new business opportunities as well as external factors such as commodity prices, among others. Our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity.

To support our investment program, we expect that higher production resulting from our core onshore US development programs combined with new production from Tamar, which began producing in late first quarter 2013, and Alen, which began producing in late second quarter 2013, will result in an increase in cash flows which will be available to meet a substantial portion of future capital commitments.

Cash on hand at June 30, 2014 totaled $958 million, and includes both domestic and foreign cash. We consider repatriating foreign cash to increase our financial flexibility and fund our capital investment program to the extent such cash is not required to fund foreign investment projects and would not incur material US tax. During the first six months of 2014, we repatriated $519 million from our UK operations. We will not incur material US tax on these repatriations.

We also evaluate potential strategic farm-out arrangements of our working interests in Israel, Cyprus, Cameroon, Nicaragua and the deepwater Gulf of Mexico for reimbursement of our capital spending in these areas. In addition, our current liquidity level and balance sheet, along with our ability to access the capital markets, provide flexibility. We believe that we are well-positioned to fund our long-term growth plans.

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 technical and financial challenges for us due to the large-scale development requirements. Potential development scenarios may include the construction of subsea pipeline, floating LNG, LNG terminals, FPSO or other options. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. We are currently considering various project finance alternatives for Leviathan.

Marcellus Shale Joint Venture Our joint venture arrangement with a subsidiary of CONSOL Energy, Inc. is structured in a manner to address partner alignment and financial affordability. Under the arrangement, we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs up to a fixed amount. See Contractual Obligations, below.

Pension Plan Termination We are in the process of terminating our defined benefit pension plan (pension plan). We expect to liquidate the associated pension obligation through lump-sum payments to participants or the purchase of annuities on their behalf. As of December 31, 2013, the latest actuarial measurement date for the pension plan, the accumulated benefit obligation totaled $315 million, and the fair value of plan assets was $265 million.

At March 31, 2014, we reclassified the long-term portion of the net pension plan liability to current, as we expect final plan termination to occur by the end of first quarter 2015. We expect to make additional contributions to the plan during the period leading up to final termination and distribution to the extent necessary to fund these obligations. In addition, upon termination

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of the pension plan, all unamortized prior service cost and net actuarial loss remaining in AOCL will be charged to expense. This amount totaled approximately $98 million as of June 30, 2014.

In coordination with the termination of the pension plan, we also amended our restoration plan to freeze the accrual of benefits effective December 31, 2013. Payments under the restoration plan will continue to be made in ordinary course without acceleration. Restoration plan participants who remain employed by us upon final liquidation and distribution of assets of the pension plan may elect to have the lump sum present value of their restoration plan benefits converted into an account balance under our nonqualified deferred compensation plan.

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



	June 30,			December 31,
	2014			2013
(millions, except percentages)
Cash and Cash Equivalents	$	958		$	1,117
Amount Available to be Borrowed Under Credit Facility ⁽¹⁾	3,400			4,000
Total Liquidity	$	4,358		$	5,117
Total Debt ⁽²⁾	$	5,237		$	4,843
Total Shareholders' Equity	9,554			9,184
Ratio of Debt-to-Book Capital ⁽³⁾	35		%	35		%


⁽¹⁾	See Credit Facility, below.


⁽²⁾	Total debt includes capital lease and other obligations and excludes unamortized debt 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 $958 million in cash and cash equivalents at June 30, 2014, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $859 million of this cash is attributable to our foreign subsidiaries and a portion would be subject to US income taxes if repatriated.

Credit Facility Our Credit Facility matures on October 3, 2018. The commitment is $4.0 billion through the maturity date of the Credit Facility. As of June 30, 2014, we had drawn $600 million under the Credit Facility to fund increased development activities. The weighted average interest rate on the borrowings was 1.41%. Borrowings under our Credit Facility subject us to interest rate risk. See Item 1. Financial Statements –Note 6. Debt and Item 3. Quantitative and Qualitative Disclosures.

Commodity Derivative Instruments We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments may include variable to fixed price commodity swaps, two-way collars, and/or three-way collars.

Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. We net settle by counterparty based on netting provisions within the master agreements. None of our counterparty agreements contain margin requirements.

Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of June 30, 2014, the fair value of our commodity derivative assets was $2 million and the fair value of our commodity derivative liabilities was $288 million (after consideration of netting provisions within our master agreements). See Item 1. Financial Statements –Note 7. Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of commodity derivative instruments and Credit Risk, below.

Credit Risk We monitor the creditworthiness of our 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 or liquidity problems. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major development projects. 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. A partner's inability to obtain financing could result in a delay of our joint development projects. For example, our Eastern Mediterranean partners must obtain financing for their share of significant development expenditures at Leviathan, offshore Israel, which potentially includes an LNG project and/or major underwater pipeline.

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

Contractual Obligations

CONSOL Carried Cost Obligation The 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 a multi-year period and is capped at $400 million in each calendar year. The obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices.

Due to past low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 to February 28, 2014. Due to recent increases in Henry Hub natural gas prices, we began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014.

Based on the June 30, 2014, NYMEX Henry Hub natural gas price curve and current development plans, we forecast we will incur approximately $240 million under the CONSOL Carried Cost Obligation for 2014. The carry will be suspended again if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any future three consecutive month period.

Marcellus Shale Firm Transportation Agreements In February 2014, we signed Precedent Agreements for Firm Transportation to move 150,000 MMBtu per day of our Marcellus Shale natural gas production to Gulf Coast markets. Our financial commitment is approximately $765 million, undiscounted, over a 15-year period, beginning in 2017.

Cash Flows

Cash flow information is as follows:



	Six Months Ended June 30,
	2014			2013
(millions)
Total Cash Provided By (Used in)
Operating Activities	$	1,757		$	1,244
Investing Activities	(2,215		)	(1,835		)
Financing Activities	299			(90		)
Decrease in Cash and Cash Equivalents	$	(159	)	$	(681	)

Operating Activities Net cash provided by operating activities for the first six months of 2014 increased as compared with 2013. Higher crude oil and natural gas sales prices and an increase in crude oil and natural gas sales volumes were offset by increases in production expenses and general and administrative expense. Working capital changes contributed $105 million of positive operating cash flow in the first six months of 2014 as compared with a negative impact of $168 million in the first six months of 2013.

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, including farm-in arrangements, which may result in reimbursement for capital spending that had occurred in prior periods. Capital spending for property, plant and equipment increased by $392 million during the first six months of 2014 as compared with 2013, primarily due to increased major project development activity in our core areas. We also invested $40 million in CONE Gathering LLC (CONE), discussed below, during the first six months of 2014. We received $146 million in proceeds from non-core asset divestitures during the first six months of 2014, as compared with $114 million during the same period in 2013.

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 six months of 2014, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($58 million) and net cash proceeds from our Credit Facility ($600 million). We used cash to pay dividends on our common stock ($116 million), to repay Senior Notes that were due April 15, 2014 ($200 million), make principal payments related to capital lease obligations ($28 million) and repurchase shares of our common stock ($15 million).

In comparison, during the first six months of 2013, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($43 million). We also used cash to pay dividends on our common stock ($96 million), make

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principal payments related to the Aseng FPSO capital lease obligation ($23 million) and repurchase shares of our common stock ($14 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 June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition ⁽¹⁾	$	74	$	97	$	129	$	134
Exploration	138		197		228		385
Development⁽²⁾	989		749		1,736		1,374
Corporate and Other	43		89		90		124
Total	$	1,244	$	1,132	$	2,183	$	2,017

Other
Investment in Equity Method Investee ⁽³⁾	$	28	$	3	$	40	$	23
Increase in Capital Lease Obligations	16		31		21		36


⁽¹⁾	Unproved property acquisition cost for 2014 includes $37 million in the DJ Basin, $75 million in the Marcellus Shale, and $16 million in the deepwater Gulf of Mexico. Unproved property acquisition cost for 2013 includes $73 million in the DJ Basin, $47 million in the Marcellus Shale, and $12 million in the deepwater Gulf of Mexico.


⁽²⁾	Development expenditures for 2014 include drilling rig mobilization charges of $55 million, a portion of which will be billed to partners in future periods as the rig is utilized.


⁽³⁾	Investment in equity method investees represents funding of our investment in CONE which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture.

Total expenditures increased in 2014 as compared with 2013 due to accelerated activity in the DJ Basin and Marcellus Shale.

Financing Activities

Long-Term Debt Our principal source of liquidity is our Credit Facility that matures October 3, 2018. At June 30, 2014, $600 million was outstanding under the Credit Facility, leaving $3.4 billion available for use. We expect to use the Credit Facility to fund our capital investment program, and may periodically borrow amounts for working capital purposes. See Item 1 Financial Statements – Note 6. Debt.

Our outstanding fixed-rate debt (excluding capital lease and other obligations) totaled approximately $4.3 billion at June 30, 2014. The weighted average interest rate on fixed-rate debt was 6.09%, with maturities ranging from March 2019 to August 2097. On April 15, 2014, we repaid $200 million of matured fixed rate debt.

Dividends We paid total cash dividends of 32 cents per share of our common stock during the first six months of 2014 and 27 cents per share during the first six months of 2013 (as adjusted for the 2-for-1 stock split during the second quarter of 2013).

On July 22, 2014, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid August 18, 2014 to shareholders of record on August 4, 2014. 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 $41 million during the first six months of 2014 and $31 million during the first six months of 2013.

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 250,013 shares with a value of $15 million during the first six months of 2014 and 247,985 shares with a value of $14 million during the first six months of 2013.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes We are exposed to market risk in the normal course of business operations, and the 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 June 30, 2014, we had entered into variable to fixed price commodity swaps and three-way collars 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 liability position with a fair value of $286 million. Based on the June 30, 2014 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would increase the fair value of our net commodity derivative liability by approximately $41 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $10 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. Derivative Instruments and Hedging Activities.

Interest Rate Risk

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

At June 30, 2014, we had approximately $4.9 billion (excluding capital lease and other obligations) of long-term debt outstanding. Of this amount, $4.3 billion was fixed-rate debt with a weighted average interest rate of 6.09%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss.

The remainder of our long-term debt, $600 million at June 30, 2014, was variable-rate debt. Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to the June 30, 2014 balance of our variable-rate debt would result in a change in annual interest expense of approximately $2 million.

We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of June 30, 2014, our cash and cash equivalents totaled approximately $958 million, approximately 40% 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 June 30, 2014 would result in a change in annual interest income of approximately $1 million.

Foreign Currency Risk

The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as taxes payable in foreign tax jurisdictions, are settled in the foreign local 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.

Net transaction gains and losses were de minimis for the second quarter and the first six months of both 2014 and 2013.

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.

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;

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•	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 those 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 in our Annual Report on Form 10-K for the year ended December 31, 2013, 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, 2013 is available on our website at www.nobleenergyinc.com.

Item 4. Controls and Procedures

Based on the evaluation of our disclosure controls and procedures by 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

West Virginia Matter In March 2013, we received seven Notices of Violation (NOV) and two Administrative Orders (Orders) from the West Virginia Department of Environmental Protection Office of Oil and Gas (OOG) regarding the unintentional discharge of a mixture of freshwater and produced water that occurred on or about the evening of February 22, 2013 from one of our permitted water storage facilities in Marshall County, West Virginia. At this time, the OOG has not established a proposed penalty for these NOVs or Orders. Given the uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the 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.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2013.

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

The following table sets forth, for the periods indicated, our 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)
4/1/2014 - 4/30/2014	1,345	$	73.46	—	—
5/1/2014 - 5/31/2014	833	70.95		—	—
6/1/2014 - 6/30/2014	507	76.08		—	—
Total	2,685	$	73.17	—	—


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

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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

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Signatures

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



		NOBLE ENERGY, INC.
		(Registrant)

Date	July 24, 2014	/s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer

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Index to Exhibits



Exhibit Number		Exhibit

3.1		Certificate of Incorporation of the Registrant (as amended through April 23, 2013), filed as Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 and incorporated herein by reference.

3.2		By-Laws of Noble Energy, Inc. (as amended through April 23, 2013), filed as Exhibit 3.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 and incorporated herein by reference.

12.1		Calculation of ratio of earnings to fixed charges, filed herewith.

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