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 ~~September 30, 2014~~March 31, 2015

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 ~~September 30, 2014~~March 31, 2015, there were ~~361,856,652~~387,004,520 shares of the registrant’s common stock,

par value $0.01 per share, outstanding.

~~Table of Contents~~

Table of Contents



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	2321

Item 3. Quantitative and Qualitative Disclosures About Market Risk	4138

Item 4. Controls and Procedures	4339

Part II. Other Information	4440

Item 1. Legal Proceedings	4440

Item 1A. Risk Factors	4440

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4440

Item 3. Defaults Upon Senior Securities	4541

Item 4. Mine Safety Disclosures	4541

Item 5. Other Information	4541

Item 6. Exhibits	4541

Signatures	4642

Index to Exhibits	4743

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

Noble Energy, Inc.

Consolidated Statements of Operations

(millions, except per share amounts)

(unaudited)


	Three Months Ended September 30,					Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013		2014			2013			2015			2014
Revenues
Oil, Gas and NGL Sales	$	1,228		$	1,341	$	3,893		$	3,537		$	740		$	1,327
Income from Equity Method Investees	41			53		138			150			18			52
Other												1			—
Total	1,269			1,394		4,031			3,687			759			1,379
Costs and Expenses
Production Expense	217			221		697			619			245			229
Exploration Expense	217			60		350			211			65			74
Depreciation, Depletion and Amortization	460			412		1,297			1,146			454			425
General and Administrative	132			109		399			324			94			140
Gain on Divestitures	(30		)	—		(72		)	(12		)
Asset Impairments	33			63		164			63			27			97
Other Operating Expense, Net	10			6		33			27			8			10
Total	1,039			871		2,868			2,378			893			975
Operating Income	230			523		1,163			1,309
Operating Income (Loss)												(134		)	404
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments	(385		)	157		(74		)	69			(150		)	75
Interest, Net of Amount Capitalized	52			46		151			104			57			47
Other Non-Operating (Income) Expense, Net	(13		)	9		1			21			1			5
Total	(346		)	212		78			194			(92		)	127
Income from Continuing Operations Before Income Taxes	576			311		1,085			1,115
Income Tax Provision	157			116		274			330
Income from Continuing Operations	419			195		811			785
Discontinued Operations, Net of Tax	—			10		—			58
Net Income	$	419		$	205	$	811		$	843
Income (Loss) Before Income Taxes												(42		)	277
Income Tax (Benefit) Provision												(20		)	77
Net Income (Loss)												$	(22	)	$	200

Earnings Per Share, Basic
Income from Continuing Operations	$	1.16		$	0.54	$	2.25		$	2.19
Discontinued Operations, Net of Tax	—			0.03		—			0.16
Net Income	$	1.16		$	0.57	$	2.25		$	2.35
Earnings Per Share, Diluted
Income from Continuing Operations	$	1.12		$	0.53	$	2.21		$	2.17
Discontinued Operations, Net of Tax	—			0.03		—			0.16
Net Income	$	1.12		$	0.56	$	2.21		$	2.33
Earnings (Loss) Per Share, Basic												$	(0.06	)	$	0.56
Earnings (Loss) Per Share, Diluted												$	(0.06	)	$	0.55

Weighted Average Number of Shares Outstanding
Basic	362			359		361			359			370			360
Diluted	367			363		367			363			370			365

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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2014			2013			2015			2014
Net Income	$	419		$	205		$	811		$	843
Net Income (Loss)													$	(22	)	$	200
Other Items of Comprehensive Income
Net Change in Mutual Fund Investment													(11		)	1
Less Tax Benefit													3			—
Net Change in Pension and Other	6			4			16			15			1			4
Less Tax Benefit	(2		)	(1		)	(6		)	(5		)	—			(2		)
Other Comprehensive Income	4			3			10			10
Comprehensive Income	$	423		$	208		$	821		$	853
Other Comprehensive Income (Loss)													(7		)	3
Comprehensive Income (Loss)													$	(29	)	$	203

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

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Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)


	September 30, 2014			December 31, 2013			March 31, 2015			December 31, 2014
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,169		$	1,117		$	1,709		$	1,183
Accounts Receivable, Net	740			947			769			857
Commodity Derivative Assets, Current							661			710
Other Current Assets	361			547			259			325
Total Current Assets	2,270			2,611			3,398			3,075
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	24,465			22,243			26,337			25,599
Property, Plant and Equipment, Other	618			517			684			630
Total Property, Plant and Equipment, Gross	25,083			22,760			27,021			26,229
Accumulated Depreciation, Depletion and Amortization	(7,325		)	(7,035		)	(8,559		)	(8,086		)
Total Property, Plant and Equipment, Net	17,758			15,725			18,462			18,143
Goodwill	620			627			617			620
Other Noncurrent Assets	538			679			784			715
Total Assets	$	21,186		$	19,642		$	23,261		$	22,553
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	1,425		$	1,354		$	1,269		$	1,578
Other Current Liabilities	807			988			874			944
Total Current Liabilities	2,232			2,342			2,143			2,522
Long-Term Debt	5,498			4,566			6,113			6,103
Deferred Income Taxes, Noncurrent	2,464			2,441			2,491			2,516
Other Noncurrent Liabilities	1,054			1,109			1,157			1,087
Total Liabilities	11,248			10,458			11,904			12,228
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
Common Stock - Par Value $0.01 per share; 500 Million Shares Authorized; 428 Million and 402 Million Shares Issued, respectively							4			4
Additional Paid in Capital	3,593			3,463			4,761			3,624
Accumulated Other Comprehensive Loss	(107		)	(117		)	(97		)	(90		)
Treasury Stock, at Cost; 38 Million Shares	(674		)	(659		)	(683		)	(671		)
Retained Earnings	7,122			6,493			7,372			7,458
Total Shareholders’ Equity	9,938			9,184			11,357			10,325
Total Liabilities and Shareholders’ Equity	$	21,186		$	19,642		$	23,261		$	22,553

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)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014
Cash Flows From Operating Activities
Net Income	$	811		$	843
Net Income (Loss)							$	(22	)	$	200
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,297			1,148			454			425
Asset Impairments	164			63			27			97
Dry Hole Cost	163			22			20			2
Deferred Income Taxes	61			168			(30		)	17
Income from Equity Method Investees, Net of Dividends	53			(12		)	(18		)	(13		)
(Gain) Loss on Commodity Derivative Instruments	(74		)	69			(150		)	75
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	(95		)	(2		)	210			(33		)
Gain on Divestitures	(72		)	(67		)
Stock Based Compensation	67			59			21			23
Other Adjustments for Noncash Items Included in Income	42			63			11			18
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable	166			(260		)
Increase in Accounts Payable	103			63
Increase (Decrease) in Current Income Taxes Payable	21			(48		)
Increase (Decrease) in Other Current Assets and Liabilities, Net	16			(7		)
Other Noncurrent Operating Assets and Liabilities, Net	(20		)	51
Decrease in Accounts Receivable							107			28
Increase (Decrease) in Accounts Payable							(71		)	57
Increase in Current Income Taxes Payable							3			47
Decrease in Other Current Assets and Liabilities, Net							(51		)	(24		)
Other Operating Assets and Liabilities, Net							30			10
Net Cash Provided by Operating Activities	2,703			2,153			541			929
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(3,585		)	(3,021		)	(1,111		)	(1,158		)
Additions to Equity Method Investments	(58		)	(30		)	(44		)	(12		)
Distribution from Equity Method Investee	156			—
Proceeds from Divestitures	312			119			119			92
Other	—			(5		)
Net Cash Used in Investing Activities	(3,175		)	(2,937		)	(1,036		)	(1,078		)
Cash Flows From Financing Activities
Exercise of Stock Options	45			39			4			10
Excess Tax Benefits from Stock-Based Awards	18			15			—			6
Dividends Paid, Common Stock	(182		)	(146		)	(64		)	(50		)
Purchase of Treasury Stock	(15		)	(14		)	(12		)	(15		)
Proceeds from Credit Facilities	900			800
Repayment of CONSOL Installment Loan	—			(328		)
Repayment of Senior Notes	(200		)	—
Proceeds from Issuance of Shares of Common Stock to Public, Net of Offering Costs							1,112			—
Proceeds from Credit Facility, Net							—			450
Repayment of Capital Lease Obligation	(42		)	(31		)	(19		)	(15		)
Net Cash Provided by Financing Activities	524			335			1,021			386
Increase (Decrease) in Cash and Cash Equivalents	52			(449		)
Increase in Cash and Cash Equivalents							526			237
Cash and Cash Equivalents at Beginning of Period	1,117			1,387			1,183			1,117
Cash and Cash Equivalents at End of Period	$	1,169		$	938		$	1,709		$	1,354

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		Additional Paid in Capital		Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Total Shareholders' Equity
December 31, 2014																	$	4	$	3,624	$	(90	)	$	(671	)	$	7,458		$	10,325
Net (Loss)																	—		—		—			—			(22		)	(22		)
Stock-based Compensation																	—		21		—			—			—			21
Exercise of Stock Options																	—		4		—			—			—			4
Dividends (18 cents per share)																	—		—		—			—			(64		)	(64		)
Changes in Treasury Stock, Net																	—		—		—			(12		)	—			(12		)
Issuance of Shares of Common Stock to Public, Net of Offering Costs																	—		1,112		—			—			—			1,112
Net Change in Pension and Other																	—		—		(7		)	—			—			(7		)
March 31, 2015																	$	4	$	4,761	$	(97	)	$	(683	)	$	7,372		$	11,357
	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		$	4	$	3,463	$	(117	)	$	(659	)	$	6,493		$	9,184
Net Income	—				—			—			811			811			—		—		—			—			200			200
Stock-based Compensation	—		67		—			—			—			67			—		23		—			—			—			23
Exercise of Stock Options	—		45		—			—			—			45			—		10		—			—			—			10
Tax Benefits Related to Exercise of Stock Options	—		18		—			—			—			18			—		6		—			—			—			6
Dividends (50 cents per share)	—		—		—			—			(182		)	(182		)
Dividends (14 cents per share)																	—		—		—			—			(50		)	(50		)
Changes in Treasury Stock, Net	—		—		—			(15		)	—			(15		)	—		—		—			(15		)	—			(15		)
Net Change in Pension and Other	—		—		10			—			—			10			—		—		3			—			—			3
September 30, 2014	$	4	$	3,593	$	(107	)	$	(674	)	$	7,122		$	9,938

December 31, 2012	$	4	$	3,302	$	(113	)	$	(648	)	$	5,713		$	8,258
Net Income	—		—		—			—			843			843
Stock-based Compensation	—		59		—			—			—			59
Exercise of Stock Options	—		39		—			—			—			39
Tax Benefits Related to Exercise of Stock Options	—		15		—			—			—			15
Dividends (41 cents per share)	—		—		—			—			(146		)	(146		)
Changes in Treasury Stock, Net	—		—		—			(14		)	—			(14		)
Net Change in Pension and Other	—		—		10			—			—			10
September 30, 2013	$	4	$	3,415	$	(103	)	$	(662	)	$	6,410		$	9,064
March 31, 2014																	$	4	$	3,502	$	(114	)	$	(674	)	$	6,643		$	9,361


⁽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 ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 and for the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 and ~~2013~~2014 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. Certain prior-period amounts have been reclassified to conform to the current-period presentation. Operating results for the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2014~~2015.

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~~2014.

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.

Equity ~~Investees~~ OfferingOn September 24, 2014, our equity method investee, CONE Gathering LLC (CONE Gathering), contributed substantially all of its assets to a newly-formed master limited partnership, CONE Midstream Partners LP (CONE Midstream), concurrently withMarch 3, 2015, we closed an ~~initial~~underwritten public offering of ~~limited partner units. CONE Gathering subsequently made~~21,000,000 shares of common stock, par value $0.01 per share, at a ~~cash distribution~~price to the public of ~~$204~~$47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3,150,000 shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and estimated offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving credit facility and the remainder will be used for general corporate purposes, including the funding of our capital investment program.

Increase in Authorized Shares On April 28, 2015, our stockholders approved an amendment to our Certificate of Incorporation to increase the number of authorized shares of our common stock from 500 million to 1 billion.

Update on Core Area – Israel In March 2014, we and our partners reached an agreement with the Israel Antitrust Authority on various matters (Consent Decree). The Consent Decree, which was subject to final approval by the Antitrust Tribunal, granted the rights, to us ~~which is reflected within cash flows~~and our partners, to jointly market natural gas from ~~operating activities ($48 million) and cash flows from investing activities ($156 million) within our consolidated statement of cash flows. As~~the Leviathan field. Also, as a result of the ~~transaction,~~Consent Decree, we ~~own a 32.1% interest in CONE Midstream, which~~agreed to divest our Tanin and Karish natural gas discoveries.

However, on December 23, 2014, we ~~account for using the equity method of accounting.~~

~~Discontinued Operations~~ ~~In 2012, we initiated a strategy to exit the North Sea geographical area through sales of~~and our ~~non-operated working interests~~partners in the ~~assets. The North Sea geographical segment~~Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. This is a matter that we believed was ~~classified as held for sale~~resolved some time ago and we had received assurances from the ~~operations were reflected as discontinued operations in 2012~~Antitrust Authority that approval was forthcoming. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and ~~2013.~~await final disposition.

~~The most significant North Sea assets were sold during 2012~~In the meantime, negotiations are ongoing with the Antitrust Authority and ~~2013. However, we have been unable to locate purchasers~~with an inter-ministerial working group, established by the Prime Minister's office for the ~~remaining assets,~~purpose of agreeing to a comprehensive regulatory framework for investment. We remain prepared to implement the Consent Decree if agreed with the Antitrust Authority but in any case, expect that divestiture of Tanin 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 the first, second, and third 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 nine months ended September 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~~Karish will be ~~effected in the form~~part of a ~~stock dividend. The stock dividend was distributed on~~ ~~May 28, 2013~~final regulatory settlement. We therefore continue 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.~~hold these assets for sale.

Recently Issued Accounting Standards In April ~~2014,~~2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. ~~2014-08:~~2015-03 (ASU 2015-03): Simplifying the 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 isDebt Issuance Costs, effective for annual and interim periods beginning after December 15, ~~2014. Early adoption~~2015. ASU 2015-03 requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. It is ~~permitted~~effective retrospectively for ~~disposals~~first quarter 2016 and is only expected to impact the presentation of our consolidated balance sheet. As of March 31, 2015 and December 31, 2014, we had $48 million and $50 million of capitalized, unamortized debt issuance costs, respectively.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-02 changes the guidance as to whether an entity is a variable interest entity (VIE) or ~~for assets classified as held for sale that~~a voting interest entity and how related parties

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

are considered in the VIE model. We are currently evaluating the provisions of ASU 2015-02 and assessing the impact, if any, it may 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.~~position and results of operations.

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,

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~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

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. In April 2015, the FASB proposed to delay the effective date for one year, for annual reporting periods beginning after December 15, 2017. The proposal will be subject to the FASB's due process requirement. We are currently evaluating the provisions of ASU 2014-09 and ~~assessing~~awaiting implementation guidance to determine 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 September 30,						Nine Months Ended September 30,					Three Months Ended March 31,
(millions)	2014			2013			2014		2013			2015			2014
Production Expense
Lease Operating Expense	$	133		$	137		$	432	$	393		$	157		$	142
Production and Ad Valorem Taxes	44			51			146		137			32			49
Transportation and Gathering Expense	40			33			119		89			56			38
Total	$	217		$	221		$	697	$	619		$	245		$	229
Other Operating (Income) Expense, Net
Midstream Gathering and Processing Expense												$	4		$	3
Other, Net												4			7
Total												$	8		$	10
Other Non-Operating (Income) Expense, Net
Deferred Compensation (Income) Expense ⁽¹⁾	$	(12	)	$	10		$	—	$	24
Deferred Compensation Expense ⁽¹⁾												$	2		$	4
Other (Income) Expense, Net	(1		)	(1		)	1		(3		)	(1		)	1
Total	$	(13	)	$	9		$	1	$	21		$	1		$	5


⁽¹⁾	Amounts represent increases ~~(decreases)~~ 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)	September 30, 2014			December 31, 2013			March 31, 2015			December 31, 2014
Accounts Receivable, Net
Commodity Sales	$	345		$	495		$	303		$	405
Joint Interest Billings	310			382			343			297
Other	101			81			140			171
Allowance for Doubtful Accounts	(16		)	(11		)	(17		)	(16		)
Total	$	740		$	947		$	769		$	857
Other Current Assets
Inventories, Materials and Supplies	$	95		$	96		$	89		$	81
Inventories, Crude Oil	28			25			28			24
Commodity Derivative Assets	79			1
Deferred Income Taxes, Net	5			62
Assets Held for Sale	98			292
Assets Held for Sale⁽¹⁾							106			180
Prepaid Expenses and Other Current Assets	56			71			36			40
Total	$	361		$	547		$	259		$	325
Other Noncurrent Assets
Equity Method Investments	$	290		$	437		$	384		$	325
Mutual Fund Investments	121			114			112			111
Commodity Derivative Assets	32			16			169			180
Other Assets	95			112			119			99
Total	$	538		$	679		$	784		$	715
Other Current Liabilities
Production and Ad Valorem Taxes	$	110		$	103		$	119		$	110
Commodity Derivative Liabilities	—			65
Income Taxes Payable	183			156			182			180
Deferred Income Taxes, Current							151			158
Accrued Benefit Costs, Current							109			125
Asset Retirement Obligations	155			39			81			81
Interest Payable	56			63			83			70
Current Portion of Long Term Debt	—			200
Current Portion of Capital Lease	67			58
Liabilities Associated with Assets Held for Sale	12			111
Current Portion of Capital Lease Obligations							65			68
Other	224			193			84			152
Total	$	807		$	988		$	874		$	944
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	264		$	253		$	224		$	218
Asset Retirement Obligations	543			547			706			670
Accrued Benefit Costs	108			155			23			24
Commodity Derivative Liabilities	—			10
Other	139			144			204			175
Total	$	1,054		$	1,109		$	1,157		$	1,087

⁽¹⁾Assets held for sale includes $76 million related to our Tanin and Karish natural gas discoveries, offshore Israel. See Update on Core Area – Israel, above.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 3. Divestitures

Onshore US Properties During the first ~~nine~~three months of ~~2014~~,2015, we sold certain ~~non-core~~ onshore US crude oil and natural gas ~~properties. The information~~leases. Properties sold generated net proceeds of $119 million, which were applied to the DJ Basin depletable field, with no recognition of gain or loss.

Information regarding ~~the~~ assets sold during the first three months of 2014 is as follows:


	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(millions)	2014						2014
Sales Proceeds	$	16		$	126		$	92
Less
Net Book Value of Assets Sold	—			(118		)	(106		)
Goodwill Allocated to Assets Sold	(1		)	(7		)	(6		)
Asset Retirement Obligations Associated with Assets Sold	14			34			20
Other Closing Adjustments	1			2			(1		)
Gain on Divestitures	$	30		$	37		$	(1	)

On October 23, 2014, we closed the sale of our non-core onshore US properties in the Piceance Basin of western Colorado, with net proceeds of $9 million. These properties were reclassified as held for sale at September 30, 2014, and written down to expected proceeds less costs to sell which resulted in an impairment charge of $31 million. See ~~Note 4. Asset ImpairmentsandNote7. Fair Value Measurements and Disclosures~~.

In October 2014, we signed a purchase and sale agreement related to certain of our properties located on the western side of the DJ Basin, outside of our core DJ Basin operating area. The sale is expected to close in late 2014, with net proceeds of approximately $145 million.

~~China~~ ~~On June 30, 2014, we closed the sale of our China assets. The information regarding the China assets sold is as follows:~~

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

~~Offshore Israel Properties~~ Assets held for sale as of September 30, 2014, include two natural gas discoveries, Tanin and Karish, 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 nine 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:~~

Nine Months Ended
September 30,
(millions) 2013
Oil and Gas Sales $ 32
Income Before Income Taxes 10
Income Tax Expense 7
Operating Loss, Net of Tax 3
Gain on Sale, Net of Tax 55
Discontinued Operations, Net of Tax $ 58

~~Table of Contents~~

~~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
September 30, Nine Months Ended
September 30,
(millions) 2014 2013 2014 2013
Deepwater Gulf of Mexico (US Properties) $ 2
$ 16
$ 25
$ 16
Piceance Basin (US Properties) 31
—
31
—
Mari-B (Offshore Israel) —
47
14
47
McCulloch and Other North Sea Properties —
—
94
—
Total $ 33
$ 63
$ 164
$ 63



	Three Months Ended March 31,
(millions)	2015		2014
Deepwater Gulf of Mexico	3		—
Eastern Mediterranean	24		—
North Sea	—		92
Non-Core US Property	—		5
Total	$	27	$	97

~~US and Offshore Israel~~ ~~During the third quarter of 2014, we reclassified our non-core onshore US properties in the Piceance Basin as assets held~~Impairments for ~~sale. The assets~~2015 were ~~written down~~related to ~~expected proceeds less~~facility costs ~~to sell.~~

~~During the first nine months of 2014, the asset carrying values of certain oil and natural gas assets in the deepwater~~at South Raton (Deepwater Gulf of ~~Mexico~~Mexico) and ~~offshore Israel 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~~for the ~~working interest owners that it would begin working with the appropriate regulatory agency~~Noa and Pinnacles fields (Eastern Mediterranean).

Impairments for ~~approval of cessation of production and subsequent~~2014 were primarily related to an increase in expected 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~~a change in the ~~asset for impairment and determined that it was impaired. The impairment charge was included in consolidated income from continuing operations.~~timing of abandonment activities at the MacCulloch North Sea field.

See Note 2. Basis of Presentation ~~and~~, Note 7. Fair Value Measurements and Disclosures and Note9. Asset Retirement Obligations.

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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 decreases in commodity prices, ~~or increases in interest rates,~~ they may also curtail benefits from future increases in commodity ~~prices or decreases in interest rates.~~prices. 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 ~~September 30, 2014~~March 31, 2015, we had entered into the following crude oil derivative instruments:


				Swaps		Collars									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		Type of Contract	Index	Bbls Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of September 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
Instruments Entered Into as of March 31, 2015												Instruments Entered Into as of March 31, 2015
2015												Swaps	NYMEX WTI	27,000	$	88.80	$	—	$	—	$	—
2015	Swaps	NYMEX WTI	27,000	88.80		—		—		—		Swaps	Dated Brent	8,000	100.31		—		—		—
2015	Swaps	Dated Brent	8,000	100.31		—		—		—		Two-Way Collars	NYMEX WTI	5,000	—		—		50.00		64.94
2015	Three-Way Collars	NYMEX WTI	20,000	—		70.50		87.55		94.41		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		Three-Way Collars	Dated Brent	13,000	—		76.92		96.00		108.49
2016	Swaps	NYMEX WTI	6,000	87.95		—		—		—		Swaps	NYMEX WTI	6,000	87.95		—		—		—
2016	Swaps	Dated Brent	9,000	97.96		—		—		—		Swaps	Dated Brent	9,000	97.96		—		—		—
2016	Three-Way Collars	NYMEX WTI	3,000	—		72.00		85.00		94.82		Three-Way Collars	NYMEX WTI	6,000	—		61.00		72.50		86.37
2016	Three-Way Collars	Dated Brent	6,000	—		80.00		95.00		105.87		Three-Way Collars	Dated Brent	8,000	—		72.50		86.25		101.79


⁽¹⁾	~~West Texas Intermediate~~

As of ~~September 30, 2014~~March 31, 2015, we had entered into the following natural gas derivative instruments:


				Swaps		Collars									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		Type of Contract	Index	MMBtu Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of September 30, 2014
2014	Swaps	NYMEX HH	60,000	$	4.24	$	—	$	—	$	—
2014	Three-Way Collars	NYMEX HH	230,000	—		2.83		3.75		4.98
Instruments Entered Into as of March 31, 2015												Instruments Entered Into as of March 31, 2015
2015	Swaps	NYMEX HH	140,000	4.30		—		—		—		Swaps	NYMEX HH	140,000	$	4.30	$	—	$	—	$	—
2015	Three-Way Collars	NYMEX HH	150,000	—		3.58		4.25		5.04		Three-Way Collars	NYMEX HH	150,000	—		3.58		4.25		5.04
2016												Swaps ⁽¹⁾	NYMEX HH	40,000	3.60		—		—		—
2016												Two-Way Collars	NYMEX HH	30,000	—		—		3.00		3.50
2016												Three-Way Collars	NYMEX HH	60,000	—		2.88		3.50		4.03

⁽¹⁾

~~Henry Hub~~We have entered into natural gas derivative contracts which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 30,000 MMBtu/d are exercisable on December 22 and 23, 2016. If the counterparties exercise all such options, the notional volume of our existing natural gas derivative contracts will increase by 30,000 MMBtu/d at an average price of $3.50 per MMBtu for each month during the period January 1, 2017 through December 31, 2017.

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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						Asset Derivative Instruments						Liability Derivative Instruments
	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013			March 31, 2015			December 31, 2014			March 31, 2015			December 31, 2014
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments	Current Assets	$	79	Current Assets	$	1	Current Liabilities	$	—	Current Liabilities	$	65	Current Assets	$	661	Current Assets	$	710	Current Liabilities	$	—	Current Liabilities	$	—
	Noncurrent Assets	32		Noncurrent Assets	16		Noncurrent Liabilities	—		Noncurrent Liabilities	10		Noncurrent Assets	169		Noncurrent Assets	180		Noncurrent Liabilities	—		Noncurrent Liabilities	—
Total		$	111		$	17		$	—		$	75		$	830		$	890		$	—		$	—

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

Three Months Ended
September 30, Nine Months Ended
September 30,
(millions) 2014 2013 2014 2013
(Gain) Loss on Commodity Derivative Instruments
   Crude Oil $ (360 ) $ 167
$ (68 ) $ 99
   Natural Gas (25 ) (10 ) (6 ) (30 )
Total (Gain) Loss on Commodity Derivative Instruments (385 ) 157
(74 ) 69
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
  Crude Oil 14
24
87
39
  Natural Gas (2 ) (14 ) 8
(37 )
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments 12
10
95
2
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
   Crude Oil (374 ) 143
(155 ) 60
   Natural Gas (23 ) 4
(14 ) 7
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments $ (397 ) $ 147
$ (169 ) $ 67

~~AOCL~~ ~~Accumulated other comprehensive loss (AOCL) at~~ ~~September 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.~~



	Three Months Ended March 31,
(millions)	2015				2014
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	(185	)		$	27
Natural Gas	(25		)		6
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(210		)	��	33
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	55				28
Natural Gas	5				14
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	60				42
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(130		)		55
Natural Gas	(20		)		20
Total (Gain) Loss on Commodity Derivative Instruments	$	(150	)		$	75

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 6. Debt

Debt consists of the following:


	September 30, 2014					December 31, 2013					March 31, 2015					December 31, 2014
(millions, except percentages)	Debt			Interest Rate		Debt			Interest Rate		Debt			Interest Rate		Debt			Interest Rate
Credit Facility, due October 3, 2018	$	900		1.43	%	$	—		—	%	$	—		—	%	$	—		—	%
Capital Lease and Other Obligations	399			—		359			—		419			—	%	413			—	%
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	%
8.25% 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	%	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	%
7.25% Senior Notes, due October 15, 2023											100			7.25	%	100			7.25	%
3.90% Senior Notes, due November 15, 2024											650			3.90	%	650			3.90	%
8.00% Senior Notes, due April 1, 2027											250			8.00	%	250			8.00	%
6.00% Senior Notes, due March 1, 2041											850			6.00	%	850			6.00	%
5.25% Senior Notes, due November 15, 2043											1,000			5.25	%	1,000			5.25	%
5.05% Senior Notes, due November 15, 2044											850			5.05	%	850			5.05	%
7.25% Senior Debentures, due August 1, 2097											84			7.25	%	84			7.25	%
Total	5,583					4,843					6,203					6,197
Unamortized Discount	(18		)			(19		)			(25		)			(26		)
Total Debt, Net of Discount	5,565					4,824					6,178					6,171
Less Amounts Due Within One Year
5¼% Senior Notes, due April 15, 2014, net of discount ⁽¹⁾	—					(200		)
Capital Lease Obligations	(67		)			(58		)			(65		)			(68		)
Long-Term Debt Due After One Year	$	5,498				$	4,566				$	6,113				$	6,103


⁽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.

~~Table of Contents~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements~~

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

Table of Contents

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														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			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)
September 30, 2014
March 31, 2015
Financial Assets
Mutual Fund Investments	$	121		$	—		$	—	$	—		$	121		$	112		$	—		$	—	$	—		$	112
Commodity Derivative Instruments	—			117			—		(6		)	111			—			832			—		(2		)	830
Financial Liabilities
Commodity Derivative Instruments	—			(6		)	—		6			—			—			(2		)	—		2			—
Portion of Deferred Compensation Liability Measured at Fair Value	(181		)	—			—		—			(181		)	(137		)	—			—		—			(137		)
December 31, 2013
December 31, 2014
Financial Assets
Mutual Fund Investments	$	114		$	—		$	—	$	—		$	114		$	111		$	—		$	—	$	—		$	111
Commodity Derivative Instruments	—			28			—		(11		)	17			—			890			—		—			890
Financial Liabilities
Commodity Derivative Instruments	—			(86		)	—		11			(75		)	—			—			—		—			—
Portion of Deferred Compensation Liability Measured at Fair Value	(176		)	—			—		—			(176		)	(134		)	—			—		—			(134		)


⁽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										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		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 September 30, 2014
Three Months Ended March 31, 2015											Three Months Ended March 31, 2015
Impaired Oil and Gas Properties	$	—	$	—	$	9	$	42	$	33	$	—	$	—	$	—	$	27	$	27
Three Months Ended September 30, 2013
Three Months Ended March 31, 2014											Three Months Ended March 31, 2014
Impaired Oil and Gas Properties	—		—		75		138		63		—		—		6		103		97
Nine Months Ended September 30, 2014
Impaired Oil and Gas Properties	$	—	$	—	$	23	$	187	$	164
Nine Months Ended September 30, 2013
Impaired Oil and Gas Properties	—		—		75		138		63

⁽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~~2015 impairments were due primarily 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~~estimated abandonment activities. Third quarter 2014 impairments related primarily to our non-core onshore properties in the Piceance Basin, which were reclassified as assets held for sale. The assets were written down to expected proceeds less costs to sell.costs. 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 September 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:


	September 30, 2014				December 31, 2013				March 31, 2015				December 31, 2014
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total Debt, Net of Unamortized Discount ⁽¹⁾	$	5,166	$	5,805	$	4,465	$	4,959	$	5,759	$	6,385	$	5,758	$	6,179


⁽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)	Nine Months Ended September 30, 2014			Three Months Ended March 31, 2015
Capitalized Exploratory Well Costs, Beginning of Period	$	1,301		$	1,337
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	274			59
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale	(186		)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves				(6		)
Capitalized Exploratory Well Costs Charged to Expense ⁽¹⁾	(85		)	(17		)
Capitalized Exploratory Well Costs, End of Period	$	1,304		$	1,373

⁽¹⁾~~Capitalized exploratory wells costs charged~~ Relates to ~~expense primarily represent the Scotia exploratory well, offshore Falkland Islands, which was determined to be non-commercial.~~onshore US exploration activity.

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)	September 30, 2014		December 31, 2013		March 31, 2015		December 31, 2014
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	307	$	568	$	272	$	247
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	997		733		1,101		1,090
Balance at End of Period	$	1,304	$	1,301	$	1,373	$	1,337
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	12		13		13		13

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

The following table ~~provides a further aging of those~~includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of ~~September 30, 2014~~March 31, 2015:


			Suspended Since
(millions)	Total		2012 - 2013		2010 - 2011		2009 & Prior		Progress	Total by Project		Progress
Country/Project:
Onshore US
Northeast Nevada										$	26	Analyzing results from our first four exploratory vertical wells and evaluating potential for production tests.
Deepwater Gulf of Mexico
Troubadour	$	44	$	44	$	—	$	—	Evaluating development scenarios for this 2013 natural gas discovery	47		Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
Offshore Equatorial Guinea
Diega (including Carmen)	161		56		52		53		Evaluating regional development scenarios for this 2008 crude oil discovery
Offshore Equatorial Guinea (Blocks O and I)
Diega/Carmen										221		Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks O and I and are engaged in processing the newly-acquired seismic data.
Carla	150		138		12		—		Evaluating regional development scenarios for this 2011 crude oil discovery	154		Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks O and I and are engaged in processing the newly-acquired seismic data.
Felicita	38		3		6		29		Evaluating regional development plans for this 2008 condensate and natural gas discovery	39		Evaluating regional development plans for this 2008 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.
Yolanda	19		2		3		14		Evaluating regional development plans for this 2007 condensate and natural gas discovery	20		Evaluating regional development plans for this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.
Offshore Cameroon
YoYo	47		4		9		34		Working with the government to assess commercialization of this 2007 condensate and natural gas discovery	48		Working with the government to assess commercialization of this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.
Offshore Israel
Offshore Israel ⁽¹⁾
Leviathan	181		71		110		—		Submitted a development plan to the Israeli government; finalizing front-end engineering and design (FEED) work; continuing marketing activities with potential natural gas customers	185		During 2014, we received the Leviathan Development and Production Leases, submitted a development plan to the government, completed substantial engineering and procurement activities and engaged in natural gas marketing activities.
Leviathan-1 Deep	77		50		27		—		Well did not reach the target interval; developing future drilling plans to test this deep oil concept	79		Well did not reach the target interval; developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. We are working on potential well design and placement.
Dalit	26		4		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	25		3		22		—		Reviewing regional development scenarios for this 2011 natural gas discovery
Offshore Cyprus
Cyprus	188		131		57		—		Discussing monetization options with the Cyprus government for this 2011 natural gas discovery
Other
Projects less than $20 million	41		31		4		6		Continuing to drill and evaluate wells
Total	$	997	$	537	$	304	$	156

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Noble Energy, Inc.

Notes to Consolidated Financial Statements



Dalit	28		Submitted a development plan to the government to develop this 2009 natural gas discovery as a tie-in to existing infrastructure.
Dolphin 1	25		Reviewing regional development scenarios for this 2011 natural gas discovery, including a potential tieback to Leviathan. We have applied to the Israeli government for a commerciality ruling.
Offshore Cyprus
Cyprus	203		Discussing monetization options with the Cyprus government for this 2011 natural gas discovery. In May 2014, our application for renewal of the PSC for two additional years was approved. We plan to submit a plan of development to the government in 2015.
Other
Individual Projects Less than $20 million	26		Continuing to drill and evaluate wells.
Total	$	1,101

⁽¹⁾ We are currently working to resolve antitrust and other regulatory matters with the Israeli government to enable Leviathan and other development to move forward. See Note 2. Basis of Presentation – Update on Core Area – Israel.

Note 9. Asset Retirement Obligations

~~ARO~~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:


	Nine Months Ended September 30,						Three Months Ended March 31,
(millions)	2014			2013			2015			2014
Asset Retirement Obligations, Beginning Balance	$	586		$	402		$	751		$	586
Liabilities Incurred	38			4			10			1
Liabilities Settled	(77		)	(15		)	(8		)	(14		)
Revision of Estimate	123			5			24			72
Accretion Expense ⁽¹⁾	28			21			10			10
Asset Retirement Obligations, Ending Balance	$	698		$	417		$	787		$	655

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

For the three months ended March 31, 2015

Liabilities incurred were due to new wells and facilities and included $4 million for onshore US and $6 million for deepwater Gulf of Mexico. Liabilities settled in 2015 relate primarily to non-core US properties classified as held for sale.

Revisions in estimate for 2015 relate to changes in cost estimates for Eastern Mediterranean.

For thethree months ended March 31, 2014

Liabilities settled in 2014 include $24 million for onshore US and deepwater Gulf of Mexico abandonments and $17 million related to properties classified as held for sale, offset by $27 million as a result of reclassifying remaining North Sea assets from held for sale to held and used.

Revision in estimate for 2014 included an increase of $67 million related to the non-operated MacCulloch North Sea field due to an increase in costs and a change in timing. See Note 3. Divestitures.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

~~For the nine months ended September 30, 2014~~

~~Liabilities incurred were due to new wells and facilities and included $13 million for onshore US, $16 million for deepwater Gulf of Mexico, and $9 million for Eastern Mediterranean.~~

Liabilities settled primarily related to onshore US property abandonments and non-core, onshore US assets sold. At December 31, 2013, our non-operated North Sea fields were classified as held for sale, which included the related ARO for these fields. During 2014, we reclassified the remaining, unsold North Sea properties as held and used. The North Sea field ARO of $24 million is recorded within liabilities settled.

~~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 $9 million for deepwater Gulf of Mexico.

~~For the nine months ended September 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
September 30, Nine Months Ended
September 30,
(millions, except per share amounts) 2014 2013 2014 2013
Income from Continuing Operations $ 419
$ 195
$ 811
$ 785
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust ⁽¹⁾
(8 ) —
—
—
Income from Continuing Operations Used for Diluted Earnings Per Share Calculation $ 411
$ 195
$ 811
$ 785

Weighted Average Number of Shares Outstanding, Basic 362
359
361
359
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust 5
4
6
4
Weighted Average Number of Shares Outstanding, Diluted 367
363
367
363
Earnings from Continuing Operations Per Share, Basic $ 1.16
$ 0.54
$ 2.25
$ 2.19
Earnings from Continuing Operations Per Share, Diluted 1.12
0.53
2.21
2.17
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 2
4
3
5



	Three Months Ended March 31,
(millions, except per share amounts)	2015			2014
Net Income (Loss)	$	(22	)	$	200

Weighted Average Number of Shares Outstanding, Basic ⁽¹⁾	370			360
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust ⁽²⁾	—			5
Weighted Average Number of Shares Outstanding, Diluted	370			365
Earnings (Loss) Per Share, Basic	$	(0.06	)	$	0.56
Earnings (Loss) Per Share, Diluted	(0.06		)	0.55
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	9			6


⁽¹⁾	The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24,150,000 shares of common stock of the Company in first quarter 2015.

~~Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are~~⁽²⁾

For the three months ended March 31, 2015, all outstanding options and non-vested restricted shares have been excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the three and nine months ended September 30, 2014 exclude deferred compensation (gains) losses, net of tax. The deferred compensation loss, net of tax, excluded for the calculation of diluted ~~earnings per share~~EPS as the Company incurred a loss for the ~~nine months ended September 30, 2014~~ ~~was de minimis.~~quarter. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted EPS would be anti-dilutive.

~~Table of Contents~~

~~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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
(millions)	2014			2013			2014			2013			2015			2014
Current	$	120		$	53		$	213		$	161		$	10		$	60
Deferred	37			63			61			169			(30		)	17
Total Income Tax Provision	$	157		$	116		$	274		$	330
Total Income Tax (Benefit) Provision													$	(20	)	$	77
Effective Tax Rate	27.2		%	37.2		%	25.3		%	29.6		%	47.6		%	27.6		%

Our effective tax rate (ETR) for the three ~~and nine~~ months ended ~~September 30, 2014 decreased~~March 31, 2015 increased as compared with the three ~~and nine~~ months ended ~~September 30, 2013~~March 31, 2014 primarily ~~due to~~as a result of a tax benefit divided by a pre-tax loss. In the case of a pre-tax loss, our ~~ability to benefit~~favorable permanent differences, such as income from ~~previously unrecognized foreign tax credits,~~equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, ~~and a decrease~~have the effect of increasing the tax benefit which, in ~~our Israeli oil profits tax. Additionally, in July 2013,~~turn, increases the Israeli government increased the corporate income tax rate from 25% to 26.5%. The change increased the deferred tax expense for 2013, which resulted in a higher rate for the three months ended September 30, 2013 as compared to the same period of 2014.ETR.

In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2011, Equatorial Guinea – 2009 and Israel – ~~2009.~~

~~See Note~~ ~~3. Divestitures~~ ~~for income taxes associated with discontinued operations.~~2010.

2019

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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, Sierra Leone, and Gabon); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 30, 2014), Falkland Islands, Nicaragua and new ventures. ~~The North Sea geographical segment is included in continuing operations in 2014 and discontinued operations in 2013.~~ Income (loss) from continuing operations before income taxes for the United States and West Africa includes gains and losses on commodity derivative instruments.


(millions)	Consolidated			United States			West Africa		Eastern Mediterranean		Other Int'l & Corporate			Consolidated			United States			West Africa			Eastern Mediterranean		Other Int'l & Corporate
Three Months Ended September 30, 2014
Three Months Ended March 31, 2015
Revenues from Third Parties														$	740		$	478		$	138		$	120	$	4
Income from Equity Method Investees														18			11			7			—		—
Gathering, Marketing and Processing														1			1			—			—		—
Total Revenues														759			490			145			120		4
DD&A														454			357			77			15		5
Asset Impairments														27			3			—			24		—
Gain on Commodity Derivative Instruments														(150		)	(105		)	(45		)	—		—
Income (Loss) Before Income Taxes														(42		)	(1		)	74			51		(166		)
Three Months Ended March 31, 2014
Revenues from Third Parties	$	1,228		$	819		$	269	$	138	$	2		$	1,327		$	842		$	323		$	112	$	50
Income from Equity Method Investees	41			—			41		—		—			52			—			52			—		—
Total Revenues	1,269			819			310		138		2			1,379			842			375			112		50
DD&A	460			351			70		17		22			425			308			76			14		27
Gain on Divestitures	(30		)	(30		)	—		—		—
Asset Impairments	33			33			—		—		—			97			5			—			—		92
Income (Loss) from Continuing Operations Before Income Taxes	576			457			321		90		(292		)
Three Months Ended September 30, 2013
Revenues from Third Parties	$	1,341		$	810		$	372	$	122	$	37
Income from Equity Method Investees	53			—			53		—		—
Total Revenues	1,394			810			425		122		37
DD&A	412			295			72		26		19
Gain on Divestitures	—			—			—		—		—
Asset Impairments	63			16			—		47		—
Income (Loss) from Continuing Operations Before Income Taxes	311			183			223		34		(129		)
Nine Months Ended September 30, 2014
Revenues from Third Parties	$	3,893		$	2,503		$	931	$	363	$	96
Income from Equity Method Investees	138			—			138		—		—
Total Revenues	4,031			2,503			1,069		363		96
DD&A	1,297			970			218		46		63
Gain on Divestitures	(72		)	(36		)	—		—		(36		)
Asset Impairments	164			56			—		14		94
Income (Loss) from Continuing Operations Before Income Taxes	1,085			838			786		211		(750		)
Nine Months Ended September 30, 2013
Revenues from Third Parties	$	3,537		$	2,209		$	935	$	274	$	119
Income from Equity Method Investees	150			—			150		—		—
Total Revenues	3,687			2,209			1,085		274		119
DD&A	1,146			819			189		81		57
Gain on Divestitures	(12		)	(12		)	—		—		—
Asset Impairments	63			16			—		47		—
Income (Loss) from Continuing Operations Before Income Taxes	1,115			746			722		93		(446		)
September 30, 2014
Loss on Commodity Derivative Instruments														75			76			(1		)	—		—
Income (Loss) from Before Income Taxes														277			183			261			77		(244		)
March 31, 2015
Total Assets	$	21,186		$	15,069		$	2,930	$	2,855	$	332		$	23,261		$	16,998		$	2,732		$	2,840	$	691
December 31, 2013
December 31, 2014
Total Assets	19,598			13,094			3,199		2,753		552			22,553			16,400			2,763			2,806		584

~~Table of Contents~~

~~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 remaining obligation totaled approximately $1.6 billion at March 31, 2015.

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 equal or exceed $4.00 per MMBtu for three consecutive months. ~~Due~~The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 until February 28, 2014. We began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014.prices. Based on the ~~September 30, 2014~~March 31, 2015 NYMEX Henry Hub natural gas price curve, ~~and current development plans,~~ we ~~forecast we will incur approximately $185 million under~~expect that the CONSOL Carried Cost Obligation will be suspended for the ~~year ended December 31, 2014.~~

~~Marcellus Shale Firm Transportation Agreements~~ During 2014, we signed Precedent Agreements for Firm Transportation (the Agreements) to flow 445,000 MMBtu per day of our Marcellus Shale natural gas production to various markets. The Agreements 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 2017 and 2018. Our financial commitment totals approximately $1.2 billion, undiscounted, over a 15-year period. Final agreements are subject to various conditions, including regulatory approval of the pipeline extension projects.next 12 months.

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~~attractive 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, ~~Gabon,~~ the Falkland Islands, Cameroon, and ~~Cyprus.~~Gabon.

~~Our financial results~~Significant Operating Highlights Included:

record total sales volumes of 318 MBoe/d, an 11% increase over first quarter 2014;

record quarterly US onshore horizontal volumes of 96 MBoe/d;

deepwater Gulf of Mexico major projects remain on schedule and on budget;

first gas sales and purchase agreement for ~~third~~ ~~quarter~~ ~~2014~~ ~~included:~~regional export of Eastern Mediterranean natural gas approved;

planning for upcoming exploration opportunities offshore the Falkland Islands and Cameroon; and

a decision to exit our position in Nicaragua following detailed future prospect review.

First Quarter 2015 Financial Results Included:

net ~~income~~loss of $~~419~~22 million, as compared with ~~$205~~net income of $200 million for ~~third~~first quarter ~~2013~~2014;

engagement in cost reduction initiatives, including both operational enhancements and new pricing arrangements with service partners, which we expect will decrease capital and operating costs through the year;

net gain on commodity derivative instruments of ~~$385~~$150 million (including ~~$397~~$60 million non-cash ~~portion of~~ ~~gain~~)loss) as compared with a net loss on commodity derivative instruments of ~~$157~~$75 million (including ~~$147~~$42 million non-cash ~~portion of~~ ~~loss~~)loss) for ~~third~~first quarter ~~2013~~2014;

~~dry hole expense of~~ ~~$161 million, as compared with~~ ~~third~~ ~~quarter~~ ~~2013, which was de minimis;~~

asset impairment charges of ~~$33~~$27 million, as compared with ~~$63~~$97 million for ~~third~~first quarter ~~2013;~~2014;

diluted loss per share of $0.06, as compared with diluted earnings per share of ~~$1.12, as compared with $0.56~~$0.55 for ~~third~~first quarter ~~2013~~2014;

cash flow provided by operating activities of ~~$946~~$541 million, as compared with ~~$909~~$929 million for ~~third~~first quarter ~~2013~~2014; and

capital expenditures (accrual based) of $919 million, as compared with $951 million for first quarter 2014.

Significant Events Impacting Liquidity Included:

net cash proceeds of $1.1 billion received from public offering of shares of common stock.

Quarter-End Key Financial Metrics Included:

ending cash balance of $~~1.2~~1.7 billion, as compared with ~~$1.1~~$1.2 billion at December 31, ~~2013~~2014;

~~capital spending, on a cash basis, of $1.1 billion, as compared with $1.1 billion for the~~ ~~third~~ ~~quarter 2013;~~

~~net increase in our unsecured revolving credit facility (Credit Facility) balance of $300 million;~~

~~cash distributions of $204 million received from CONE Gathering LLC (CONE Gathering);~~

total liquidity of ~~$4.3~~$5.7 billion at ~~September 30, 2014,~~March 31, 2015, as compared with ~~$5.1~~$5.2 billion at December 31, ~~2013;~~2014; and

ratio of debt-to-book capital of ~~36%~~35% at ~~September 30, 2014,~~March 31, 2015, as compared with ~~35%~~38% at December 31, ~~2013~~2014.

~~Our operating results for~~ ~~third~~Commodity Price Changes ~~quarter~~ ~~2014~~ ~~included:~~

~~formed a master limited partnership with CONSOL Energy Inc. (CONSOL) for our jointly owned midstream assets in the Marcellus Shale~~The upstream oil and ~~completed the initial public offering;~~

~~announced successful final well results at the Katmai exploratory well and at the Dantzler-2 appraisal well located in the deepwater Gulf of Mexico;~~

~~signed a regional export Letter of Intent (LOI) for~~gas business is cyclical. During 2014, natural gas ~~sales from Leviathan~~prices declined steadily, and, during fourth quarter 2014, a significant decline in crude oil prices occurred. During first quarter 2015, crude oil and average realized natural gas prices continued to ~~National Electric Power Company of Jordan; and~~

~~entered into~~decline. As a ~~new position offshore West Africa in Gabon.~~

result, our consolidated average realized crude oil price

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decreased 54% and our consolidated average realized natural gas price decreased 27% for first quarter 2015 as compared with first quarter 2014.

We are unable to predict the extent to which commodity prices may recover during 2015. Prices are likely to remain volatile and could decline further. In addition, we could be entering a period of sustained, lower worldwide crude oil prices.

We plan for these cyclical downturns in our business and feel we are well positioned to withstand current and future commodity price volatility:

we have a high-quality, diversified portfolio of assets which provide investment flexibility;

we have positive operating cash flow (revenues less cash operating expenses), prior to capital expenditures, in each of our core areas;

we have designed a substantially-reduced capital investment program which will allow us to respond to conditions that occur in 2015;

we are well hedged, with approximately 60% of global crude oil and 50% of domestic natural gas production hedged for 2015, with additional quantities hedged into 2016;

we have a strong balance sheet with a ratio of debt-to-book capital of 35% at March 31, 2015; and

we have robust liquidity with total liquidity of $5.7 billion at March 31, 2015.

See Operating Outlook – 2015 Capital Investment Program below.

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) During the quarter, we drilled 57 horizontal wells and commenced production on 48 wells, including 17 extended reach lateral wells. Third-party compression, natural gas processing and transportation capacity continue to expand.

Marcellus Shale (Onshore US) During the quarter, we drilled 15 operated wells, and commenced production on three operated wells. Our joint venture partner drilled 25 wells and 29 dry gas wells commenced production.

Gunflint (Deepwater Gulf of Mexico) Development is on track for the Gunflint (31% operated working interest) crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar 1 spar platform. The drilling rig is currently performing development work at Gunflint. Topsides equipment fabrication is underway for installation in 2015 through early 2016, and first production is targeted for mid-2016.

Big Bend and Dantzler (Deepwater Gulf of Mexico) A co-development project is underway for the Big Bend (54% operated working interest) and Dantzler (45% operated working interest) crude oil discoveries, located in the Rio Grande area of the deepwater Gulf of Mexico, which will tie back to the Thunder Hawk semi-submersible production facility. All drilling and completion activities are complete, and development work is progressing on schedule. First production for Big Bend is targeted for fourth quarter 2015, and first production for Dantzler is targeted for end of 2015.

Tamar Compression (Onshore Israel) The Tamar compression project is near completion. The compression is targeted to increase deliverability at Tamar to approximately 1.2 Bcf/d, gross, beginning in mid-2015.

Tamar Southwest We continue 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 maintain well capacity and reliability for our overall Tamar project.

Unsanctioned Development Projects

Tamar Expansion Project (Offshore Israel) We have engaged in the planning phase for an expansion project which would expand Tamar field deliverability to approximately 2.0 Bcf/d. Timing of project sanction depends on satisfactory resolution of antitrust and other regulatory matters. See Update on Core Area – Israel, below.

Leviathan Project (Offshore Israel) In 2014, we submitted the Plan of Development to the Ministry of National Infrastructures, Energy and Water Resources. The development plan is expected to serve both domestic demand and export. Timing of project sanction depends on satisfactory resolution of antitrust and other regulatory matters, as well as execution of natural gas sales and purchase agreements (GSPAs), which will be subject to, among other conditions, the receipt of regulatory

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approvals. Project financing will also be required. We are engaged with the governments of the US, Israel, Jordan and Egypt on this project. See Update on Core Area – Israel, below.

Cyprus Project (Offshore Cyprus) We are currently evaluating development scenarios for Block 12 and plan to submit a plan of development to the Cypriot government in 2015. There is also potential for a farm-out arrangement of our working interest.

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

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 ~~September 30, 2014~~March 31, 2015 (See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs), and expect to ~~continue an active~~conduct additional exploratory ~~drilling program in the future.~~activities.

A portion of our ~~2014~~2015 capital investment program is dedicated to exploration and associated appraisal ~~activities, including seismic and leasehold acquisitions.~~activities. 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 recorded as dry hole 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 two exploratory vertical wells and conducting a production test. In third quarter 2014, we commenced drilling a third exploratory well and plan to drill additionalhave drilled four exploratory wells into date. Further testing is required to assess commercial viability, and we are preparing to conduct production testing of the third well during second quarter 2015. Currently, no exploratory drilling is planned for the remainder of 2015.

Deepwater Gulf of Mexico InWe currently have an inventory of identified prospects, which are a combination of both high impact subsalt prospects and smaller, high value tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options. We are actively assessing exploration and appraisal drilling activity necessary to test the resource potential of our Katmai discovery from third quarter 2014 ~~we announced successful final well results at the Katmai exploratory well~~ (Green Canyon Block 40, 50% operated working interest). We anticipate drilling a Katmai appraisal well in the deepwater Gulf of Mexico. Katmai was drilled to a total depth of 27,900 feet in 2,100 feet of water. Wireline logging data indicated a total of 154 net feet of crude oil pay discovered in multiple reservoirs, including 117 net feet in Middle Miocene and 37 net feet in Lower Miocene reservoirs. Additional exploration and appraisal drilling will be required to test the remaining resource potential.2016.

We participated with a 50% non-operated working interest in the Bright prospect, which was drilled on Atwater Valley Block 362 to a total depth of 13,500 feet during the third quarter 2014. The exploratory well reached the targeted Upper and Middle Miocene objectives and was subsequently plugged and abandoned as we did not encounter hydrocarbons. As a result, we recorded $79 million dry hole cost in the third quarter of 2014.

~~In the fourth quarter 2014, we plan to drill the Madison prospect (Mississippi Canyon 479), where we have a 60% working interest.~~

Offshore West Africa We are currently ~~acquiring~~processing the results of recently-acquired 3D seismic data across Blocks O and I ~~offshore Equatorial Guinea,~~which will aid in advancing other regional exploration and development opportunities, including Diega/Carmen and Carla.

During first quarter, the Government of Cameroon approved a farmout of a portion of our working interest in the Tilapia PSC to Woodside Energy, Ltd. We remain the operator (46.67% working interest) and plan to drill the Cheetah exploration prospect in the second half of 2015. We are also reprocessing 3D seismic data over our YoYo mining ~~concession, offshore Cameroon.~~

In August 2014, we expanded our exploration portfolio by signing a Production Sharing Contract (PSC) with the Government of Gabon covering Block F15. Block F15 is located in the Gabon Coastal Basin and covers over 670,000 gross acres. The PSC includes a 4-year seismic commitment and an option for exploration drilling. We have a 60% operated working interest.concession.

Offshore Eastern Mediterranean ~~We are processing and evaluating recently acquired 3D seismic data over offshore~~See Update on Core Area – Israel, ~~and Cyprus and continue to study locations for potential exploratory wells, with opportunities offshore in Israel and Cyprus.~~below.

Offshore Falkland Islands We anticipate drilling operations to begin ~~in mid-2015~~ at the Humpback ~~our~~prospect (35% operated ~~prospect~~working interest), located in the ~~Fitzroy sub-basin~~South Falkland Basin, in May 2015. In addition, we recently acquired a 75% interest and operatorship of the ~~Southern Area License.~~PL001 License in the North Falkland Basin. The PL001 License covers an area of nearly 285,000 gross acres. We ~~are currently finalizing locations for a second exploratory well, planned for later in 2015 following results at Humpback. We operate our Southern Area licenses with a 35% working interest.~~

~~Based~~have identified the Rhea prospect as the initial target on the ~~results of seismic interpretation conducted on the Scotia exploratory well which was drilled~~PL001 License and expect to commence drilling in ~~2012, we have concluded that the Scotia prospect is not economically viable. As a result, we recorded $73 million dry hole expense during~~ third quarter ~~2014.~~2015.

Argentine officials have recently filed charges against Noble and other oil and gas companies operating offshore the Falkland Islands. We believe the charges have no merit. Our concessions are offshore the Falkland Islands and our concession contracts are with the Falkland Islands Government.

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~~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 an extensive level of horizontal drilling activity with continued growth from 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 75 horizontal wells, of which 22 were extended reach lateral wells, and 68 wells initiated production. Our 2014 drilling program includes over 90 extended reach lateral wells. Currently, nine drilling rigs are active across the basin.

~~Marcellus Shale (Onshore US)~~ We continue to delineate the wet gas acreage, while our partner, CONSOL, continues to develop the dry gas acreage. During the quarter, we and our partner drilled 50 wells, and 37 wells initiated production. The joint venture is currently operating eight drilling rigs.

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.

On September 24, 2014, our jointly-owned equity method investee, CONE Gathering, contributed substantially all of its assets to a newly-formed master limited partnership, CONE Midstream Partners LP (CONE Midstream). CONE Gathering subsequently made a cash distribution of $204 million to each of us and CONSOL. In addition, we and CONSOL each own a 32.1% interest in CONE Midstream. CONE Midstream will own, operate, and develop our jointly-owned natural gas midstream assets in the Marcellus Shale.

~~Gunflint (Deepwater Gulf of Mexico)~~ Development is on track for the Gunflint crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar 1 spar platform. Topsides equipment fabrication is underway for planned 2015 installation, and we are targeting first production for mid-2016.

~~Big Bend and Dantzler (Deepwater Gulf of Mexico)~~ A co-development project is underway for the Big Bend (54% operated working interest) and Dantzler (45% operated working interest) crude oil discoveries, located in the Rio Grande area of the deepwater Gulf of Mexico.

During third quarter 2014, we announced final well results at the Dantzler-2 appraisal well, located in Mississippi Canyon 782, which encountered 122 net feet of crude oil pay in two high-quality Miocene reservoirs. The well was drilled to a total depth of 18,210 feet in 6,600 feet of water.

We recently signed a production handling agreement for tie back to the Thunder Hawk semi-submersible production facility. First production for Big Bend is targeted for fourth quarter 2015, and first production for Dantzler is targeted for first quarter 2016.

~~Tamar Expansion (Offshore Israel)~~ The Tamar compression project is ongoing. De-bottlenecking of the Tamar facilities has increased current peak production deliverability at Tamar to more than 1.1 Bcf/d, gross. Additional progress was made at the Ashdod onshore terminal, which brings the project to approximately 80% complete. The expansion is targeted to increase deliverability at Tamar to 1.2 Bcf/d, gross, beginning in mid-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 maintain well capacity and reliability for our overall Tamar project.

~~In May 2014, we announced that we had entered into a non-binding 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 September 30, 2014)~~

~~Leviathan (Offshore Israel)~~ We have 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.

We have submitted the Plan of Development for the initial phase of development of Leviathan to the Ministry of Energy and Water Resources. The initial phase of development is planned to include a 1.6 Bcf/d Floating, Production, Storage, and Offloading (FPSO) vessel, with initial sales targeted to begin in early 2018 at 75% of total FPSO capacity.

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We have also entered into two non-binding LOIs for the supply of natural gas from the Leviathan field. In June 2014, we announced an LOI to supply natural gas to existing LNG facilities in Egypt. In September 2014, we announced an LOI to supply natural gas to the National Electric Power Company of Jordan. We are working towards final gas purchase and sales agreements, which will be subject to, among other conditions, the receipt of regulatory approvals. We are engaged with the governments of the US, Israel, Jordan and Egypt.

~~Project financing discussions are underway, and we are targeting to sanction Phase 1 in 2015.~~

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

~~Cyprus Project (Offshore Cyprus)~~ ~~We are currently evaluating development scenarios in Cyprus. 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 will incorporate the results of our 3D seismic data acquisition across Blocks O and I. A natural gas sales agreement has been executed by the Block O and I partners to sell dedicated natural gas from the Alen field to the proposed Integrated Petrochemical Complex in Equatorial Guinea.

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

Non-Core Divestiture Program

We have continued our non-core asset divestiture program with the sale of ~~our China assets as well as~~ certain smaller onshore US property packages during the first ~~nine~~three months of ~~2014. In addition we closed the sale of our Piceance Basin properties in October 2014.~~2015. 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.

Colorado Air Matter

In August 2013, we received an information request from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our DJ Basin operations. The information request relates to our compliance with certain regulatory requirements at those locations, including air emissions of volatile organic compounds in a marginal ozone non-attainment area. We responded to the EPA’s information requests between November 2013 and April 2014 and, in April 2015, reached a settlement with the EPA and the State of Colorado regarding potential noncompliance with the Clean Air Act, Colorado's State Implementation Plan, Colorado's Air Pollution Prevention and Control Act and its implementation regulations. See Part II. Other Information – Item 1. Legal Proceedings.

Update on Core Area – Israel

Noble Energy and its partners have been committed to providing natural gas to Israeli citizens for over a decade. We have delivered approximately 1.3 Tcf, gross, of natural gas to Israeli customers, including the government-owned Israel Electric Corporation (IEC), the largest supplier of electricity in the country.

Since obtaining our first exploration license in 1998, Noble Energy has been the first, and only, oil and natural gas company to successfully explore for significant amounts of hydrocarbons in Israel. We are ~~currently winding up local business~~also the first company to construct, operate and produce from a major development project offshore Israel. We have invested significant amounts of capital in exploration and development activities ~~in countries of former operations. At~~since 1998. Throughout this time, we ~~do not believe that any~~have focused on partnering with our customers and the Israeli government to provide a reliable fuel source at reasonable prices to support affordable energy for the country’s citizens.

Since our initial discovery at Mari-B in 2000, we and our partners have continued to reinvest for long-term growth, leasing additional acreage and conducting exploration activities offshore Israel, in pursuit of additional resources to meet increasing demand from Israeli consumers and global markets. Our exploration efforts resulted in numerous natural gas discoveries over the past several years. The Tamar and Leviathan discoveries, in particular, are large scale, high quality reservoirs, of global significance, providing substantial additional resources for the government and citizens of Israel. We developed the Tamar field, with a discovery to production cycle time of approximately four years, which is exceptionally fast by historical industry standards for an offshore natural gas project of this magnitude and complexity.

The quantity of discovered resources at Tamar and Leviathan have positioned Israel to meet domestic needs for years to come and eventually become a significant natural gas exporter. Multiple regional markets are emerging and Israel’s domestic demand is predicted to continue to grow over the next decade. Eastern Mediterranean export projects would be well positioned to supply growing regional and global natural gas demand, which would provide benefits beyond satisfying domestic consumption of natural gas. In fact, we have been working with potential customers to supply natural gas through a regional pipeline system and/or LNG facilities. Government export royalties and tax revenues related to regional export sales would provide material financial benefit for Israel’s citizens.

In addition to our natural gas discoveries, the Levant Basin also has potential for large scale crude oil discoveries, which may exist at greater depths. We have conducted preliminary exploration activities ~~associated~~and have been planning to complete our test of two deeper intervals.

We have been working with ~~these areas will~~the Israeli government on plans to develop the Leviathan field and expand the currently-producing Tamar field. However, the regulatory environment in Israel has become increasingly challenging and uncertain. Laws, regulations and guidelines have ~~a material effect~~been modified, sometimes with retroactive impacts, resulting in an unpredictable investment climate. Timing of approval for development plans has been delayed, and consequently our ability to make significant, long-term investment decisions has been stymied.

Since 2011, following the discovery of Leviathan, we have been engaged with the Israeli government, including the Antitrust Commissioner, to reach agreement on various antitrust matters resulting from our ~~financial position, results of operations or cash flows.~~

~~Update on Israel's Natural Gas Economy~~

~~Israel Antitrust Authority~~significant resource ownership status. During 2014, we and our partners reached an agreement with the Israeli government on ~~various~~the antitrust matters (Consent Decree), which included an agreement to divest two of our natural gas discoveries, Tanin and Karish.

Acting in good faith upon the Consent Decree, we engaged in discussions with potential purchasers of the Tanin and Karish discoveries. We believed that the Consent Decree matter had been resolved and had received assurances from the Antitrust Authority that approval was forthcoming.

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However, on December 23, 2014, the Israeli Antitrust Commissioner (Commissioner) reversed a decision to submit the agreed Consent Decree to the Israeli Antitrust Tribunal for approval. Subsequently, we requested an oral hearing with the Antitrust Authority. The hearing took place on January 27, 2015, and we are awaiting final disposition.

Because stable fiscal and regulatory regimes are imperative to support ongoing investment and sanction of major development projects, we determined that the resolution of the following items, and greater certainty with respect to Israeli fiscal and regulatory matters, would be required prior to sanction of a Leviathan development project, the Tamar expansion or other future development projects:

Approval of final gas sale and purchase agreements with off-takers, to support financing arrangements;

Clear, economically viable tax rulings, including export tax rulings;

Export approval with reasonable export allocations;

Approvals of Plans of Development;

Acceptable resolution of Leviathan and other pending matters with the Israeli Antitrust Authority;

Timely permitting;

Prompt decisions regarding pipeline onshore landing sites;

Other relevant regulatory terms critical to offshore crude oil and natural gas exploration and production;

Stable fiscal and contract terms that allow for financial returns that are appropriate to support long-term investment by a global exploration and production company; and

Stability clauses and protection from changes in laws and regulations.

In response to this situation, in late 2014, the Prime Minister's office established an inter-ministerial working group, led by the head of the National Economic Council, for the purpose of addressing outstanding regulatory matters and developing a comprehensive regulatory framework to support further investment in natural gas development. We have been engaged with the Israeli government inter-ministerial working group in an attempt to resolve these matters. As

During March 2015, general elections were held, and a new coalition government is under formation. Under this new governing coalition, leadership changes in certain of the government ministries could occur, which could impact the timing of decisions regarding natural gas development.

Although our development plans have been delayed as a result of recent government actions, described above, we believe that, given the ~~agreement, we will divest two~~quality of the natural gas ~~discoveries. We have initiated an active program~~resources and significant associated economic benefit to ~~locate a buyer~~the citizens of Israel, which could total in the billions of dollars over the life of the fields, it is in the best interest of the Israeli government to ultimately support development, and, we continue to expect that our discoveries will be developed, upon satisfactory resolution of the above matters. Therefore, we believe the risk of loss of our investment is remote as the value of these assets could be realized through ultimate development and/or sale to third parties. In addition, we would pursue any and all remedies for any damages incurred.

As of March 31, 2015, our $2.1 billion investment in Israel includes: approximately $1.3 billion related to the currently-producing Tamar field; approximately $400 million related to the Leviathan natural gas discovery and suspended deep oil test; approximately $300 million related to the Tamar expansion project and previous discoveries which are ~~progressing~~awaiting sanction of development plans; and $76 million related to the ~~other actions required to complete the sale. The assets~~Karish and Tanin discoveries, which are ~~reported within~~included in assets held for ~~sale in our consolidated balance sheet at September 30, 2014.~~

~~The agreement also granted the rights,~~sale. We expect further capital expenditure 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~~be minimized, pending resolution 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 primary purpose of the proposed amendments is 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 and have submitted comments and suggestions to the Ministry.regulatory matters.

Update on Regulations

DOI Hydraulic Fracturing Rules

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~~On March 26, 2015, the US Interior Department's Bureau of Land Management (BLM) published a final rule regulating hydraulic fracturing ~~was~~on public and Indian lands. The new rules include requirements related to well-bore integrity, wastewater disposal and public disclosure of chemicals. Key components of the rule, which will take effect on June 24, 2015, include:

• provisions for ensuring the protection of groundwater supplies by requiring a validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes;

• increased transparency by requiring companies to publicly disclose chemicals used in hydraulic fracturing to the Bureau of Land Management through the website FracFocus, within 30 days of completing fracturing operations;

• higher standards for interim storage of recovered waste fluids from hydraulic fracturing to mitigate risks to air, water and wildlife; and

• measures to lower the risk of cross-well contamination with chemicals and fluids used in the fracturing operation, by requiring companies to submit more detailed information on the ~~ballot~~geology, depth, and location of preexisting wells to afford the BLM an opportunity to better evaluate and manage unique site characteristics.

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We are currently reviewing the final rules to determine the impacts, including additional costs and reporting burdens and increased cycle time for permit approval, they may have on our operations on federal land, including our federal units in Nevada.

Nevada Regulations

In September 2014, Nevada state regulators finalized regulations for the ~~City~~use of ~~Loveland~~hydraulic fracturing in northern Colorado in June of 2014. The oil and gas industry worked with the community to defeat that initiative. Also during 2014, we actively worked to avoid statewide ballot initiatives that would unreasonably restrict or limit crude oil and natural gas development. The regulatory program includes requirements for groundwater baseline sampling and monitoring, water resource and wastewater disposal requirements, chemical disclosure requirements and mandates for extra casing for unconventional wells. We actively participated in its development and do not believe it will have a material impact on our activities.

DOI Proposed Offshore Drilling Regulations

On April 13, 2015, the DOI announced proposed regulations which include more stringent design requirements and operational procedures for critical well control equipment used in ~~Colorado. On August 4, 2014, an agreement was reached with supporters of the ballot initiatives to withdraw all ballot measures relating to~~offshore oil and gas operations.

The proposed rule, which will be open for public comment, addresses the range of systems and equipment related to well control operations. The measures are designed to improve equipment reliability, building upon enhanced industry standards for blowout preventers and blowout prevention technologies. The rule also includes reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. We will continue to monitor the development of these new regulations to determine the impacts, including additional costs and reporting burdens, they may have on our deepwater Gulf of Mexico operations.

Endangered Species Act

The US Fish and Wildlife Service (the Agency), under the Endangered Species Act (ESA), has regulatory authority over our exploration for, and production and sale of, crude oil, natural gas and ~~to support~~NGLs and activities that may result in the ~~creation~~take of aany endangered or threatened species or its habitat. The Agency recently listed the northern long-eared bat as threatened under the ESA, which could have an impact on the timing of certain of our operations in the Marcellus Shale.

Colorado Task Force

In 2014, by executive order, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (Task Force)~~. Colorado Governor Hickenlooper created the Task Force by executive order and named 21 members to it,~~ for the purpose of recommending policies and ~~legislation by~~legislation.

The 21-member Task Force, which included a Noble Energy representative, concluded its activities on February 27, 2015. ~~A Noble Energy representative is a member of~~The Task Force sent nine recommendations to the ~~Task Force.~~

~~In Nevada, state regulators are in the process of promulgating rules~~governor. The recommendations seek to ~~govern hydraulic fracturing~~balance land use issues among communities and ~~crude~~ oil and ~~natural~~ gas ~~development. We have actively participated in that process~~operators and doallow reasonable access to private mineral rights. Three recommendations are presently being considered by the legislature and the governor is reviewing the remaining recommendations, but has not ~~believe it will have a material impact on our activities.~~yet indicated how he plans to proceed.

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In addition to the above, we will continue to monitor proposed and new ~~legislation~~regulations and ~~regulations~~legislation in all operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.

~~Update on West Africa Operations~~

An epidemic of the Ebola virus is ongoing in certain regions of West Africa and may adversely affect our business operations through travel or other restrictions which could have an impact on business continuity. We continue to monitor and prepare for potential escalation.

~~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 3%11% higher for ~~the~~ ~~third~~first quarter of ~~2014~~2015 as compared with ~~the~~first quarter ~~third~~ ~~quarter of~~ ~~2013~~2014, and our mix of sales volumes was 43% global liquids, ~~27%~~25% international natural gas, and ~~30%~~32% US natural gas. ~~Increases in onshore US sales were offset by the impacts of the DJ Basin acreage exchange in fourth quarter 2013 and recent divestments.~~ See Results of Operations – Revenues, below.

~~Commodity Price Changes~~

Average realized crude oil prices decreased 9% in the US and 8% in Equatorial Guinea for the third quarter of 2014 as compared with the third quarter of 2013. Average realized natural gas prices decreased 5% in the US and increased 10% in Israel for third quarter of 2014 as compared with the third quarter of 2013.

In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows, we have hedged approximately 65% of our expected global crude oil production and approximately 60% of our expected domestic natural gas production for the remainder of 2014.

Recently Issued Accounting Standards

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

OPERATING OUTLOOK

~~2014~~2015 Production Our expected crude oil, natural gas and NGL production for ~~2014~~2015 may be impacted by several factors including:

~~changes to~~overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling ~~plans~~success, will impact near-term production volumes;

the level of horizontal drilling activity in the DJ Basin and the Marcellus Shale;

~~impact of potential pipeline~~decline in our DJ Basin legacy vertical well production and ~~processing facility~~ capacity constraints ~~in the~~of midstream facilities serving those wells;

timing of start up of DCP Midstream's Lucerne 2 cryogenic plant and occurrence of other events which impact capacity constraints of midstream facilities serving our DJ Basin ~~and Marcellus Shale;~~horizontal wells;

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timing of start-up of the Big Bend project (deepwater Gulf of Mexico);

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;

variations in West Africa crude oil and condensate sales volumes due to potential Aseng FPSO downtime and timing of liftings, and variations in natural gas sales volumes related to potential downtime at ~~key assets including: Galapagos and Swordfish, deepwater Gulf of Mexico; Tamar, offshore Israel; and Aseng and Alen, offshore Equatorial Guinea;~~the methanol, LPG and/or LNG plants;

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

potential weather-related volume curtailments ~~such as severely cold weather~~due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding in the DJ Basin and/or Marcellus Shale;

reliability of support equipment and facilities and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing;

pending Alba and Alen field unitizations in West Africa;

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

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

potential purchases of producing properties or divestments of non-core operating assets.

2015 Capital Investment Program Given the current commodity price environment with low prices and an industry cost structure that has yet to fully reset to lower revenue levels, we have designed a substantially-reduced capital investment program that is appropriate for the environment and will be responsive to conditions that develop during 2015. Our preliminary capital program for 2015 will accommodate an investment level of approximately $2.9 billion which represents an approximate 40% reduction from 2014. The program allocates more than 60% of total investment to core onshore US assets and 35% for global offshore development activities including the deepwater Gulf of Mexico, and approximately 5% for global offshore exploration.

The 2015 investment program allocates approximately $1.8 billion to onshore US development split between DJ Basin and Marcellus Shale ~~which can shut-in or reduce production.~~drilling programs and continued infrastructure investments. We and our Marcellus Shale joint venture partner continue to work together to determine the optimal investment plan for 2015 and 2016.

~~2014 Capital Investment Program~~ ~~Total capital expenditures are estimated at $4.8~~Approximately $600 million will be invested in the continued development of our sanctioned Gulf of Mexico projects, and additional amounts have been allocated to ~~$5.0 billion for 2014. We expect to invest approximately 70% of~~ the ~~program in onshore US development~~Alba and ~~approximately 30% of the program in global deepwater activities.~~Tamar compression projects.

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The ~~2014~~2015 capital investment program is ~~estimated~~anticipated to exceed operating cash flows during the first half of 2015 and ~~is expected to~~may be funded from cash flows from operations, cash on hand, ~~and~~proceeds from divestments of non-core assets, borrowings under our Credit Facility and/or other ~~financing. Funding may also be provided~~financings. We are targeting a cash neutral position, whereby the capital investment program is at, or below, operating cash flows, by ~~proceeds from divestment~~the second half of ~~non-core assets or farm-out of working interests in exploration prospects.~~2015. 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, during first quarter 2015, we are in the process of conducting exploration activities in several onshore US areas, such as the Permian Basin area of West Texas. If we conclude that the prospect is not economically viable, costs incurred would be recorded as dry hole ~~expense. The Permian Basin properties had a net book value~~expense of ~~approximately $60 million at September 30, 2014.~~$20 million. See also Item 1. Financial Statements -

During third quarter 2014, we drilled the Bright exploratory well in the deepwater Gulf of Mexico, which did not encounter hydrocarbons. Also, based on the results of recent seismic interpretation conducted on the Scotia exploratory well drilled in 2012, offshore Falkland Islands, we have concluded that the Scotia prospect is not economically viable. As such, the costs that we incurred on both Bright and Scotia prospects have been recorded as dry hole expense.Note 8. Capitalized Exploratory Well Costs.

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~~ We currently have capitalized undeveloped leasehold cost of approximately $308 million related to deepwater Gulf of Mexico ~~lease, which we acquired under regulations in effect prior to~~prospects that have not yet been drilled. These leases will expire over the Deepwater Gulf of Mexico Moratorium, expired on July 31, 2014. We have been working to mature this prospect by conducting various activities, including the licensing and processing of 3D seismic data and interpretation of geophysical information, which have resulted in the identification of a potential subsalt hydrocarbon-bearing formation below 25,000 feet. Our lease maturation activity of the sub-25,000 foot subsalt objective should satisfy the requirements needed to be granted an extension of the lease term for a period sufficient to complete the lease maturation and to commit to drilling a well to evaluate the prospect. Accordingly, we submitted an application to the Bureau of Safety and Environmental Enforcement (BSEE) on July 7, 2014 justifying and requesting a suspension of operations (SOO) for the lease and, at BSEE’s request, submitted additional information in September 2014. An approved SOO will allow us to continue to process the subsalt image and to initiate efforts to establish a multi-company partnership to mature the prospect and design an appropriate well to drill and evaluate the prospect with a targeted spud date in 2017. We believe we have satisfied the requirements for the SOO and expect that a favorable decision from BSEE will be forthcoming. However, there is no certainty a lease extension will be formally approved by BSEE. The lease had a net book value of approximately $41 million at September 30, 2014. If BSEE denies our application for the lease SOO and extension, we will write off the book value of the lease to exploration expense.years 2015 - 2024.

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 was shut-in due to mechanical issues. The well was brought back online at the end of third quarter 2014 and, as part of our remediation plan, was granted a 180 day SOO to conduct remediation activities. No impairment is currently indicated; however, we will monitor production and reserves and continue to assess the field for possible impairment. South Raton had a net book value of $123 million at September 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.

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Divestments We are currently marketing certain non-core onshore US properties. 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.

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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.

For example, in September 2014, we signed a purchase and sale agreement related to our non-core onshore US properties in the Piceance Basin of western Colorado. These properties were reclassified as held for sale at September 30, 2014 and recorded at anticipated sales proceeds less costs to sell, which resulted in an impairment charge of $31 million. ~~See~~ ~~Note 3. Divestitures, Note 4. Asset ImpairmentsandNote7. Fair Value Measurements and Disclosures~~

In addition, certain assets offshore Israel were classified as held for sale at ~~September 30, 2014.~~March 31, 2015. 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.

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RESULTS OF OPERATIONS

In the discussion below, the North Sea geographical segment is reflected as discontinued operations for the first nine 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						Increase/(Decrease) from Prior Year
(millions)	2014		2013		Increase/(Decrease) from Prior Year		2015		2014		Increase/(Decrease) from Prior Year
Three Months Ended September 30,
Three Months Ended March 31,
Oil, Gas and NGL Sales	$	1,228	$	1,341	(8	)%	$	740	$	1,327	(44	)%
Income from Equity Method Investees	41		53		(23	)%	18		52		(65	)%
Other							1		—		N/M
Total	$	1,269	$	1,394	(9	)%	$	759	$	1,379	(45	)%

Nine Months Ended September 30,
Oil, Gas and NGL Sales	$	3,893	$	3,537	10	%
Income from Equity Method Investees	138		150		(8	)%
Total	$	4,031	$	3,687	9	%

Changes in revenues are discussed below.

Oil, Gas and NGL Sales

We generally sell crude oil, natural gas, and NGLs under two types of agreements, which are common in our industry. Both types of agreements may include transportation charges. One type of agreement is a netback agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense incurred by the purchaser. In this case, we record crude oil and natural gas revenue at the net price we received from the purchaser. In the case of NGLs, we may receive a price from the purchaser, which is net of processing costs. In this case, we record NGL revenue at the net price we receive from the purchaser. The second type of agreement is one whereby we pay transportation expense directly. In that case, transportation expense is included within production expense in our consolidated statements of operations.

In addition, commodity prices we receive may be reduced by location basis differentials, which can be significant. As a result of both netback agreements and location basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.

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


	Sales Volumes				Average Realized Sales Prices						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)		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 September 30, 2014
Three Months Ended March 31, 2015											Three Months Ended March 31, 2015
United States	67	538	25	182	$	94.21	$	3.41	$	29.53	73	619	25	201	$	44.39	$	2.72	$	14.65
Equatorial Guinea ⁽²⁾	29	233	—	68	98.63		0.27		—		30	231	—	68	49.65		0.27		—
Israel	—	262	—	44	—		5.59		—		—	242	—	40	—		5.45		—
Other International ⁽³⁾	—	—	—	—	—		—		—		1	—	—	1	52.89		—		—
Total Consolidated Operations	96	1,033	25	294	95.55		3.26		29.53		104	1,092	25	310	45.96		2.81		14.65
Equity Investees ⁽⁴⁾	2	—	6	8	102.02		—		62.24		2	—	6	8	48.63		—		30.17
Total Continuing Operations	98	1,033	31	302	$	95.64	$	3.26	$	35.85
Three Months Ended September 30, 2013
Total											106	1,092	31	318	$	46.01	$	2.81	$	17.64
Three Months Ended March 31, 2014											Three Months Ended March 31, 2014
United States	64	489	13	159	$	103.59	$	3.57	$	31.26	64	483	18	163	$	97.02	$	4.81	$	44.50
Equatorial Guinea ⁽²⁾	37	257	—	80	107.67		0.27		—		34	242	—	74	105.73		0.27		—
Israel	—	255	—	43	—		5.08		—		—	218	—	37	—		5.60		—
Other International ⁽³⁾	4	—	—	4	101.58		—		—		5	—	—	5	104.28		—		—
Total Consolidated Operations	105	1,001	13	286	104.95		3.11		31.26		103	943	18	279	100.23		3.83		44.50
Equity Investees⁽⁴⁾	2	—	6	7	104.45		—		64.74		2	—	5	7	104.71		—		74.51
Total Continuing Operations	107	1,001	19	293	$	104.94	$	3.11	$	41.34

Nine Months Ended September 30, 2014
United States	66	497	22	171	$	96.84	$	4.12	$	35.39
Equatorial Guinea ⁽²⁾	32	241	—	72	104.38		0.27		—
Israel	—	233	—	39	—		5.59		—
Other International ⁽³⁾	3	—	—	3	104.47		—		—
Total Consolidated Operations	101	971	22	285	99.48		3.52		35.39
Equity Investees ⁽⁴⁾	2	—	6	7	105.15		—		67.06
Total Continuing Operations	103	971	28	292	$	99.58	$	3.52	$	47.96
Nine Months Ended September 30, 2013
United States	61	434	15	148	$	98.03	$	3.64	$	33.60
Equatorial Guinea ⁽²⁾	31	251	—	73	106.78		0.27		—
Israel	—	196	—	33	—		5.03		—
Other International ⁽³⁾	4	—	—	4	103.00		—		—
Total Consolidated Operations	96	881	15	258	101.08		3.00		33.60
Equity Investees ⁽⁴⁾	2	—	6	8	105.03		—		67.59
Total Continuing Operations	98	881	21	266	$	101.15	$	3.00	$	43.18
Total											105	943	23	286	$	100.30	$	3.83	$	51.54

⁽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 both natural gas isand NGL are 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 (through June 30, 2014). North Sea sales volumes for 2014 and 2015 were de minimis.


⁽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 September 30, 2013 $ 1,017
$ 286
$ 38
$ 1,341
Changes due to

Increase (Decrease) in Sales Volumes (85 ) 9
35
(41 )
Increase (Decrease) in Sales Prices (83 ) 15
(4 ) (72 )
Three Months Ended September 30, 2014 $ 849
$ 310
$ 69
$ 1,228

Nine Months Ended September 30, 2013 $ 2,683
$ 719
$ 135
$ 3,537
Changes due to

Increase in Sales Volumes 109
73
68
250
Increase (Decrease) in Sales Prices (44 ) 140
10
106
Nine Months Ended September 30, 2014 $ 2,748
$ 932
$ 213
$ 3,893



	Sales Revenues
(millions)	Crude Oil & Condensate			Natural Gas			NGLs			Total
Three Months Ended March 31, 2014	$	928		$	325		$	74		$	1,327
Changes due to
Increase in Sales Volumes	11			51			24			86
Decrease in Sales Prices	(508		)	(100		)	(65		)	(673		)
Three Months Ended March 31, 2015	$	431		$	276		$	33		$	740

Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales decreased by $497 million or 54% during ~~third~~first quarter of ~~2014~~2015 as compared with ~~2013~~2014 due to the following:

~~lower~~a 54% decrease in total consolidated average realized prices ~~for~~primarily due to the NYMEX WTI crude oil price decline between June and ~~condensate~~December 2014, with a similar Brent crude oil price decline, with sales prices continuing to be weak in first quarter 2015;

natural field decline in the ~~DJ Basin,~~ deepwater Gulf of ~~Mexico, and West Africa;~~

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

~~lower sales volumes due to the timing of liftings in offshore Equatorial Guinea; and~~Mexico;

lower sales volumes due to the sale of our China assets at the end of second quarter 2014; and

a volume reduction in West Africa due to natural field decline at Aseng;

partially offset by:

higher sales volumes for crude oil and condensate in the DJ Basin and Marcellus Shale.

Natural Gas Sales – Revenues from ~~crude oil and condensate~~natural gas sales ~~increased~~decreased by $49 million or 15% during first ~~nine months of 2014~~quarter 2015 as compared with ~~2013~~2014 due to the following:

a 43% decrease in US natural gas prices;

partially offset by:

higher sales volumes in the DJ Basin and Marcellus Shale ~~attributable to our horizontal drilling program;~~

~~partially offset by:~~

~~lower realized prices for crude oil and condensate in the deepwater Gulf of Mexico; and~~

~~lower sales volumes due to the sale of our China assets at the end of the second quarter of 2014.~~

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

~~higher sales volumes in the Marcellus Shale~~ primarily attributable to our horizontal drilling ~~program~~program; and ~~continued ramp-up of activity;~~

higher sales volumes in the Eastern Mediterranean ~~due to the start-up of~~from the Tamar ~~project; and~~

increases in total consolidated average realized prices primarily due to increased demand from cooler weather earlier in 2014 and higher-than-expected inventory withdrawals in the US, which increased the market price in our producing areas;

~~partially offset by:~~

~~lower sales volumes due to non-core onshore US properties divested during 2013 and the first nine months of 2014.~~field.

NGL Sales – The majority of our US NGL production is currently from the DJ Basin. Additional NGL production from the Marcellus Shale added 54 MBbl/d during ~~third~~first quarter ~~2014 and 3 MBbl/d during the first nine months of 2014~~2015 as compared with ~~2013~~2014, primarily due to increased production from the wet gas acreage. NGL sales in the DJ Basin increased by 72 MBbl/d during ~~the third~~first quarter ~~of 2014~~2015 as compared with ~~2013, while recent sales of non-core onshore US properties have slightly reduced sales volumes as compared with third quarter 2013.~~2014. Additionally, consolidated average sales prices ~~increased 5%~~decreased 67% for the first ~~nine~~three months of ~~2014,~~2015 compared to the first ~~nine~~three months of ~~2013.~~2014.

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Income from Equity Method Investees We have interests in ~~various~~ equity method investees that operate midstream assets onshore US and West Africa. 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, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.

We recorded income of $11 million related to our investments in CONE Gathering LLC and CONE Midstream Partners LP in first quarter 2015. Our West Africa geographical segment had an 86% decrease in equity method investee income, as compared to first quarter 2014. This decrease is due to expenses related to the 45-day AMPCO methanol plant turnaround. Production at AMPCO was shut down during first quarter 2015, which resulted in a quarterly loss.

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Operating Costs and Expenses

Operating costs and expenses were as follows:

Increase (Decrease)
from Prior Year
(millions) 2014 2013
Three Months Ended September 30,
Production Expense $ 217
$ 221
(2 )%
Exploration Expense 217
60
N/M
Depreciation, Depletion and Amortization 460
412
12 %
General and Administrative 132
109
21 %
Gain on Divestitures (30 ) —
— %
Asset Impairments 33
63
(48 )%
Other Operating (Income) Expense, Net 10
6
67 %
Total $ 1,039
$ 871
19 %

Nine Months Ended September 30,
Production Expense $ 697
$ 619
13 %
Exploration Expense 350
211
66 %
Depreciation, Depletion and Amortization 1,297
1,146
13 %
General and Administrative 399
324
23 %
Gain on Divestitures (72 ) (12 ) N/M
Asset Impairments 164
63
N/M
Other Operating (Income) Expense, Net 33
27
23 %
Total $ 2,868
$ 2,378
21 %

~~N/M – Amount is not meaningful.~~



					Increase (Decrease) from Prior Year
(millions)	2015		2014		Increase (Decrease) from Prior Year
Three Months Ended March 31,
Production Expense	$	245	$	229	7	%
Exploration Expense	65		74		(12	)%
Depreciation, Depletion and Amortization	454		425		7	%
General and Administrative	94		140		(33	)%
Asset Impairments	27		97		(72	)%
Other Operating (Income) Expense, Net	8		10		(20	)%
Total	$	893	$	975	(8	)%

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⁾		Total per BOE ⁽¹⁾		Total		United States		Equatorial Guinea		Israel		Other Int'l, Corporate ⁽²⁾
Three Months Ended September 30, 2014
Three Months Ended March 31, 2015
Lease Operating Expense ⁽³⁾	$	4.91	$	133	$	79	$	34	$	13	$	7	$	5.61	$	157	$	103	$	34	$	12	$	8
Production and Ad Valorem Taxes	1.64		44		44		—		—		—		1.16		32		32		—		—		—
Transportation and Gathering Expense	1.48		40		40		—		—		—		2.00		56		56		—		—		—
Total Production Expense	$	8.03	$	217	$	163	$	34	$	13	$	7	$	8.77	$	245	$	191	$	34	$	12	$	8
Three Months Ended September 30, 2013
Total Production Expense per BOE															$	8.77	$	10.55	$	5.55	$	3.27	N/M
Three Months Ended March 31, 2014
Lease Operating Expense ⁽³⁾	$	5.21	$	137	$	81	$	30	$	13	$	13	$	5.66	$	142	$	85	$	31	$	12	$	14
Production and Ad Valorem Taxes	1.94		51		43		—		—		8		1.96		49		40		—		—		9
Transportation and Gathering Expense	1.26		33		32		—		—		1		1.52		38		37		—		—		1
Total Production Expense	$	8.41	$	221	$	156	$	30	$	13	$	22	$	9.14	$	229	$	162	$	31	$	12	$	24

Nine Months Ended September 30, 2014
Lease Operating Expense ⁽³⁾	$	5.55	$	432	$	255	$	101	$	39	$	37
Production and Ad Valorem Taxes	1.88		146		129		—		—		17
Transportation and Gathering Expense	1.54		119		118		—		—		1
Total Production Expense	$	8.97	$	697	$	502	$	101	$	39	$	55
Nine Months Ended September 30, 2013
Lease Operating Expense ⁽³⁾	$	5.56	$	393	$	260	$	77	$	33	$	23
Production and Ad Valorem Taxes	1.94		137		112		—		—		25
Transportation and Gathering Expense	1.26		89		86		—		—		3
Total Production Expense	$	8.76	$	619	$	458	$	77	$	33	$	51
Total Production Expense per BOE															$	9.14	$	11.04	$	4.67	$	3.65	N/M

N/M Amount is not meaningful.


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


⁽²⁾	Other International includes primarily China (through June 30, 2014). and corporate expenditures.


⁽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~~ ~~third~~first quarter ~~2014~~2015, total production expense ~~decreased~~increased as compared with ~~2013~~2014 due to the following:

~~decreased~~an increase of $15 million in lease operating expense due to increased production in the ~~deepwater Gulf of Mexico~~DJ Basin and Marcellus Shale; and

an increase in transportation and gathering expenses due to ~~lower net processing costs resulting from the Neptune spar, which we acquired~~an increase in ~~the second half 2013;~~onshore US production.

partially offset by:

decreased lease operating expense ~~from~~due to the sale of our China assets at the end of the second quarter 2014; and

decreased production and ad valorem taxes due to decreased revenues resulting from lower realized prices in the US as well as the sale of our China assets at the end of the second quarter 2014.

~~partially offset by:~~

~~increased lease operating expense in the DJ Basin due to increased development activity and higher production~~

~~For the first nine 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 resulting in higher production;~~

~~increased lease operating expense offshore Equatorial Guinea primarily driven by increases in labor and FPSO expense resulting from the start up of the Alen field during the second half of 2013;~~

~~increased lease operating expense offshore Israel primarily driven by increases in labor 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 increased revenues resulting from higher production volumes and higher average realized 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;~~

~~decreased lease operating expense from the sale of our China assets at the end of the second quarter of 2014; 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⁾		Total		United States		West Africa ⁽¹⁾			Eastern Mediter- ranean ⁽²⁾		Other Int'l, Corporate ⁽³⁾
Three Months Ended September 30, 2014
Three Months Ended March 31, 2015													Three Months Ended March 31, 2015
Dry Hole Cost	$	161		$	79		$	—	$	—	$	82	$	20	$	17	$	—		$	—	$	3
Seismic	22			4			12		1		5		2		2		—			—		—
Staff Expense	22			4			2		4		12		30		3		(3		)	7		23
Other	12			12			—		—		—		13		13		—			—		—
Total Exploration Expense	$	217		$	99		$	14	$	5	$	99	$	65	$	35	$	(3	)	$	7	$	26
Three Months Ended September 30, 2013
Three Months Ended March 31, 2014													Three Months Ended March 31, 2014
Dry Hole Cost	$	(1	)	$	(1	)	$	—	$	—	$	—	$	2	$	3	$	—		$	—	$	(1	)
Seismic	16			7			1		7		1		23		7		—			1		15
Staff Expense	33			11			2		2		18		35		8		2			3		22
Other	12			11			—		—		1		14		14		—			—		—
Total Exploration Expense	$	60		$	28		$	3	$	9	$	20	$	74	$	32	$	2		$	4	$	36

Nine Months Ended September 30, 2014
Dry Hole Cost	$	163		$	81		$	—	$	—	$	82
Seismic	54			19			12		3		20
Staff Expense	90			22			6		9		53
Other	43			43			—		—		—
Total Exploration Expense	$	350		$	165		$	18	$	12	$	155
Nine Months Ended September 30, 2013
Dry Hole Cost	$	22		$	14		$	8	$	—	$	—
Seismic	66			20			3		13		30
Staff Expense	91			23			6		3		59
Other	32			32			—		—		—
Total Exploration Expense	$	211		$	89		$	17	$	16	$	89


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


⁽²⁾	Eastern Mediterranean includes Israel and Cyprus.


⁽³⁾	Other International includes the Falkland Islands and ~~Nicaragua.~~other new ventures.

Exploration expense for ~~the third~~first quarter ~~and first nine months~~2015 included:

$13 million of ~~2014 included:~~

~~seismic expense related to 3D seismic acquisition in the deepwater Gulf of Mexico, Equatorial Guinea, and Falkland Islands;~~

dry hole cost related primarily to ~~the Bright~~onshore US exploratory ~~well, deepwater Gulf of Mexico, the Scotia exploratory well, offshore Falkland Islands, and other miscellaneous charges;~~wells; and

salaries and related expenses for corporate exploration and new ventures personnel.

Exploration expense for ~~the third~~first quarter ~~and first nine months of 2013~~2014 included the following:

~~dry hole cost related primarily to the deeper exploration objective~~$12 million 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;~~

seismic expense ~~related to 3D seismic acquisition~~ in the ~~deepwater Gulf of Mexico, Cyprus, and~~ Falkland Islands; and

salaries and related expenses for corporate exploration and new ventures personnel.

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2014		2013		2014		2013		2015		2014
DD&A Expense (millions) ⁽¹⁾	$	460	$	412	$	1,297	$	1,146	$	454	$	425
Unit Rate per BOE ⁽²⁾	$	16.98	$	15.67	$	16.67	$	16.22	$	16.24	$	16.95


⁽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.

Total DD&A expense for ~~the third~~first quarter ~~and first nine months of 2014~~2015 increased as compared with ~~2013~~2014 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;~~

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

~~increase offshore Israel due to the start up of the Tamar field at the end of first quarter 2013;~~volumes;

partially offset by:

decrease due to ~~sales~~the sale of ~~non-core onshore US properties in 2013; and~~

~~decrease from natural field decline at the Mari-B, Noa and Pinnacles fields, offshore Israel.~~our China assets during 2014.

The ~~increase~~decrease in the unit rate per BOE for the ~~third~~first quarter ~~and first nine months of 2014~~2015 as compared with ~~2013~~2014 was due primarily to the change in mix of production. Higher-cost production volumes in the deepwater Gulf of Mexico and DJ Basin were offset by an increase in lower cost volumes produced at Tamar, offshore Israel. ~~Lower cost volumes~~

Our year-end 2014 proved reserves estimates, upon which we based our first quarter 2015 DD&A calculation, were based on the previous 12-month average commodity prices. Therefore, the significant decline in crude oil prices at ~~Tamar replaced higher cost volumes produced from~~ the ~~Mari-B, Noa~~end of 2014 and ~~Pinnacles fields.~~the continued price weakness into 2015, are not yet fully reflected in our proved reserves estimates. We expect to update our proved reserves estimates as of June 30, 2015. A decline in proved reserves estimates, caused by decreases in the 12-month average commodity prices as of June 30, 2015, could result in an increase in DD&A expense during second quarter 2015.

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2014		2013		2014		2013		2015		2014
G&A Expense (millions)	$	132	$	109	$	399	$	324	$	94	$	140
Unit Rate per BOE ⁽¹⁾	$	4.89	$	4.14	$	5.12	$	4.59	$	3.36	$	5.57


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

G&A expense for ~~the~~ ~~third~~first quarter ~~and first nine months of 2014~~2015 ~~increased~~decreased as compared with ~~2013~~2014 primarily due to ~~additional expenses relating to personnel~~the following:

a $33 million decrease in short term incentive compensation and ~~office space~~related payroll burden;

an $8 million decrease in ~~support of our major development projects. For example, our total number of employees increased from 2,190 at December 31, 2012, to 2,527 at December 31, 2013~~contractor and ~~to over 2,600 at September 30, 2014.~~consulting services; and

reductions in travel and other discretionary expenses.

Asset Impairment Expense Asset impairment expense was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
(millions)	2014		2013		2014		2013		2015		2014
Asset Impairments	$	33	$	63	$	164	$	63	$	27	$	97

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

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Other (Income) Expense

Other (income) expense was as follows:


	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
(millions)	2014			2013		2014			2013		2015			2014
(Gain) Loss on Commodity Derivative Instruments	$	(385	)	$	157	$	(74	)	$	69	$	(150	)	$	75
Interest, Net of Amount Capitalized	52			46		151			104		57			47
Other Non-Operating (Income) Expense, Net	(13		)	9		1			21		1			5
Total	$	(346	)	$	212	$	78		$	194	$	(92	)	$	127

(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 the terms of our executed commodity instruments; increases in notional volumes; and the mix of instruments 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.

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2014			2013			2015			2014
(millions, except unit rate)
Interest Expense, Gross	$	79		$	68		$	238		$	204		$	93		$	81
Capitalized Interest	(27		)	(22		)	(87		)	(100		)	(36		)	(34		)
Interest Expense, Net	$	52		$	46		$	151		$	104		$	57		$	47
Unit Rate per BOE ⁽¹⁾	$	1.93		$	1.74		$	1.94		$	1.47		$	2.05		$	1.89

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

The increase in interest expense, gross, for ~~third~~first quarter ~~and first nine months of~~2015 as compared with 2014 is due to the issuance of new senior debt in November ~~2013~~2014. During first quarter 2015, we drew down and ~~recent borrowings~~repaid amounts under our Credit Facility. There have been no other significant changes in our debt.

~~The increase in capitalized interest during third quarter~~

Table of ~~2014 as compared with~~ ~~2013~~ is primarily due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and offshore Israel. This increase is partially offset by 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.Contents

~~The~~ ~~decrease~~ in capitalized interest for the nine months ended September 30, 2014 is primarily due to the completion of longer cycle time major projects in 2013, 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.

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~~ ~~third~~first quarter ~~and first nine months of 2014~~2015 as compared with ~~2013~~.

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~~Discontinued Operations~~

~~The North Sea geographical segment is reflected as discontinued operations for the first nine 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
September 30, Nine Months Ended
September 30,
2013 2013
(millions)
Oil and Gas Sales $ 11
$ 32
Expenses 4
22
Income Before Income Taxes 7
10
Income Tax Expense (3 ) 7
Operating (Income) Loss, Net of Tax 10
3
Gain on Sale, Net of Tax —
55
Income From Discontinued Operations $ 10
$ 58

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) $ 110.13
$ 108.51
Natural Gas (Per Mcf) 10.49
10.59

~~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~~.

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.~~cycle, including the current downturn in crude oil prices. 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~~continuing 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.

On September 24, 2014, our equity method investee, CONE Gathering, contributed substantially all of its assets to a newly-formed master limited partnership, CONE Midstream, concurrently with an initial public offering of limited partner units. CONE Gathering subsequently distributed $204 million of the offering proceeds to us.

We ~~may also~~occasionally 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. ~~During third quarter 2014,~~On March 3, 2015, we ~~borrowed~~closed an underwritten public offering of 21,000,000 shares of common stock, par value $0.01 per share, at a price to the public of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3,150,000 shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net ~~$300~~proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and estimated offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving credit facility and the remainder will be used for general corporate purposes, including the funding of our capital investment program.

We also consider repatriations of 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 incremental US tax. We evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider other sources of funding.

Cash on hand at March 31, 2015 totaled $1.7 billion, which includes both domestic and foreign cash, and there were no amounts outstanding under our Credit Facility. 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 deepwater development projects, and ~~our~~ planned exploration and appraisal drilling activities, ~~are estimated to result~~as well as the fourth quarter 2014 decline in ~~near term~~crude oil prices, resulted in capital expenditures exceeding cash flows from operating ~~activities.~~activities for first quarter 2015. The extent to which capital investment will exceed operating cash flows depends on ~~our success in sanctioning~~the pace of future DJ Basin and Marcellus Shale development activities, timing of future development ~~projects,~~project sanction, the results of ~~our~~ exploration activities, and new business

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opportunities, as well as external factors such as commodity prices, among others. ~~Our~~In particular, the sustained crude oil price decline has a significant negative impact on our cash flows. However, 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 the Big Bend and Dantzler development projects and additional production from the Tamar ~~which began producing in late first quarter 2013, and Alen, which began producing in late second quarter 2013,~~compression project, will result in an increase in cash flows which will be available to meet a ~~substantial~~ portion of future capital ~~commitments.~~commitments in 2016 and subsequent years. See Results of Operations above.

Cash on hand at September 30, 2014 totaled $1.2 billion, 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 nine months of 2014, we repatriated $519 million from our UK operations and $300 million from various other foreign operations. We will not incur material US tax on these repatriations.

We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. 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 and/or financing scenarios for our significant natural gas discoveries offshore Eastern Mediterranean. The magnitude of these discoveries presents technical and financial challenges for us due to the large-scale development requirements. Each of these development options, including the development of Leviathan Phase 1, would require a multi-billion dollar investment and require a number of years to complete. We are currently working to resolve antitrust and other regulatory matters with the Israeli government to enable Leviathan and other development to move forward. See Executive Overview – Update on Core Area – Israel, above.

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Pension Plan Termination We are in the process of terminating our defined benefit pension ~~plan (pension plan). We~~plan. The Internal Revenue Service has approved the termination, and 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,~~2014, the latest actuarial measurement date for the pension plan, the accumulated benefit obligation totaled ~~$315~~$287 million, and the fair value of plan assets was ~~$265~~$242 million. Therefore, we expect to make additional contributions to the plan of approximately $50 million during the period leading up to final termination and distribution to the extent necessary to fund the net obligation.

In addition, upon termination of the pension plan, all unamortized prior service cost and net actuarial loss remaining in ~~AOCL~~accumulated other comprehensive loss will be charged to expense. This amount totaled approximately ~~$95~~$82 million as of ~~September 30, 2014. We expect pension plan termination to occur in the first half of~~March 31, 2015.

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:


	September 30,			December 31,			March 31,			December 31,
	2014			2013			2015			2014
(millions, except percentages)
Cash and Cash Equivalents	$	1,169		$	1,117		$	1,709		$	1,183
Amount Available to be Borrowed Under Credit Facility ⁽¹⁾	3,100			4,000			4,000			4,000
Total Liquidity	$	4,269		$	5,117		$	5,709		$	5,183
Total Debt ⁽²⁾	$	5,583		$	4,843		$	6,203		$	6,197
Total Shareholders' Equity	9,938			9,184			11,357			10,325
Ratio of Debt-to-Book Capital ⁽³⁾	36		%	35		%	35		%	38		%


⁽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 $~~1.2~~1.7 billion in cash and cash equivalents at ~~September 30, 2014~~March 31, 2015, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately ~~$862~~$791 million of this cash is attributable to our foreign subsidiaries and a portion would be subject to US income taxes if repatriated.

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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 ~~September 30, 2014, we had drawn $900 million~~March 31, 2015, no amounts were outstanding under the Credit ~~Facility to fund increased development activities. The weighted average interest rate on the borrowings was 1.43% at September 30, 2014.~~Facility. 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 About Market Risk..

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, three-way collars and/or ~~three-way collars.~~extendable swaps.

Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties.

A significant portion of the hedged volumes are attributable to three-way collars. When commodities trade below the strike price of the sold put option contract of the three-way collar, the cash settlements received by us are limited. However, we still receive the cash market price plus the delta between the purchased put option floor price of the two-way collar contract and the sold put option strike price.

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 ~~September 30, 2014~~March 31, 2015, the fair value of our commodity derivative assets was $~~111~~830 million and we had no derivative liabilities (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

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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 for Leviathan Phase 1.~~

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 See Item 1. Financial Statements - Note 13. Commitments and Contingencies.

Exploration Commitments The ~~CONSOL Carried Cost Obligation represents~~terms of some of our ~~agreement~~PSCs, licenses or concession agreements require us to ~~fund up to approximately $2.1 billion of CONSOL’s future~~conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. At March 31, 2015, we have the following commitments: remaining three-well obligation in Nevada; one-well obligation offshore Cameroon; one-well obligation offshore Cyprus; two-well obligation offshore Falkland Islands; and ~~completion costs. The CONSOL Carried Cost Obligation is expected to~~3D seismic obligation offshore Gabon. These obligations extend over a ~~multi-year~~ period ~~and is capped at $400 million~~ranging from one to four years. Failure to conduct exploration activities within the prescribed periods could lead to loss of leases or exploration rights.

Ratings Triggers We do not have triggers on any of our corporate debt that would cause an event of default in ~~each calendar year. The obligation is suspended if average Henry Hub~~the case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a downgrade or other negative rating action could affect our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas ~~prices fall~~sales contracts, work commitments and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices.certain abandonment obligations.

Due to past low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 to February 28, 2014. 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 September 30, 2014, NYMEX Henry Hub natural gas price curve and current development plans, we forecast we will incur approximately $185 million under the CONSOL Carried Cost Obligation for 2014. The carry will be suspended again if average Henry Hub natural gas prices remain at or below $4.00 per MMBtu in any future three consecutive month period.

~~Marcellus Shale Firm Transportation Agreements~~ During 2014, we signed Precedent Agreements for Firm Transportation to move 445,000 MMBtu per day of our Marcellus Shale natural gas production to various markets. Our financial commitment is approximately $1.2 billion, undiscounted, over a 15-year period, beginning in 2017.

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Cash Flows

Cash flow information is as follows:


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014
(millions)
Total Cash Provided By (Used in)
Operating Activities	$	2,703		$	2,153		$	541		$	929
Investing Activities	(3,175		)	(2,937		)	(1,036		)	(1,078		)
Financing Activities	524			335			1,021			386
Increase (Decrease) in Cash and Cash Equivalents	$	52		$	(449	)
Increase in Cash and Cash Equivalents							$	526		$	237

Operating Activities Net cash provided by operating activities for the first ~~nine~~three months of ~~2014~~2015 ~~increased~~decreased significantly as compared with ~~2013~~2014. ~~Slight increases~~Significant decreases in ~~natural gas and natural gas liquids~~the average realized sales prices ~~and an increase in~~of crude oil and domestic natural gas were partially offset by increases in sales volumes, ~~were offset by~~ decreases ~~in crude oil sales prices, increases~~ in production expenses, and a decrease in general and administrative expense. Working capital changes contributed ~~$286~~$18 million of positive operating cash flow in the first ~~nine~~three months of ~~2014~~2015 as compared with a ~~negative~~positive impact of ~~$201~~$126 million in the first ~~nine~~three months of ~~2013.~~2014.

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~~decreased by ~~$564~~$47 million during the first ~~nine~~three months of ~~2014~~2015 as compared with ~~2013~~2014, primarily due to ~~increased major project development activity in our core areas.~~a reduced capital spending program. Investing activities included ~~$156 million of the $204 million distribution from CONE Gathering, and we also invested $58~~$44 million in CONE Gathering ~~discussed below,~~LLC during the first ~~nine~~three months of 2015 as compared with $12 million in the first three months of 2014. We received ~~$312~~$119 million in proceeds from ~~non-core~~ asset divestitures during the first ~~nine~~three months of ~~2014,~~2015, as compared with ~~$119~~$92 million during the same period in ~~2013.~~2014.

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 ~~nine~~three months of 2015, funds were provided by cash proceeds from the issuance of shares of Company common stock to the public ($1.1 billion) and the exercise of stock options ($4 million). We used cash to pay dividends on our common stock ($64 million), make principal payments related to capital lease obligations ($19 million) and repurchase shares of our common stock ($12 million).

In comparison, during the first three months of 2014, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($6316 million) and net cash proceeds from our Credit Facility ($~~900~~450 million). We also used cash to

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pay dividends on our common stock ($~~182~~50 million)~~, to repay Senior Notes that were due April 15, 2014 ($200 million)~~, make principal payments related to capital lease obligations ~~($42 million) and repurchase shares of our common stock ($15 million).~~

~~In comparison, during the~~ ~~first nine months of 2013, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options~~ ($~~54 million). We also used cash to pay dividends on our common stock ($146 million), make principal payments related to the Aseng FPSO capital lease obligation ($31~~15 million) and repurchase shares of our common stock ($1415 million).

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

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Investing Activities

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2014		2013		2014		2013		2015		2014
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition ⁽¹⁾	$	42	$	34	$	171	$	168	$	26	$	55
Exploration	191		275		419		660		69		90
Development⁽²⁾	1,056		795		2,792		2,169		699		703
Midstream									58		44
Corporate and Other	28		35		118		159		23		47
Total	$	1,317	$	1,139	$	3,500	$	3,156	$	875	$	939

Other
Investment in Equity Method Investee ⁽³⁾	$	18	$	8	$	58	$	30
Investment in Equity Method Investee ⁽²⁾									$	44	$	12
Increase in Capital Lease Obligations	60		18		81		54		20		5

⁽¹⁾

Unproved property acquisition cost for ~~2014~~2015 includes ~~$55~~$11 million in the DJ Basin ~~$98~~and $15 million in the Marcellus ~~Shale, and $16 million in the deepwater Gulf of Mexico.~~Shale. Unproved property acquisition cost for ~~2013 were primarily related to acquisitions that strengthened our positions~~2014 includes $20 million in the DJ Basin and $35 million in the Marcellus ~~Shale, and deepwater Gulf of Mexico.~~Shale.


⁽²⁾	~~Development expenditures for 2014 include drilling rig mobilization charges of $54 million, a portion of which is being billed to partners as the rig is utilized.~~


⁽³⁾	Investment in equity method ~~investees~~investee represents contributions to CONE Gathering LLC which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture.

Total expenditures ~~increased in 2014~~decreased first quarter 2015 as compared with ~~2013~~2014 due to ~~accelerated activity in the DJ Basin and Marcellus Shale.~~our reduced capital spending program. See Operating Outlook – 2015 Capital Investment Program, above.

Financing Activities

Long-Term Debt Our principal source of liquidity is our Credit Facility that matures October 3, 2018. At ~~September 30, 2014~~March 31, 2015, ~~$900 million was~~there were no borrowings outstanding under the Credit Facility, leaving $~~3.1~~4.0 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~~5.8 billion at ~~September 30, 2014~~March 31, 2015. The weighted average interest rate on fixed-rate debt was ~~6.09%~~5.69%, 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 5018 cents per share of our common stock during the first ~~nine~~three months of ~~2014~~2015 and 4114 cents per share during the first ~~nine~~three months of ~~2013~~2014 ~~(as adjusted for the 2-for-1 stock split during the second quarter of 2013)~~.

On ~~October 21, 2014,~~April 27, 2015, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid on ~~November 17, 2014~~May 26, 2015 to shareholders of record on ~~November 4, 2014.~~May 11, 2015. 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 $454 million during the first ~~nine~~three months of ~~2014~~2015 and $3910 million during the first ~~nine~~three months of ~~2013~~2014.

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 ~~253,094~~249,122 shares with a value of $12 million during the first three months of 2015 and 247,674 shares with a value of $15 million during the first ~~nine~~three months of 2014 ~~and 248,986 shares with a value of~~ ~~$14 million~~ ~~during the~~ ~~first nine 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.

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At ~~September 30, 2014~~March 31, 2015, we had entered into ~~variable to fixed price~~various commodity ~~swaps and three-way collars~~derivative instruments 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 asset position with a fair value of ~~$111~~$830 million. Based on the ~~September 30, 2014~~March 31, 2015 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $10.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by approximately ~~$341~~$194 million. A hypothetical price increase of $0.50 per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately ~~$44~~$42 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 ~~September 30, 2014~~March 31, 2015, we had approximately $~~5.2~~5.8 billion (excluding capital lease and other obligations) of long-term debt outstanding. Of this amount, $~~4.3~~5.8 billion was fixed-rate debt with a weighted average interest rate of ~~6.09%~~5.69%. 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~~There was no variable-rate debt ~~$900 million~~outstanding at ~~September 30, 2014~~March 31, 2015~~, 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 are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of ~~September 30, 2014~~March 31, 2015, our cash and cash equivalents totaled approximately $~~1.2~~1.7 billion, approximately ~~66%~~72% of which was invested in money market funds and short-term investments with major financial institutions. A change in the interest rate applicable to our variable-rate debt or our short term investments would have a de minimis impact. We currently have no interest rate derivative instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our interest rate risk.

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 third~~first quarter of each of 2015 and ~~the first nine months of both 2014 and 2013.~~2014.

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;

our future results of operations;

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

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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

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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~~2014, 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~~2014 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.

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Part II. Other Information

Item 1. Legal Proceedings

~~West Virginia~~Colorado Air Matter In ~~March 2013,~~April 2015, we ~~received seven Notices of Violation (NOV) and two Administrative Orders (Orders) from~~entered into a joint consent decree (Consent Decree) with the ~~West Virginia~~US Environmental Protection Agency, US Department of ~~Environmental Protection Office~~Justice, and State of ~~Oil~~Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and ~~Gas (OOG) regarding~~natural gas operations within the ~~unintentional discharge~~Non-Attainment Area of the DJ Basin. The Consent Decree is subject to a 30 day public comment period before it may be considered for entry by the Court.

The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, will require the performance of certain injunctive relief activities, completion of mitigation projects and supplemental environmental projects (SEP), and payment of a ~~mixture~~civil penalty. The value of ~~freshwater~~the settlement consists of $4.95 million in civil penalties, $4.5 million in mitigation projects, and ~~produced water~~$4 million in SEPs. The value associated with the injunctive relief is not yet quantifiable as it will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.

Compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019. The Consent Decree further contains requirements for ongoing inspection and monitoring, in addition to existing Colorado regulatory requirements. Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.

We have concluded that ~~occurred on or about~~ the ~~evening of February 22, 2013~~penalties, injunctive relief, and mitigation expenditures that resulted from ~~one of our permitted water storage facilities in Marshall County, West Virginia. In July 2014, we reached a resolution with OOG regarding the NOVs and Orders. The resolution of these proceedings~~this settlement did 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~~2014.

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)
7/1/2014 - 7/31/2014 533
$ 71.83
—
—
8/1/2014 - 8/31/2014 1,492
70.03
—
—
9/1/2014 - 9/30/2014 710
70.99
—
—
Total 2,735
$ 70.63
—
—



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)
1/1/2015 - 1/31/2015	48,403	$	47.74	—	—
2/1/2015 - 2/28/2015	199,705	47.74		—	—
3/1/2015 - 3/31/2015	1,014	46.94		—	—
Total	249,122	$	47.74	—	—


⁽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.~~plans, which vested primarily on January 31 and February 1, 2015.

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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	~~October 28, 2014~~May 5, 2015	/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)~~29, 2015), 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.~~herewith.

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.

10.1		~~Retention and Confidentiality Agreement between~~ Noble Energy, Inc. 1992 Stock Option and ~~Charles D. Davidson dated~~ ~~August 14, 2014,~~Restricted Stock Plan (as amended through April 28, 2015), filed ~~as Exhibit 10.1 to the Registrant's Current Report on Form 8-K (Date~~herewith.

10.2		2015 Stock Plan for Non-Employee Directors of ~~Event: August 14, 2014)~~Noble Energy, Inc., filed ~~August 18, 2014 and incorporated herein by reference.~~herewith.

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

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