Noble Energy (NBL) 10-Q 4 May 16 2016 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	3 Months Ended
	Mar. 31, 2016shares
Document And Entity Information [Abstract]
Entity Registrant Name	NOBLE ENERGY INC
Entity Central Index Key	72,207
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	429,592,264
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016

Consolidated Statements of Oper

Consolidated Statements of Operations (unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2016		Mar. 31, 2015
Revenues
Oil, Gas and NGL Sales		$ 705		$ 749
Income from Equity Method Investees		19		18
Total		724	[1]	767
Costs and Expenses
Production Expense		272		254
Exploration Expense		163		65
Depreciation, Depletion and Amortization		617		454
General and Administrative		91		94
Other Operating (Income) Expense, Net		3		34
Total		1,146		901
Operating Loss		(422)		(134)
Other (Income) Expense
Gain on Commodity Derivative Instruments		(44)		(150)
Interest, Net of Amount Capitalized		79		57
Other Non-Operating (Income) Expense, Net		(4)		1
Total		31		(92)
Loss Before Income Taxes		(453)		(42)
Income Tax Benefit		(166)		(20)
Net Loss		$ (287)	[1]	$ (22)
Loss per share, basic (in dollars per share)		$ (0.67)	[1]	$ (0.06)
Loss per share, diluted (in dollars per share)		$ (0.67)	[1]	$ (0.06)
Weighted Average Number of Shares Outstanding
Basic (in shares)	[2]	429		370
Diluted (in shares)		429		370
[1]	No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.
[2]	The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Loss (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016		Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Loss	$ (287)	[1]	$ (22)
Other Items of Comprehensive Loss
Net Change in Mutual Fund Investment	0		(11)
Less Tax Benefit	0		3
Net Change in Pension and Other	0		1
Other Comprehensive Loss	0		(7)
Comprehensive Loss	$ (287)		$ (29)
[1]	No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Consolidated Balance Sheets (un

Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents	$ 953	$ 1,028
Accounts Receivable, Net	531	450
Commodity Derivative Assets, Current	454	582
Other Current Assets	154	216
Total Current Assets	2,092	2,276
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	31,209	31,220
Property, Plant and Equipment, Other	892	858
Total Property, Plant and Equipment, Gross	32,101	32,078
Accumulated Depreciation, Depletion and Amortization	(11,394)	(10,778)
Total Property, Plant and Equipment, Net	20,707	21,300
Other Noncurrent Assets	614	620
Total Assets	23,413	24,196
Current Liabilities
Accounts Payable - Trade	1,005	1,128
Other Current Liabilities	601	677
Total Current Liabilities	1,606	1,805
Long-Term Debt	7,882	7,976
Deferred Income Taxes, Noncurrent	2,640	2,826
Other Noncurrent Liabilities	1,233	1,219
Total Liabilities	$ 13,361	$ 13,826
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued	$ 0	$ 0
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 471 Million and 470 Million Shares Issued, respectively	5	5
Additional Paid in Capital	6,378	6,360
Accumulated Other Comprehensive Loss	(33)	(33)
Treasury Stock, at Cost; 38 Million Shares	(696)	(688)
Retained Earnings	4,398	4,726
Total Shareholders’ Equity	10,052	10,370
Total Liabilities and Shareholders’ Equity	$ 23,413	$ 24,196

Consolidated Balance Sheets (u5

Consolidated Balance Sheets (unaudited) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Preferred stock, par value per share (in dollars per share)	$ 1	$ 1
Preferred stock, shares authorized (in shares)	4,000,000	4,000,000
Common stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000,000,000	1,000,000,000
Common stock, shares issued (in shares)	471,000,000	470,000,000
Treasury stock, shares (in shares)	38,000,000	38,000,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016		Mar. 31, 2015
Cash Flows From Operating Activities
Net Loss		$ (287)	[1]	$ (22)
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		617		454
Asset Impairments	[2]	0		27
Dry Hole Cost		93		20
Gain on Extinguishment of Debt	[3]	(80)		0
Loss on Asset Due to Terminated Contract	[4]	42		0
Deferred Income Tax Benefit		(186)		(30)
Loss from Equity Method Investees, Net of Dividends		(3)		(18)
Gain on Commodity Derivative Instruments		(44)		(150)
Net Cash Received in Settlement of Commodity Derivative Instruments		178		210
Stock Based Compensation		20		21
Other Adjustments for Noncash Items Included in Income		37		11
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable		(38)		107
Decrease in Accounts Payable		(24)		(71)
(Decrease) Increase in Current Income Taxes Payable		(16)		3
Other Current Assets and Liabilities, Net		(64)		(51)
Other Operating Assets and Liabilities, Net		6		30
Net Cash Provided by Operating Activities		251		541
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(496)		(1,111)
Additions to Equity Method Investments		(6)		(44)
Proceeds from Divestitures and Other		238		119
Net Cash Used in Investing Activities		(264)		(1,036)
Cash Flows From Financing Activities
Dividends Paid, Common Stock		(41)		(64)
Proceeds from Issuance of Shares of Common Stock to Public, Net of Offering Costs		0		1,112
Proceeds from Term Loan Facility		1,400		0
Repayment of Senior Notes		(1,383)		0
Repayment of Capital Lease Obligation		(13)		(19)
Other		(25)		(8)
Net Cash (Used in) Provided by Financing Activities		(62)		1,021
(Decrease) Increase in Cash and Cash Equivalents		(75)		526
Cash and Cash Equivalents at Beginning of Period		1,028		1,183
Cash and Cash Equivalents at End of Period		$ 953		$ 1,709
[1]	No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.
[2]	Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean).
[3]	Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 6. Debt.
[4]	Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity (unaudited) - USD ($) $ in Millions	Total		Common Stock	Additional Paid in Capital	Accumulated Other Comprehensive Loss	Treasury Stock at Cost	Retained Earnings
Balance at Beginning of Period at Dec. 31, 2014	$ 10,325		$ 4	$ 3,624	$ (90)	$ (671)	$ 7,458
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Loss	(22)		0	0	0	0	(22)
Stock-based Compensation	21		0	21	0	0	0
Dividends	(64)		0	0	0	0	(64)
Issuance of Shares of Common Stock to Public, Net of Offering Costs	1,112		0	1,112	0	0	0
Other	(15)		0	4	(7)	(12)	0
Balance at End of Period at Mar. 31, 2015	11,357		4	4,761	(97)	(683)	7,372
Balance at Beginning of Period at Dec. 31, 2015	10,370		5	6,360	(33)	(688)	4,726
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Loss	(287)	[1]	0	0	0	0	(287)
Stock-based Compensation	19		0	19	0	0	0
Dividends	(41)		0	0	0	0	(41)
Other	(9)		0	(1)	0	(8)	0
Balance at End of Period at Mar. 31, 2016	$ 10,052		$ 5	$ 6,378	$ (33)	$ (696)	$ 4,398
[1]	No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Consolidated Statements of Sha8

Consolidated Statements of Shareholders' Equity (unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.10	$ 0.18

Organization and Nature of Oper

Organization and Nature of Operations	3 Months Ended
	Mar. 31, 2016
Organization and Nature of Operations [Abstract]
Organization and Nature of Operations	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 (DJ Basin, Marcellus Shale, Eagle Ford Shale, and Permian Basin), deepwater Gulf of Mexico, offshore Eastern Mediterranean and offshore West Africa.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2016
Basis of Presentation [Abstract]
Basis of Presentation	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 March 31, 2016 and December 31, 2015 and for the three months ended March 31, 2016 and 2015 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 months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 . 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, 2015 . 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. 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. Issuance of Phantom Units On February 1, 2016, we issued cash-settled awards to certain employees under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (phantom units; nomenclature used in accounting literature), a portion of which are subject to the achievement of specific performance goals. These phantom units, once vested, are settled in cash. The phantom units represent a hypothetical interest in the Company and are equivalent in value to the phantom unit value. The phantom unit value is the lesser of the fair market value of a share of common stock of the Company as of the vesting date or four times the fair market value of a share of common stock of the Company as of the grant date, which was $31.65 . The Company recognizes the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation . The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. As of March 31, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 7. Fair Value Measurements and Disclosures . Recently Issued Accounting Standards In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation , to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. We are currently evaluating the effect that the guidance will have on our consolidated financial statements and related disclosures. In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures , to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. While we are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures, we believe it is likely to have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In July 2015, the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory , effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We follow the average cost method and are currently evaluating the provisions of ASU 2015-11 and assessing the impact, if any, it may have on our financial position and results of operations. In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis , which changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. As of March 31, 2016, we have adopted the provisions of ASU 2015-02, which did not impact our consolidated financial statements. In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . 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 standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. We are continuing to evaluate the provisions of ASU 2014-09 and have not yet determined the full impact it may have on our financial position and results of operations. At a minimum, we expect we will be required to change from the entitlements method used for certain domestic natural gas sales to the sales method of accounting. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended (millions) 2016 2015 Production Expense Lease Operating Expense $ 161 $ 157 Production and Ad Valorem Taxes (1) 4 32 Transportation and Gathering Expense (2) 107 65 Total $ 272 $ 254 Other Operating (Income) Expense, Net Loss on Asset Due to Terminated Contract (3) $ 42 $ — Marketing and Processing Expense, Net (4) 22 6 Asset Impairments (5) — 27 Gain on Extinguishment of Debt (6) (80 ) — Other, Net 19 1 Total $ 3 $ 34 Other Non-Operating (Income) Expense, Net Deferred Compensation Expense (7) — $ 2 Other (Income) Expense, Net (4 ) (1 ) Total $ (4 ) $ 1 (1) The reduction in production and ad valorem taxes is primarily due to the accrual of a $28 million onshore US severance tax receivable during first quarter 2016. (2) Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense and prior year amounts have been reclassified to conform to the current presentation. (3) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update . (4) In 2016, amount includes $16 million of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (5) Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean). (6) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 6. Debt . (7) Amounts represent decreases in the fair value of shares of our common stock held in a rabbi trust. Balance Sheet Information Other balance sheet information is as follows: (millions) March 31, December 31, Accounts Receivable, Net Commodity Sales $ 308 $ 298 Joint Interest Billings 51 20 Proceeds Receivable (1) 40 — Severance Tax Refund (2) 28 — Other 128 151 Allowance for Doubtful Accounts (24 ) (19 ) Total $ 531 $ 450 Other Current Assets Inventories, Materials and Supplies $ 90 $ 92 Inventories, Crude Oil 27 23 Assets Held for Sale (3) — 67 Prepaid Expenses and Other Current Assets 37 34 Total $ 154 $ 216 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 461 $ 453 Mutual Fund Investments 77 90 Commodity Derivative Assets 6 10 Other Assets 70 67 Total $ 614 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 162 $ 166 Income Taxes Payable 71 86 Asset Retirement Obligations 128 128 Interest Payable 94 83 Current Portion of Capital Lease Obligations 54 53 Other 92 161 Total $ 601 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 214 $ 217 Asset Retirement Obligations 872 861 Production and Ad Valorem Taxes 76 68 Other 71 73 Total $ 1,233 $ 1,219 (1) Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures . (2) Amount relates to the accrual of a $28 million onshore US severance tax receivable. (3) Assets held for sale at December 31, 2015 included our Karish and Tanin natural gas discoveries, offshore Israel. The sale closed first quarter 2016. See Note 4. Divestitures .

Rosetta Merger Rosetta Merger

Rosetta Merger Rosetta Merger	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Rosetta Merger	Rosetta Merger On July 20, 2015, Noble Energy completed the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statements of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta common stock using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin ( 45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs in 2015 of approximately $81 million , including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and were included in Other Operating (Income) Expense, Net. Allocation of Purchase Price The merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair value at the merger date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final assessment of deferred taxes based upon the underlying tax basis of Rosetta's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the merger date, in line with the acquisition method of accounting, during which time the value of the assets and liabilities may be revised as appropriate. The following table sets forth our preliminary purchase price allocation which was based on fair values of assets acquired and liabilities assumed at the merger date, July 20, 2015, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill: (in millions, except stock price) Shares of Noble Energy common stock issued to Rosetta shareholders 41 Noble Energy common stock price on July 20, 2015 $ 36.97 Fair value of common stock issued $ 1,518 Plus: fair value of Rosetta's restricted stock awards and performance awards assumed 10 Plus: Rosetta stock options assumed 1 Total purchase price 1,529 Plus: liabilities assumed by Noble Energy Accounts Payable 100 Current Liabilities 37 Long Term Deferred Tax Liability 8 Long-Term Debt 1,992 Other Long Term Liabilities 23 Asset Retirement Obligation 27 Total purchase price plus liabilities assumed $ 3,716 Fair Value of Rosetta Assets Cash and Equivalents $ 61 Other Current Assets 76 Derivative Instruments 209 Oil and Gas Properties Proved Reserves 1,613 Undeveloped Leaseholds 1,355 Gathering & Processing Assets 207 Asset Retirement Obligation 27 Other Property Plant and Equipment 5 Goodwill 163 Total Asset Value $ 3,716 The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. 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. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs. The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $87 million and pre-tax net loss of $31 million from Rosetta were generated during first quarter 2016. Proforma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) adjustments to conform Rosetta's historical policy of accounting for its crude oil and natural gas properties from the full cost method to the successful efforts method of accounting, (ii) depletion of Rosetta's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results. Three Months Ended (in millions, except per share amounts) 2016 (1) 2015 Revenues $ 724 $ 894 Net Loss $ (287 ) $ (27 ) Loss per share Basic $ (0.67 ) $ (0.07 ) Diluted $ (0.67 ) $ (0.07 ) (1) No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Divestitures

Divestitures	3 Months Ended
	Mar. 31, 2016
Divestitures [Abstract]
Divestitures	Divestitures Offshore Israel Assets In November 2015, we executed an agreement to divest our 47% interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields, for a total transaction value of $73 million . These assets were held for sale as of December 31, 2015, and the transaction closed in January 2016. Cyprus Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million . In first quarter 2016, we received proceeds of $131 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million , subject to post-close adjustments, in 2017. The proceeds were applied to the Cyprus project asset with no gain or loss recognized. Onshore US Properties During first quarter 2016, we sold certain onshore US crude oil and natural gas properties, generating net proceeds of $20 million . Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss. During first quarter 2015, we sold certain onshore US crude oil and natural gas properties, generating net proceeds of $119 million . Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss. Subsequent Event On May 2, 2016, we entered into a purchase and sale agreement for the divestiture of certain producing and undeveloped crude oil and natural gas interests in approximately 33,100 net acres in Weld County, Colorado for $505 million , subject to customary closing adjustments. The divestiture is expected to close during 2016, with an effective date of April 1, 2016; however, there can be no assurance that the transaction contemplated by the agreement will be consummated.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil and natural gas prices. 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. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity 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 March 31, 2016 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2Q16 (1) Swaps NYMEX WTI 5,000 $ 54.16 $ — $ — $ — 2H16 (1) Call Option (2) NYMEX WTI 5,000 — — — 54.16 2H16 (1) Swaps NYMEX WTI 4,000 47.34 — — — 2H16 (1) Two-Way Collars NYMEX WTI 6,000 — — 35.00 49.82 2016 Swaps NYMEX WTI 12,000 74.47 — — — 2016 Swaps (3) (4) 6,000 90.28 — — — — 2016 Two-Way Collars NYMEX WTI 1,000 — — 60.00 70.00 2016 Three-Way Collars NYMEX WTI 6,000 — 61.00 72.50 86.37 2016 Swaps Dated Brent 9,000 97.96 — — — 2016 Three-Way Collars Dated Brent 8,000 — 72.50 86.25 101.79 1H17 (1) Swaps NYMEX WTI 3,000 60.12 — — — 1H17 (1) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (1) Swaps Dated Brent 3,000 62.80 — — — 2H17 (1) Call Option (2) NYMEX WTI 3,000 — — — 60.12 2H17 (1) Swaptions (5) Dated Brent 3,000 — — — 62.80 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.29 2017 Call Option (2) NYMEX WTI 3,000 — — — 57.00 2017 Swaptions (5) NYMEX WTI 4,000 — — — 47.34 (1) We have entered into NYMEX WTI swap contracts for portions of 2016 and 2017 resulting in the difference in hedge volumes for the full year. (2) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms. (3) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (4) The index for these derivative instruments is NYMEX WTI and Argus LLS indices. (5) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend for an additional 6-month or 12-month period. Options covering a notional volume of 3,000 Bbls/d are exercisable on June 30, 2017. If the counterparties exercise all such options, the notional volume of our existing Dated Brent derivative contracts will increase by 3,000 Bbls/d at a weighted average price of $62.80 per Bbl for each month during the period July 1, 2017 through December 31, 2017. Options covering a notional volume of 4,000 Bbls/d are exercisable on December 30, 2016. If the counterparties exercise all such options, the notional volume of our existing NYMEX WTI derivative contracts will increase by 4,000 Bbls/d at a weighted average price of $47.34 per Bbl for each month during the period July 1, 2017 through December 31, 2017. As of March 31, 2016 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2H16 Swaps NYMEX HH 30,000 $ 2.77 $ — $ — $ — 2016 Swaps NYMEX HH 40,000 3.60 — — — 2016 Two-Way Collars NYMEX HH 30,000 — — 3.00 3.50 2016 Three-Way Collars NYMEX HH 90,000 — 2.83 3.42 3.90 2016 Swaps (1) (2) 30,000 4.04 — — — 2016 Two-Way Collars (1) (2) 30,000 — — 3.50 5.60 2017 Swaptions (3) NYMEX HH 60,000 — — — 3.14 (1) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (2) The index for these derivative instruments includes a combination of Houston Ship Channel and Tennessee Zone 0 indices. (3) We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 60,000 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 60,000 MMBtu/d at a weighted average price of $ 3.14 per MMBtu for each month during the period January 1, 2017 through December 31, 2017. 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 March 31, December 31, March 31, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 454 Current Assets $ 582 Current Liabilities $ 2 Current Liabilities $ — Noncurrent Assets 6 Noncurrent Assets 10 Noncurrent Liabilities 1 Noncurrent Liabilities — Total $ 460 $ 592 $ 3 $ — The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended (millions) 2016 2015 Cash Received in Settlement of Commodity Derivative Instruments Crude Oil $ (156 ) $ (185 ) Natural Gas (22 ) (25 ) Total Cash Received in Settlement of Commodity Derivative Instruments (178 ) (210 ) Non-cash Portion of Loss on Commodity Derivative Instruments Crude Oil 127 55 Natural Gas 7 5 Total Non-cash Portion of Loss on Commodity Derivative Instruments 134 60 Gain on Commodity Derivative Instruments Crude Oil (29 ) (130 ) Natural Gas (15 ) (20 ) Total Gain on Commodity Derivative Instruments $ (44 ) $ (150 )

Debt

Debt	3 Months Ended
	Mar. 31, 2016
Debt [Abstract]
Debt	Debt Debt consists of the following: March 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — % $ — — % Capital Lease and Other Obligations 390 — % 403 — % Term Loan Facility, due January 6, 2019 1,400 1.69 % — — % 8.25% Senior Notes, due March 1, 2019 1,000 8.25 % 1,000 8.25 % 5.625% Senior Notes, due May 1, 2021 379 5.625 % 693 5.63 % 4.15% Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % 5.875% Senior Notes, due June 1, 2022 18 5.875 % 597 5.88 % 7.25% Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % 5.875% Senior Notes, due June 1, 2024 8 5.875 % 499 5.88 % 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 7,979 7,976 Unamortized Discount (24 ) (24 ) Unamortized Premium 19 113 Unamortized Debt Issuance Costs (38 ) (36 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,936 8,029 Less Amounts Due Within One Year Capital Lease Obligations (54 ) (53 ) Long-Term Debt Due After One Year $ 7,882 $ 7,976 Revolving Credit Facility Our Credit Agreement, as amended, provides for a $4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating, and (iii) includes a sub-limit for letters of credit up to an aggregate amount of $500 million ( $450 million of which is committed as of March 31, 2016). Term Loan Agreement and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility) with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three -year term loan facility for a principal amount of $1.4 billion . Provisions of the Term Loan Facility are consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility may be prepaid prior to maturity without premium. The Term Loan Facility will accrue interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5% , and (iii) a London interbank offered rate plus 1.0% , plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) a London interbank offered rate, plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. The interest rate for our Term Loan Facility is 1.69% as of March 31, 2016. In connection with the Term Loan Facility, we launched cash tender offers for the 5.875% Senior Notes due June 1, 2024, 5.875% Senior Notes due June 1, 2022 and 5.625% Senior Notes due May 1, 2021, all of which were assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Approximately $1.38 billion of notes were validly tendered and accepted by us, with a corresponding amount borrowed under the new Term Loan Facility. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations. See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Fair Value Measurements and Dis

Fair Value Measurements and Disclosures	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements and Disclosures	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 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, three-way collars, swaptions and enhanced swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 5. Derivative Instruments and Hedging Activities . Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above . Phantom Units The fair value of phantom unit awards is measured based on the fair market value of our common stock on the date of grant. We recognize the value of these awards utilizing the liability method whereby these liability awards are remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 2. Basis of Presentation . Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement (millions) March 31, 2016 Financial Assets Mutual Fund Investments $ 77 $ — $ — $ — $ 77 Commodity Derivative Instruments — 472 — (12 ) 460 Financial Liabilities Commodity Derivative Instruments — (15 ) — 12 (3 ) Portion of Deferred Compensation Liability Measured at Fair Value (96 ) — — — (96 ) Portion of Stock Based Compensation Liability Measured at Fair Value (1 ) — — — (1 ) December 31, 2015 Financial Assets Mutual Fund Investments $ 90 $ — $ — $ — $ 90 Commodity Derivative Instruments — 600 — (8 ) 592 Financial Liabilities Commodity Derivative Instruments — (8 ) — 8 — Portion of Deferred Compensation Liability Measured at Fair Value (98 ) — — — (98 ) (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 Quoted Prices in Significant Other Significant Net Book Value (1) Total Pre-tax (Non-cash) Impairment Loss (millions) Three Months Ended March 31, 2016 Impaired Oil and Gas Properties $ — $ — $ — $ — $ — Three Months Ended March 31, 2015 Impaired Oil and Gas Properties — — — 27 27 (1) Amount represents net book value at the date of assessment. The fair value of impaired crude oil and natural gas properties was determined as of the date of the assessment using a discounted cash flow model based on management’s expectations of future production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent futures price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate. First quarter 2015 impairments were due primarily to increases in asset carrying values associated with increases in estimated abandonment costs. Additional Fair Value Disclosures Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy. Our Term Loan Facility is variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of our Term Loan 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: March 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 7,546 $ 7,334 $ 7,626 $ 7,105 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	3 Months Ended
	Mar. 31, 2016
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	Capitalized Exploratory Well Costs and Undeveloped Leasehold 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. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. 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) Three Months Ended March 31, 2016 Capitalized Exploratory Well Costs, Beginning of Period $ 1,353 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 22 Divestitures (1) (143 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (2 ) Capitalized Exploratory Well Costs Charged to Expense (2) (56 ) Capitalized Exploratory Well Costs, End of Period $ 1,174 (1) Represents our farm-out of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) Includes $42 million relating to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. 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) March 31, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 63 $ 95 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 1,111 1,258 Balance at End of Period $ 1,174 $ 1,353 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 14 14 The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of March 31, 2016 : (millions) Total by Project Progress Country/Project: Deepwater Gulf of Mexico Troubadour 49 Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. Katmai 93 Commenced drilling of an appraisal well in April 2016 to test the resource potential of this 2014 crude oil discovery. Offshore Equatorial Guinea (Blocks I and O) Diega (Block I) and Carmen (Block O) 235 Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and are interpreting and evaluating the acquired seismic data. Carla (Block O) 180 Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and are interpreting and evaluating the acquired seismic data. Yolanda/Felicita 66 Evaluating regional development plans for these 2007/2008 condensate and natural gas discoveries. Natural gas development teams are working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize data exchange agreements between the two countries. Offshore Cameroon YoYo 52 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. Our 50% working interest partner has given notice to us and the Cameroon government of their intention to exit this acreage position. Once the assignment process is finalized, we will hold 100% operating working interest. We have begun efforts to market this additional working interest. Offshore Israel Leviathan 194 We are engaged in natural gas marketing activities for both export and domestic Israeli customers. We have submitted a Plan of Development to the Government of Israel and continue to pursue financing arrangements to support development. The Natural Gas Framework was enacted in 2015 and subsequently affirmed by the Israeli Supreme Court, with the exception of the stability provisions. The Court concluded that the Government of Israel should provide stability assurances and provisions through an alternate legal mechanism and provided the Government up to one year to resolve this matter. In first quarter 2016, Israel's National Planning Commission approved the platform location and gas interconnect. Leviathan-1 Deep 82 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. See also Leviathan, above, for discussion of Natural Gas Framework. 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 26 Reviewing regional development scenarios for this 2011 natural gas discovery, including a potential tieback to Leviathan. We have applied to the government for a commerciality ruling and our license has been extended to second quarter 2016. Offshore Cyprus Cyprus 84 We continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will enable us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. During fourth quarter 2015, we farmed-out a 35% working interest. Other Individual Projects Less than $20 million 22 Continuing to assess and evaluate wells. Total $ 1,111 Undeveloped Leasehold Costs As of March 31, 2016, we had capitalized undeveloped leasehold costs of $2.3 billion , of which approximately $2 billion relates to our core operating areas onshore US and is included in our quarterly impairment testing for these areas. In addition, we have capitalized undeveloped leasehold of $57 million relating to international operations,and $255 million relating to deepwater Gulf of Mexico. Significant undeveloped leases, primarily in deepwater Gulf of Mexico, are individually assessed for impairment. While none of our undeveloped leases were impaired as of March 31, 2016, if, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, changing regulations and/or other factors, an impairment is indicated, a valuation allowance will be provided. Costs of individually insignificant leases are combined and amortized over their lease term. Expense associated with either impairment or amortization of undeveloped leases is included in exploration expense in our consolidated statement of operations.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Three Months Ended (millions) 2016 2015 Asset Retirement Obligations, Beginning Balance $ 989 $ 751 Liabilities Incurred 2 10 Liabilities Settled (8 ) (8 ) Revision of Estimate 5 24 Accretion Expense (1) 12 10 Asset Retirement Obligations, Ending Balance $ 1,000 $ 787 (1) Accretion expense is included in DD&A expense in the consolidated statements of operations. For the three months ended March 31, 2016 Liabilities incurred were due to new wells and facilities for onshore US. Liabilities settled primarily related to onshore US property abandonments. Revisions of estimates relate to changes in cost estimates of $5 million for Equatorial Guinea. 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.

Loss Per Share

Loss Per Share	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Loss Per Share	Loss Per Share Basic loss per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The following table summarizes the calculation of basic and diluted loss per share: Three Months Ended (millions, except per share amounts) 2016 2015 Net Loss $ (287 ) $ (22 ) Weighted Average Number of Shares Outstanding, Basic (1) 429 370 Weighted Average Number of Shares Outstanding, Diluted (2) 429 370 Loss Per Share, Basic $ (0.67 ) $ (0.06 ) Loss Per Share, Diluted (0.67 ) (0.06 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 15 9 (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 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015. (2) For the three months ended March 31, 2016 and March 31, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy incurred a net loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted loss per share would be anti-dilutive.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax benefit consists of the following: Three Months Ended (millions) 2016 2015 Current $ 20 $ 10 Deferred (186 ) (30 ) Total Income Tax Benefit $ (166 ) $ (20 ) Effective Tax Rate 36.6 % 47.6 % Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2015, we no longer consider our foreign subsidiaries’ undistributed earnings to be indefinitely reinvested outside the United States and, accordingly, recorded additional deferred income taxes, net of estimated foreign tax credits. Effective Tax Rate (ETR) Our ETR decreased first quarter 2016 as compared with first quarter 2015. This is primarily due to a higher income tax benefit as compared with the change in the components of the overall net loss from period to period, which is impacted by certain income items with different tax rates. Also, during first quarter 2016, the change in our permanent reinvestment assumption, noted above, resulted in additional deferred income tax expense (net of estimated foreign tax credits) being recorded on certain income items, including income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate. This additional deferred income tax expense had the result of offsetting our income tax benefit to a greater extent in first quarter 2016 thereby driving the ETR lower than it would have been if additional deferred taxes had not been recorded. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2012 , Equatorial Guinea – 2010 and Israel – 2011 .

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segment Information	Segment Information We have operations throughout the world and manage our global 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, Gabon and Sierra Leone (which we exited in second quarter 2015); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, Falkland Islands, Suriname, Nicaragua (which we exited in first quarter 2015) and new ventures. (millions) Consolidated United States West Africa Eastern Mediterranean Other Int'l & Corporate Three Months Ended March 31, 2016 Revenues from Third Parties $ 705 $ 489 $ 90 $ 126 $ — Income from Equity Method Investees 19 16 3 — — Total Revenues 724 505 93 126 — DD&A 617 530 55 20 12 Gain on Commodity Derivative Instruments (44 ) (37 ) (7 ) — — Income (Loss) Before Income Taxes (453 ) (292 ) 9 84 (254 ) Three Months Ended March 31, 2015 Revenues from Third Parties $ 749 $ 487 $ 138 $ 120 $ 4 Income from Equity Method Investees 18 11 7 — — Total Revenues 767 498 145 120 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 ) March 31, 2016 Total Assets $ 23,413 $ 18,387 $ 2,233 $ 2,459 $ 334 December 31, 2015 Total Assets 24,196 18,831 2,299 2,677 389

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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 (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at March 31, 2016 . 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 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; however, the funding was suspended again in November 2014 due to lower natural gas prices. Based on the March 31, 2016 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months. Delivery and Firm Transportation Commitments We have commitments to deliver approximately 437 Bcf of natural gas produced onshore US (primarily in the Marcellus Shale) and have also entered into various long-term gathering, processing and transportation contracts for some of our onshore US crude oil and natural gas production (in the Marcellus Shale, DJ Basin and Eagle Ford Shale). We enter into long-term contracts to provide production flow assurance in over-supplied markets and/or markets with limited infrastructure. This strategy provides for optimization of transportation and processing costs. As properties are undergoing development activities, we may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. During first quarter 2016, we incurred expense of approximately $16 million related to deficiencies and/or unutilized commitments. We expect to continue to incur deficiency and/or unutilized costs in the near-term as development activities continue. Should commodity prices continue to decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset. 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. Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the Court on June 2, 2015. 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, requires us to perform certain injunctive relief activities to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are not yet precisely quantifiable as they 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 contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. 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 the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. Colorado Air Compliance Order on Consent In December 2015, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment's Air Pollution Control Division to resolve allegations of noncompliance associated with certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions. The COC, which provided for an opportunity to further discuss the offer of settlement, has not yet been executed. At present, the revised COC seeks completion of compliance testing, modification of certain permits, submission of a notice and payment of a reduced penalty of $223,475 , of which up to 80% may be mitigated by pursuing a SEP or SEPs. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	3 Months Ended
	Mar. 31, 2016
Basis of Presentation [Abstract]
Statement of Operations Information	Statements of Operations Information Other statements of operations information is as follows: Three Months Ended (millions) 2016 2015 Production Expense Lease Operating Expense $ 161 $ 157 Production and Ad Valorem Taxes (1) 4 32 Transportation and Gathering Expense (2) 107 65 Total $ 272 $ 254 Other Operating (Income) Expense, Net Loss on Asset Due to Terminated Contract (3) $ 42 $ — Marketing and Processing Expense, Net (4) 22 6 Asset Impairments (5) — 27 Gain on Extinguishment of Debt (6) (80 ) — Other, Net 19 1 Total $ 3 $ 34 Other Non-Operating (Income) Expense, Net Deferred Compensation Expense (7) — $ 2 Other (Income) Expense, Net (4 ) (1 ) Total $ (4 ) $ 1 (1) The reduction in production and ad valorem taxes is primarily due to the accrual of a $28 million onshore US severance tax receivable during first quarter 2016. (2) Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense and prior year amounts have been reclassified to conform to the current presentation. (3) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update . (4) In 2016, amount includes $16 million of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (5) Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean). (6) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 6. Debt . (7) Amounts represent decreases in the fair value of shares of our common stock held in a rabbi trust.
Balance Sheet Information Table	Balance Sheet Information Other balance sheet information is as follows: (millions) March 31, December 31, Accounts Receivable, Net Commodity Sales $ 308 $ 298 Joint Interest Billings 51 20 Proceeds Receivable (1) 40 — Severance Tax Refund (2) 28 — Other 128 151 Allowance for Doubtful Accounts (24 ) (19 ) Total $ 531 $ 450 Other Current Assets Inventories, Materials and Supplies $ 90 $ 92 Inventories, Crude Oil 27 23 Assets Held for Sale (3) — 67 Prepaid Expenses and Other Current Assets 37 34 Total $ 154 $ 216 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 461 $ 453 Mutual Fund Investments 77 90 Commodity Derivative Assets 6 10 Other Assets 70 67 Total $ 614 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 162 $ 166 Income Taxes Payable 71 86 Asset Retirement Obligations 128 128 Interest Payable 94 83 Current Portion of Capital Lease Obligations 54 53 Other 92 161 Total $ 601 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 214 $ 217 Asset Retirement Obligations 872 861 Production and Ad Valorem Taxes 76 68 Other 71 73 Total $ 1,233 $ 1,219 (1) Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures . (2) Amount relates to the accrual of a $28 million onshore US severance tax receivable. (3) Assets held for sale at December 31, 2015 included our Karish and Tanin natural gas discoveries, offshore Israel. The sale closed first quarter 2016. See Note 4. Divestitures .

Rosetta Merger Rosetta Merger (

Rosetta Merger Rosetta Merger (Tables)	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Schedule of purchase price allocations	The following table sets forth our preliminary purchase price allocation which was based on fair values of assets acquired and liabilities assumed at the merger date, July 20, 2015, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill: (in millions, except stock price) Shares of Noble Energy common stock issued to Rosetta shareholders 41 Noble Energy common stock price on July 20, 2015 $ 36.97 Fair value of common stock issued $ 1,518 Plus: fair value of Rosetta's restricted stock awards and performance awards assumed 10 Plus: Rosetta stock options assumed 1 Total purchase price 1,529 Plus: liabilities assumed by Noble Energy Accounts Payable 100 Current Liabilities 37 Long Term Deferred Tax Liability 8 Long-Term Debt 1,992 Other Long Term Liabilities 23 Asset Retirement Obligation 27 Total purchase price plus liabilities assumed $ 3,716 Fair Value of Rosetta Assets Cash and Equivalents $ 61 Other Current Assets 76 Derivative Instruments 209 Oil and Gas Properties Proved Reserves 1,613 Undeveloped Leaseholds 1,355 Gathering & Processing Assets 207 Asset Retirement Obligation 27 Other Property Plant and Equipment 5 Goodwill 163 Total Asset Value $ 3,716
Schedule of pro forma information	Three Months Ended (in millions, except per share amounts) 2016 (1) 2015 Revenues $ 724 $ 894 Net Loss $ (287 ) $ (27 ) Loss per share Basic $ (0.67 ) $ (0.07 ) Diluted $ (0.67 ) $ (0.07 ) (1) No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Derivative Instruments and He24

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unsettled Derivative Instruments	Unsettled Commodity Derivative Instruments As of March 31, 2016 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2Q16 (1) Swaps NYMEX WTI 5,000 $ 54.16 $ — $ — $ — 2H16 (1) Call Option (2) NYMEX WTI 5,000 — — — 54.16 2H16 (1) Swaps NYMEX WTI 4,000 47.34 — — — 2H16 (1) Two-Way Collars NYMEX WTI 6,000 — — 35.00 49.82 2016 Swaps NYMEX WTI 12,000 74.47 — — — 2016 Swaps (3) (4) 6,000 90.28 — — — — 2016 Two-Way Collars NYMEX WTI 1,000 — — 60.00 70.00 2016 Three-Way Collars NYMEX WTI 6,000 — 61.00 72.50 86.37 2016 Swaps Dated Brent 9,000 97.96 — — — 2016 Three-Way Collars Dated Brent 8,000 — 72.50 86.25 101.79 1H17 (1) Swaps NYMEX WTI 3,000 60.12 — — — 1H17 (1) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (1) Swaps Dated Brent 3,000 62.80 — — — 2H17 (1) Call Option (2) NYMEX WTI 3,000 — — — 60.12 2H17 (1) Swaptions (5) Dated Brent 3,000 — — — 62.80 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.29 2017 Call Option (2) NYMEX WTI 3,000 — — — 57.00 2017 Swaptions (5) NYMEX WTI 4,000 — — — 47.34 (1) We have entered into NYMEX WTI swap contracts for portions of 2016 and 2017 resulting in the difference in hedge volumes for the full year. (2) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms. (3) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (4) The index for these derivative instruments is NYMEX WTI and Argus LLS indices. (5) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend for an additional 6-month or 12-month period. Options covering a notional volume of 3,000 Bbls/d are exercisable on June 30, 2017. If the counterparties exercise all such options, the notional volume of our existing Dated Brent derivative contracts will increase by 3,000 Bbls/d at a weighted average price of $62.80 per Bbl for each month during the period July 1, 2017 through December 31, 2017. Options covering a notional volume of 4,000 Bbls/d are exercisable on December 30, 2016. If the counterparties exercise all such options, the notional volume of our existing NYMEX WTI derivative contracts will increase by 4,000 Bbls/d at a weighted average price of $47.34 per Bbl for each month during the period July 1, 2017 through December 31, 2017. As of March 31, 2016 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2H16 Swaps NYMEX HH 30,000 $ 2.77 $ — $ — $ — 2016 Swaps NYMEX HH 40,000 3.60 — — — 2016 Two-Way Collars NYMEX HH 30,000 — — 3.00 3.50 2016 Three-Way Collars NYMEX HH 90,000 — 2.83 3.42 3.90 2016 Swaps (1) (2) 30,000 4.04 — — — 2016 Two-Way Collars (1) (2) 30,000 — — 3.50 5.60 2017 Swaptions (3) NYMEX HH 60,000 — — — 3.14 (1) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (2) The index for these derivative instruments includes a combination of Houston Ship Channel and Tennessee Zone 0 indices. (3) We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 60,000 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 60,000 MMBtu/d at a weighted average price of $ 3.14 per MMBtu for each month during the period January 1, 2017 through December 31, 2017.
Fair Value of Derivative Instruments	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 March 31, December 31, March 31, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 454 Current Assets $ 582 Current Liabilities $ 2 Current Liabilities $ — Noncurrent Assets 6 Noncurrent Assets 10 Noncurrent Liabilities 1 Noncurrent Liabilities — Total $ 460 $ 592 $ 3 $ —
Derivative Instruments, (Gain) Loss	The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended (millions) 2016 2015 Cash Received in Settlement of Commodity Derivative Instruments Crude Oil $ (156 ) $ (185 ) Natural Gas (22 ) (25 ) Total Cash Received in Settlement of Commodity Derivative Instruments (178 ) (210 ) Non-cash Portion of Loss on Commodity Derivative Instruments Crude Oil 127 55 Natural Gas 7 5 Total Non-cash Portion of Loss on Commodity Derivative Instruments 134 60 Gain on Commodity Derivative Instruments Crude Oil (29 ) (130 ) Natural Gas (15 ) (20 ) Total Gain on Commodity Derivative Instruments $ (44 ) $ (150 )

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt [Abstract]
Schedule of debt	Debt consists of the following: March 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — % $ — — % Capital Lease and Other Obligations 390 — % 403 — % Term Loan Facility, due January 6, 2019 1,400 1.69 % — — % 8.25% Senior Notes, due March 1, 2019 1,000 8.25 % 1,000 8.25 % 5.625% Senior Notes, due May 1, 2021 379 5.625 % 693 5.63 % 4.15% Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % 5.875% Senior Notes, due June 1, 2022 18 5.875 % 597 5.88 % 7.25% Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % 5.875% Senior Notes, due June 1, 2024 8 5.875 % 499 5.88 % 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 7,979 7,976 Unamortized Discount (24 ) (24 ) Unamortized Premium 19 113 Unamortized Debt Issuance Costs (38 ) (36 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,936 8,029 Less Amounts Due Within One Year Capital Lease Obligations (54 ) (53 ) Long-Term Debt Due After One Year $ 7,882 $ 7,976

Fair Value Measurements and D26

Fair Value Measurements and Disclosures (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement (millions) March 31, 2016 Financial Assets Mutual Fund Investments $ 77 $ — $ — $ — $ 77 Commodity Derivative Instruments — 472 — (12 ) 460 Financial Liabilities Commodity Derivative Instruments — (15 ) — 12 (3 ) Portion of Deferred Compensation Liability Measured at Fair Value (96 ) — — — (96 ) Portion of Stock Based Compensation Liability Measured at Fair Value (1 ) — — — (1 ) December 31, 2015 Financial Assets Mutual Fund Investments $ 90 $ — $ — $ — $ 90 Commodity Derivative Instruments — 600 — (8 ) 592 Financial Liabilities Commodity Derivative Instruments — (8 ) — 8 — Portion of Deferred Compensation Liability Measured at Fair Value (98 ) — — — (98 ) (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.
Fair Value Measurements, Nonrecurring	Asset Impairments Information about impaired assets is as follows: Fair Value Measurements Using Quoted Prices in Significant Other Significant Net Book Value (1) Total Pre-tax (Non-cash) Impairment Loss (millions) Three Months Ended March 31, 2016 Impaired Oil and Gas Properties $ — $ — $ — $ — $ — Three Months Ended March 31, 2015 Impaired Oil and Gas Properties — — — 27 27 (1) Amount represents net book value at the date of assessment.
Additional fair value disclosures	Fair value information regarding our debt is as follows: March 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 7,546 $ 7,334 $ 7,626 $ 7,105 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well 27

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)	3 Months Ended
	Mar. 31, 2016
Capitalized Exploratory Well Costs [Abstract]
Changes in Capitalized Exploratory Well Costs	Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions) Three Months Ended March 31, 2016 Capitalized Exploratory Well Costs, Beginning of Period $ 1,353 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 22 Divestitures (1) (143 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (2 ) Capitalized Exploratory Well Costs Charged to Expense (2) (56 ) Capitalized Exploratory Well Costs, End of Period $ 1,174 (1) Represents our farm-out of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) Includes $42 million relating to the termination
Aging of Capitalized Well Costs	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) March 31, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 63 $ 95 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 1,111 1,258 Balance at End of Period $ 1,174 $ 1,353 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 14 14
Aging of Exploratory Well Costs	The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of March 31, 2016 : (millions) Total by Project Progress Country/Project: Deepwater Gulf of Mexico Troubadour 49 Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. Katmai 93 Commenced drilling of an appraisal well in April 2016 to test the resource potential of this 2014 crude oil discovery. Offshore Equatorial Guinea (Blocks I and O) Diega (Block I) and Carmen (Block O) 235 Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and are interpreting and evaluating the acquired seismic data. Carla (Block O) 180 Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and are interpreting and evaluating the acquired seismic data. Yolanda/Felicita 66 Evaluating regional development plans for these 2007/2008 condensate and natural gas discoveries. Natural gas development teams are working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize data exchange agreements between the two countries. Offshore Cameroon YoYo 52 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. Our 50% working interest partner has given notice to us and the Cameroon government of their intention to exit this acreage position. Once the assignment process is finalized, we will hold 100% operating working interest. We have begun efforts to market this additional working interest. Offshore Israel Leviathan 194 We are engaged in natural gas marketing activities for both export and domestic Israeli customers. We have submitted a Plan of Development to the Government of Israel and continue to pursue financing arrangements to support development. The Natural Gas Framework was enacted in 2015 and subsequently affirmed by the Israeli Supreme Court, with the exception of the stability provisions. The Court concluded that the Government of Israel should provide stability assurances and provisions through an alternate legal mechanism and provided the Government up to one year to resolve this matter. In first quarter 2016, Israel's National Planning Commission approved the platform location and gas interconnect. Leviathan-1 Deep 82 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. See also Leviathan, above, for discussion of Natural Gas Framework. 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 26 Reviewing regional development scenarios for this 2011 natural gas discovery, including a potential tieback to Leviathan. We have applied to the government for a commerciality ruling and our license has been extended to second quarter 2016. Offshore Cyprus Cyprus 84 We continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will enable us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. During fourth quarter 2015, we farmed-out a 35% working interest. Other Individual Projects Less than $20 million 22 Continuing to assess and evaluate wells. Total $ 1,111

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in ARO are as follows: Three Months Ended (millions) 2016 2015 Asset Retirement Obligations, Beginning Balance $ 989 $ 751 Liabilities Incurred 2 10 Liabilities Settled (8 ) (8 ) Revision of Estimate 5 24 Accretion Expense (1) 12 10 Asset Retirement Obligations, Ending Balance $ 1,000 $ 787 (1) Accretion expense is included in DD&A expense in the consolidated statements of operations.

Loss Per Share (Tables)

Loss Per Share (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Schedule of earnings per share	The following table summarizes the calculation of basic and diluted loss per share: Three Months Ended (millions, except per share amounts) 2016 2015 Net Loss $ (287 ) $ (22 ) Weighted Average Number of Shares Outstanding, Basic (1) 429 370 Weighted Average Number of Shares Outstanding, Diluted (2) 429 370 Loss Per Share, Basic $ (0.67 ) $ (0.06 ) Loss Per Share, Diluted (0.67 ) (0.06 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 15 9 (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 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015. (2) For the three months ended March 31, 2016 and March 31, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy incurred a net loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted loss per share would be anti-dilutive.

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax Provision (Benefit)	The income tax benefit consists of the following: Three Months Ended (millions) 2016 2015 Current $ 20 $ 10 Deferred (186 ) (30 ) Total Income Tax Benefit $ (166 ) $ (20 ) Effective Tax Rate 36.6 % 47.6 %

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segment Information	(millions) Consolidated United States West Africa Eastern Mediterranean Other Int'l & Corporate Three Months Ended March 31, 2016 Revenues from Third Parties $ 705 $ 489 $ 90 $ 126 $ — Income from Equity Method Investees 19 16 3 — — Total Revenues 724 505 93 126 — DD&A 617 530 55 20 12 Gain on Commodity Derivative Instruments (44 ) (37 ) (7 ) — — Income (Loss) Before Income Taxes (453 ) (292 ) 9 84 (254 ) Three Months Ended March 31, 2015 Revenues from Third Parties $ 749 $ 487 $ 138 $ 120 $ 4 Income from Equity Method Investees 18 11 7 — — Total Revenues 767 498 145 120 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 ) March 31, 2016 Total Assets $ 23,413 $ 18,387 $ 2,233 $ 2,459 $ 334 December 31, 2015 Total Assets 24,196 18,831 2,299 2,677 389

Basis of Presentation (Details)

Basis of Presentation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Feb. 01, 2016
Share Price					$ 31.65
Production Expense
Lease Operating Expense		$ 161		$ 157
Production and Ad Valorem Taxes (1)	[1]	4		32
Transportation and Gathering Expense (2)	[2]	107		65
Total		272		254
Other Operating (Income) Expense, Net
Loss on Asset Due to Terminated Contract	[3]	42		0
Midstream Gathering and Processing (Income) Expense, Net	[4]	22		6
Asset Impairments	[5]	0		27
Gain on Extinguishment of Debt	[6]	(80)		0
Other, Net		19		1
Total		3		34
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense	[7]	0		2
Other (Income) Expense, Net		(4)		(1)
Total		(4)		$ 1
Additional expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments		16
Accounts Receivable, Net
Commodity Sales		308	$ 298
Joint Interest Billings		51	20
Proceeds Receivable	[8]	40	0
Severance Tax Refund	[9]	28	0
Other		128	151
Allowance for Doubtful Accounts		(24)	(19)
Total		531	450
Other Current Assets
Inventories, Materials and Supplies		90	92
Inventories, Crude Oil		27	23
Assets Held-for-Sale	[10]	0	67
Prepaid Expenses and Other Current Assets		37	34
Total		154	216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries		461	453
Mutual Fund Investments		77	90
Commodity Derivative Assets		6	10
Other Assets		70	67
Total		614	620
Other Current Liabilities
Production and Ad Valorem Taxes		162	166
Income Taxes Payable		71	86
Asset Retirement Obligations		128	128
Interest Payable		94	83
Current Portion of Capital Lease Obligations		54	53
Other		92	161
Total		601	677
Other Noncurrent Liabilities
Deferred Compensation Liabilities		214	217
Asset Retirement Obligations		872	861
Accrual for Taxes Other than Income Taxes		76	68
Other		71	73
Total		$ 1,233	$ 1,219
Percentage of divestiture farmed out		35.00%	35.00%
Phantom Units [Member]
Shares issued					1
State and Local Jurisdiction [Member]
Other Non-Operating (Income) Expense, Net
Accrual of severance tax refund		$ 28
[1]	The reduction in production and ad valorem taxes is primarily due to the accrual of a $28 million onshore US severance tax receivable during first quarter 2016.
[2]	Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense and prior year amounts have been reclassified to conform to the current presentation.
[3]	Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold
[4]	In 2016, amount includes $16 million of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
[5]	Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean).
[6]	Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 6. Debt.
[7]	Amounts represent decreases in the fair value of shares of our common stock held in a rabbi trust.
[8]	Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.
[9]	Amount relates to the accrual of a $28 million onshore US severance tax receivable.
[10]	Assets held for sale at December 31, 2015 included our Karish and Tanin natural gas discoveries, offshore Israel. The sale closed first quarter 2016. See Note 4. Divestitures

Rosetta Merger - Narrative (Det

Rosetta Merger - Narrative (Details) $ / shares in Units, a in Thousands, shares in Millions, $ in Millions		Jul. 20, 2015USD ($)abusiness$ / sharesshares	Mar. 31, 2016USD ($)
Business Acquisition [Line Items]
Shares exchange in acquisition | shares		41
Pro forma revenue			$ 87
Pro forma pre-tax net income			31
Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Shares exchange in acquisition | shares		41
Number of onshore plays added in acquisition | business		2
Merger related costs including noncash share-based compensation expense			81
Rosetta Merger Expenses			66
Merger related costs related to noncash share-based compensation			$ 15
Share price | $ / shares		$ 36.97
Eagle Ford Shale [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Liquid rich asset based acquired | a		50
Permian [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Liquid rich asset based acquired | a		54
Delaware Basin [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Liquid rich asset based acquired | a		45
Midland Basin [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Long-term Debt, Fair Value	[1]	$ 2,000
Liquid rich asset based acquired | a		9
Common Stock | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Exchange ratio of common shares for acquired company		0.542
[1]	Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Rosetta Merger - Assets Acquire

Rosetta Merger - Assets Acquired and Liabilities Assumed (Details) $ / shares in Units, shares in Millions, $ in Millions	Jul. 20, 2015USD ($)$ / sharesshares
Business Acquisition [Line Items]
Shares of Noble Energy common stock issued to Rosetta shareholders (in shares) | shares	41
Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Shares of Noble Energy common stock issued to Rosetta shareholders (in shares) | shares	41
Noble Energy common stock price on July 20, 2015 | $ / shares	$ 36.97
Fair value of common stock issued	$ 1,518
Plus: fair value of Rosetta's restricted stock awards and performance awards assumed	10
Plus: Rosetta stock options assumed	1
Total purchase price	1,529
Plus: liabilities assumed by Noble Energy
Accounts Payable	100
Current Liabilities	37
Long Term Deferred Tax Liability	8
Long-Term Debt	1,992
Other Long Term Liabilities	23
Asset Retirement Obligation	27
Total purchase price plus liabilities assumed	3,716
Fair Value of Rosetta Assets
Cash and Equivalents	61
Other Current Assets	76
Derivative Instruments	209
Oil and Gas Properties
Proved Reserves	1,613
Undeveloped Leaseholds	1,355
Gathering & Processing Assets	207
Asset Retirement Obligation	27
Other Property Plant and Equipment	5
Goodwill	163
Total Asset Value	$ 3,716

Rosetta Merger - Pro Forma Info

Rosetta Merger - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2016	[1]	Mar. 31, 2015
Business Combinations [Abstract]
Revenues	$ 724		$ 894
Net Loss	$ (287)		$ (27)
Loss per share
Basic (in dollars per share)	$ (0.67)		$ (0.07)
Diluted (in dollars per share)	$ (0.67)		$ (0.07)
[1]	No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Divestitures (Details)

Divestitures (Details) $ in Millions	3 Months Ended
	Jun. 30, 2016USD ($)a	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2015USD ($)	Nov. 20, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of divestiture farmed out		35.00%	35.00%
Sales Proceeds		$ 238		$ 119
Alon A And Alon C [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity method investment, ownership percentage					47.00%
Total transaction value					$ 73
Cyprus Block 12 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value			$ 171
Proceeds received from farm-out agreement		131
Consideration subject to post-close adjustments		40
Certain US Crude Oil And Natural Gas Properties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds		$ 20
Subsequent Event [Member] | Weld County, Colorado [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sales agreement, area | a	33,100
Purchase and sales agreement, consideration	$ 505

Derivative Instruments and He37

Derivative Instruments and Hedging Activities (Details)	3 Months Ended
	Mar. 31, 2016bbl / dMMBTU / d$ / bbl$ / MMBTU
Crude Oil Commodity Contract | Swaps - Dated Brent Extension [Member]
Derivative [Line Items]
Bbls Per Day | MMBTU / d	3,000
Weighted Average Fixed Price | $ / MMBTU	62.80	[1]
Crude Oil Commodity Contract | Swaps - NYMEX WTI Extension [Member]
Derivative [Line Items]
Bbls Per Day | MMBTU / d	4,000
Weighted Average Fixed Price | $ / MMBTU	47.34	[1]
Crude Oil Commodity Contract | Swaps - NYMEX WTI Increase [Member]
Derivative [Line Items]
Bbls Per Day | MMBTU / d	4,000
Crude Oil Commodity Contract | Swaps - Dated Brent Increase [Member]
Derivative [Line Items]
Bbls Per Day | MMBTU / d	3,000
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX WTI
Bbls Per Day | bbl / d	12,000
Weighted Average Fixed Price	74.47
Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2016 [Member]
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX WTI
Bbls Per Day | bbl / d	1,000
Weighted Average Floor Price	60
Weighted Average Ceiling Price	70
Crude Oil Commodity Contract | Swaps - Dated Brent 2016
Derivative [Line Items]
Settlement Period	2,016
Index	Dated Brent
Bbls Per Day | bbl / d	9,000
Weighted Average Fixed Price	97.96
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX WTI
Bbls Per Day | bbl / d	6,000
Weighted Average Short Put Price	61
Weighted Average Floor Price	72.50
Weighted Average Ceiling Price	86.37
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2016
Derivative [Line Items]
Settlement Period	2,016
Index	Dated Brent
Bbls Per Day | bbl / d	8,000
Weighted Average Short Put Price	72.50
Weighted Average Floor Price	86.25
Weighted Average Ceiling Price	101.79
Crude Oil Commodity Contract | Call - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	57
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX WTI
Bbls Per Day | bbl / d	4,000
Weighted Average Ceiling Price	47.34
Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX WTI
Bbls Per Day | bbl / d	7,000
Weighted Average Floor Price	40
Weighted Average Ceiling Price	53.29
Natural Gas Commodity Contract | Swaps - NYMEX HH 2016
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	40,000
Weighted Average Fixed Price | $ / MMBTU	3.60
Natural Gas Commodity Contract | Two Way Collars - NYMEX HH 2016
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Floor Price | $ / MMBTU	3
Weighted Average Ceiling Price | $ / MMBTU	3.50
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2016 [Member]
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	90,000
Weighted Average Short Put Price | $ / MMBTU	2.83
Weighted Average Floor Price | $ / MMBTU	3.42
Weighted Average Ceiling Price | $ / MMBTU	3.90
Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	60,000
Weighted Average Ceiling Price | $ / MMBTU	3.14
Natural Gas Commodity Contract | Swaps - NYMEX HH Extension
Derivative [Line Items]
Bbls Per Day | MMBTU / d	60,000
Natural Gas Commodity Contract | Swaps - NYMEX HH Increase
Derivative [Line Items]
Bbls Per Day | MMBTU / d	60,000
Weighted Average Fixed Price | $ / MMBTU	3.14	[1]
Rosetta Resources, Inc [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2,016
Index	(4)
Bbls Per Day | bbl / d	6,000
Weighted Average Fixed Price	90.28
Rosetta Resources, Inc [Member] | Natural Gas Commodity Contract | Swaps - Houston Ship Channel and Tennessee Zone 0 2016 [Member] [Member]
Derivative [Line Items]
Settlement Period	2,016
Index	(2)
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	4.04
Rosetta Resources, Inc [Member] | Natural Gas Commodity Contract | Two Way Collars - Houston Ship Channel and Tennessee Zone 0 2016 [Member]
Derivative [Line Items]
Settlement Period	2,016
Index	(2)
Bbls Per Day | MMBTU / d	30,000
Weighted Average Floor Price | $ / MMBTU	3.50
Weighted Average Ceiling Price | $ / MMBTU	5.60
Second half 2017 [Member] | Crude Oil Commodity Contract | Call - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	60.12
Second half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (1)
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	62.80
Second Quarter 2016 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2Q16 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	5,000
Weighted Average Fixed Price	54.16
Second half 2016 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2H16 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	4,000
Weighted Average Fixed Price	47.34
Second half 2016 [Member] | Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2016 [Member]
Derivative [Line Items]
Settlement Period	2H16 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	6,000
Weighted Average Floor Price	35
Weighted Average Ceiling Price	49.82
Second half 2016 [Member] | Crude Oil Commodity Contract | Call - NYMEX WTI 2016 [Member]
Derivative [Line Items]
Settlement Period	2H16 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	5,000
Weighted Average Ceiling Price	54.16
Second half 2016 [Member] | Natural Gas Commodity Contract | Swaps - NYMEX HH 2016
Derivative [Line Items]
Settlement Period	2H16
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	2.77
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Fixed Price	60.12
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (1)
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Fixed Price	62.80
First half 2017 [Member] | Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (1)
Index	NYMEX WTI
Bbls Per Day | bbl / d	2,000
Weighted Average Floor Price	40
Weighted Average Ceiling Price	50.44
[1]	Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

Derivative Instruments and He38

Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 460		$ 592
Derivative Liability, Fair Value	3		0
Gain on Commodity Derivative Instruments	(44)	$ (150)
Non-cash Portion of Loss on Commodity Derivative Instruments	(178)	(210)
Gain on Commodity Derivative Instruments	134	60
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	454		582
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	2		0
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	6		10
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	1		$ 0
Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Gain on Commodity Derivative Instruments	(29)	(130)
Non-cash Portion of Loss on Commodity Derivative Instruments	(156)	(185)
Gain on Commodity Derivative Instruments	127	55
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Gain on Commodity Derivative Instruments	(15)	(20)
Non-cash Portion of Loss on Commodity Derivative Instruments	(22)	(25)
Gain on Commodity Derivative Instruments	$ 7	$ 5

Debt (Details)

Debt (Details) - USD ($)	Jan. 06, 2016	Mar. 31, 2016	Dec. 31, 2015	Aug. 27, 2015
Debt Instrument [Line Items]
Debt		$ 7,979,000,000	$ 7,976,000,000
Unamortized Discount		(24,000,000)	(24,000,000)
Debt Instrument, Unamortized Premium		19,000,000	113,000,000
Total Debt, Net of Discount		7,936,000,000	8,029,000,000
Capital Lease Obligations, Current		(54,000,000)	(53,000,000)
Long-term Debt Due After One Year		$ 7,882,000,000	7,976,000,000
Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt	$ 1,400,000,000		$ 0
Debt stated rate			0.00%
Debt instrument, maturity date		Jan. 6, 2019
Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Debt		$ 0	$ 0
Debt stated rate		0.00%	0.00%
Debt instrument, maturity date		Aug. 27, 2020	Aug. 27, 2020
Revolving Credit Facility Maximum Borrowing Capacity		$ 4,000,000,000
Credit facility fee rate basis points, minimum				0.10%
Credit facility fee rate basis points, maximum				0.25%
Credit facility aggregate short-term loans and letters of credit, maximum				$ 500,000,000
Credit facility aggregate short-term loans and letters of credit, committed		450,000,000
Credit facility interest rate, Eurodollar rate plus, minimum				0.90%
Credit facility interest rate, Eurodollar rate plus, maximum				1.50%
Capital Lease and Other Obligations
Debt Instrument [Line Items]
Debt		$ 390,000,000	$ 403,000,000
Debt stated rate		0.00%	0.00%
Capital Lease Obligations, Current		$ (54,000,000)	$ (53,000,000)
8.25% Senior Notes, due March 1, 2019
Debt Instrument [Line Items]
Debt		$ 1,000,000,000	$ 1,000,000,000
Debt stated rate		8.25%	8.25%
Debt instrument, maturity date		Mar. 1, 2019	Mar. 1, 2019
5.625% Senior Notes, due May 1, 2021
Debt Instrument [Line Items]
Debt		$ 379,000,000	$ 693,000,000
Debt stated rate		5.625%	5.625%
Debt instrument, maturity date		May 1, 2021	May 1, 2021
4.15% Senior Notes, due December 15, 2021
Debt Instrument [Line Items]
Debt		$ 1,000,000,000	$ 1,000,000,000
Debt stated rate		4.15%	4.15%
Debt instrument, maturity date		Dec. 15, 2021	Dec. 15, 2021
5.875% Senior Notes, due June 1, 2022
Debt Instrument [Line Items]
Debt		$ 18,000,000	$ 597,000,000
Debt stated rate		5.875%	5.875%
Debt instrument, maturity date		Jun. 1, 2022	Jun. 1, 2022
7.25% Senior Notes, due October 15, 2023
Debt Instrument [Line Items]
Debt		$ 100,000,000	$ 100,000,000
Debt stated rate		7.25%	7.25%
Debt instrument, maturity date		Oct. 15, 2023	Oct. 15, 2023
Unamortized Debt Issuance Expense		$ (38,000,000)	$ (36,000,000)
5.875% Senior Notes, due June 1, 2024
Debt Instrument [Line Items]
Debt		$ 8,000,000	$ 499,000,000
Debt stated rate		5.875%	5.875%
Debt instrument, maturity date		Jun. 1, 2024	Jun. 1, 2024
3.90% Senior Notes, due November 15, 2024
Debt Instrument [Line Items]
Debt		$ 650,000,000	$ 650,000,000
Debt stated rate		3.90%	3.90%
Debt instrument, maturity date		Nov. 15, 2024	Nov. 15, 2024
8.00% Senior Notes, due April 1, 2027
Debt Instrument [Line Items]
Debt		$ 250,000,000	$ 250,000,000
Debt stated rate		8.00%	8.00%
Debt instrument, maturity date		Apr. 1, 2027	Apr. 1, 2027
6.00% Senior Notes, due March 1, 2041
Debt Instrument [Line Items]
Debt		$ 850,000,000	$ 850,000,000
Debt stated rate		6.00%	6.00%
Debt instrument, maturity date		Mar. 1, 2041	Mar. 1, 2041
5.25% Senior Notes, due November 15, 2043
Debt Instrument [Line Items]
Debt		$ 1,000,000,000	$ 1,000,000,000
Debt stated rate		5.25%	5.25%
Debt instrument, maturity date		Nov. 15, 2043	Nov. 15, 2043
5.05% Senior Notes, due November 15, 2044
Debt Instrument [Line Items]
Debt		$ 850,000,000	$ 850,000,000
Debt stated rate		5.05%	5.05%
Debt instrument, maturity date		Nov. 15, 2044	Nov. 15, 2044
7.25% Senior Debentures, due August 1, 2097
Debt Instrument [Line Items]
Debt		$ 84,000,000	$ 84,000,000
Debt stated rate		7.25%	7.25%
Debt instrument, maturity date		Aug. 1, 2097	Aug. 1, 2097
Revolving Credit Facility, due August 27, 2020 | Credit Facility [Member]
Debt Instrument [Line Items]
Proceeds from Lines of Credit		$ 1,380,000,000
Debt stated rate		1.69%
Credit facility fee rate basis points, minimum	0.10%
Credit facility fee rate basis points, maximum	0.75%
Debt Instrument, Term	3 years
Revolving Credit Facility, due August 27, 2020 | Federal Funds Effective Swap Rate [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate	0.50%
Revolving Credit Facility, due August 27, 2020 | London Interbank Offered Rate (LIBOR) [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility interest rate, Eurodollar rate plus, minimum	1.00%
Credit facility interest rate, Eurodollar rate plus, maximum	1.75%
Debt instrument, variable rate	1.00%
Other Operating Income (Expense) [Member] | Revolving Credit Facility, due August 27, 2020 | Credit Facility [Member]
Debt Instrument [Line Items]
Gain on tendered offers		$ 80,000,000

Fair Value Measurements and D40

Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Financial Assets [Abstract]
Mutual Fund Investments		$ 77	$ 90
Commodity Derivative Instruments		460	592
Financial Liabilities [Abstract]
Commodity Derivative Instruments		(3)	0
Portion of Deferred Compensation Liability Measured at Fair Value		(96)	(98)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability		(1)
Quoted Prices in Active Markets (Level 1)
Financial Assets [Abstract]
Mutual Fund Investments	[1]	77	90
Commodity Derivative Instruments	[1]	0	0
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[1]	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	[1]	(96)	(98)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[1]	(1)
Significant Unobservable Inputs (Level 3)
Financial Assets [Abstract]
Mutual Fund Investments	[2]	0	0
Commodity Derivative Instruments	[2]	0	0
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[2]	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	[2]	0	0
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[2]	0
Significant Other Observable Inputs (Level 2)
Financial Assets [Abstract]
Mutual Fund Investments	[3]	0	0
Commodity Derivative Instruments	[3]	472	600
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[3]	(15)	(8)
Portion of Deferred Compensation Liability Measured at Fair Value	[3]	0	0
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[3]	0
Scenario, Adjustment [Member]
Financial Assets [Abstract]
Mutual Fund Investments	[4]	0	0
Commodity Derivative Instruments	[4]	(12)	(8)
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[4]	12	8
Portion of Deferred Compensation Liability Measured at Fair Value	[4]	0	$ 0
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[4]	$ 0
[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 3 measurements are fair value measurements which use unobservable inputs.
[3]	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.
[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.

Fair Value Measurements and D41

Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Nonrecurring Basis (Details 2) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties	[1]	$ 0	$ 27
Oil and Gas Property, Full Cost Method, Net	[2]	0	27
Quoted Prices in Active Markets (Level 1)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties		0	0
Significant Other Observable Inputs (Level 2)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties		0	0
Significant Unobservable Inputs (Level 3)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties		$ 0	$ 0
[1]	Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean).
[2]	Amount represents net book value at the date of assessment.

Fair Value Measurements and D42

Fair Value Measurements and Disclosures (Details 3) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	[1]	$ 7,546	$ 7,626
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	[1]	$ 7,334	$ 7,105
[1]	Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well 43

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Details) $ in Millions		3 Months Ended
		Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost		$ 2,300
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized Exploratory Well Costs, Beginning of Period		1,353
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		22
Capitalized Exploratory Well Cost, Other	[1]	(143)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves		(2)
Capitalized Exploratory Well Cost, Charged to Expense	[2]	(56)
Capitalized Exploratory Well Costs, End of Period		1,174	$ 1,353
Exploratory Well Costs Capitalized for a Period of One Year or Less				$ 63	$ 95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				1,111	1,258
Capitalized Exploratory Well Costs, End of Period		$ 1,353	$ 1,353	$ 1,174	$ 1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling				14	14
Percentage of divestiture farmed out		35.00%	35.00%
Onshore US [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost		$ 2,000
International [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost		57
Deepwater Gulf of Mexico [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost		255
Katmai Deepwater Gulf Of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				$ 93
Troubadour Deepwater Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				49
Diega (including Carmen) Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				235
Carla Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				180
Felicita/Yolanda Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				66
YoYo Offshore Cameron [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				52
Leviathan Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				194
Leviathan-1 Deep Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				82
Dalit Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				28
Dolphin 1 Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				26
Cyprus [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				84
Other - Projects of $20 million or less each [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				$ 22
Falkland Island
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized Exploratory Well Cost, Charged to Expense		$ (42)
[1]	Represents our farm-out of a 35% interest in Block 12 offshore Cyprus to a new partner.
[2]	Includes $42 million relating to the termination

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance		$ 989	$ 751
Liabilities Incurred		2	10
Liabilities Settled		(8)	(8)
Revision of Estimate		5	24
Accretion Expense	[1]	(12)	(10)
Asset Retirement Obligations, Ending Balance		1,000	787
Onshore US [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities Incurred			4
Deepwater Gulf of Mexico [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities Incurred			$ 6
Equatorial Guinea
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate		$ 5
[1]	Accretion expense is included in DD&A expense in the consolidated statements of operations.

Loss Per Share (Details)

Loss Per Share (Details) - USD ($) $ / shares in Units, $ in Millions		Jul. 20, 2015	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net Loss			$ (287)	$ (22)
Weighted Average, Number of Shares Outstanding, Basic (in shares)	[1]		429,000,000	370,000,000
Weighted Average, Number of Shares Outstanding, Diluted (in shares)			429,000,000	370,000,000
Earnings (Loss) from Continuing Operations Per Share, Basic (in dollars per share)			$ (0.67)	$ (0.06)
Earnings (Loss) from Continuing Operations Per Share, Diluted (in dollars per share)			$ (0.67)	$ (0.06)
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above (in shares)			15,000,000	9,000,000
Underwritten public offering (in shares)			24,150,000
Shares exchange in acquisition		41,000,000
[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 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Tax Examination [Line Items]
Current	$ 20	$ 10
Deferred	(186)	(30)
Total Income Tax Benefit	$ (166)	$ (20)
Effective Tax Rate	36.60%	47.60%
US
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2,012
Equatorial Guinea
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2,010
Israel
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2,011

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016		Mar. 31, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues from Third Parties		$ 705		$ 749
Income from Equity Method Investees		19		18
Total Revenues		724	[1]	767
DD&A		617		454
Asset Impairments	[2]	0		27
Gain on Commodity Derivative Instruments		(44)		(150)
Income (Loss) Before Income Taxes		(453)		(42)
Total Assets		23,413			$ 24,196
United States [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties		489		487
Income from Equity Method Investees		16		11
Total Revenues		505		498
DD&A		530		357
Asset Impairments				3
Gain on Commodity Derivative Instruments		(37)		(105)
Income (Loss) Before Income Taxes		(292)		(1)
Total Assets		18,387			18,831
West Africa [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties		90		138
Income from Equity Method Investees		3		7
Total Revenues		93		145
DD&A		55		77
Asset Impairments				0
Gain on Commodity Derivative Instruments		(7)		(45)
Income (Loss) Before Income Taxes		9		74
Total Assets		2,233			2,299
Eastern Mediterranean [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties		126		120
Income from Equity Method Investees		0		0
Total Revenues		126		120
DD&A		20		15
Asset Impairments				24
Gain on Commodity Derivative Instruments		0		0
Income (Loss) Before Income Taxes		84		51
Total Assets		2,459			2,677
Other Int'l & Corporate [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties		0		4
Income from Equity Method Investees		0		0
Total Revenues		0		4
DD&A		12		5
Asset Impairments				0
Gain on Commodity Derivative Instruments		0		0
Income (Loss) Before Income Taxes		(254)		$ (166)
Total Assets		$ 334			$ 389
[1]	No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.
[2]	Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean).

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details)	1 Months Ended	3 Months Ended
	Dec. 31, 2015USD ($)	Mar. 31, 2016USD ($)$ / MMBTU
Other Commitments [Line Items]
Additional expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments		$ 16,000,000
CONSOL Carried Cost Obligation [Member]
Other Commitments [Line Items]
Equity method investment, ownership percentage		50.00%
Maximum amount to be paid each calendar year for funding of future drilling and completion costs		$ 400,000,000
Funding of joint venture's future drilling and completion costs		$ 1,600,000,000
Natural gas price agreed upon benchmark, average		4
Consent Decree [Member]
Other Commitments [Line Items]
Civil penalty		$ 4,950,000
Mitigation projects		4,500,000
Supplemental environmental projects		$ 4,000,000
Pending Litigation [Member] | Unfavorable Regulatory Action [Member]
Other Commitments [Line Items]
Reduced penalty	$ 223,475
Maximum reduction to penalty	80.00%