Noble Energy (NBL) 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	9 Months Ended
	Sep. 30, 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	429,701,812
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016		Sep. 30, 2015
Income Statement [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		$ (143)	$ (283)	$ (745)		$ (413)
Revenues
Oil, Gas and NGL Sales		882	783	2,411		2,264
Income from Equity Method Investees		28	36	70		60
Total		910	819	2,481		2,324
Costs and Expenses
Production Expense		274	247	820		715
Exploration Expense		125	203	376		308
Depreciation, Depletion and Amortization		621	539	1,859		1,444
General and Administrative		95	109	293		308
Other Operating Expense, Net		45	188	66		310
Total		1,160	1,286	3,414		3,085
Operating Loss		(250)	(467)	(933)		(761)
Other Expense (Income)
(Gain) Loss on Commodity Derivative Instruments		(55)	(267)	53		(331)
Interest, Net of Amount Capitalized		86	71	242		183
Other Non-Operating (Income) Expense, Net		(1)	(12)	3		(20)
Total		30	(208)	298		(168)
Loss Before Income Taxes		(280)	(259)	(1,231)		(593)
Income Tax (Benefit) Provision		(137)	24	(486)		(180)
Net Income (Loss) Attributable to Noncontrolling Interest		1	0	1		0
Net Loss Including Noncontrolling Interests		$ (144)	$ (283)	$ (746)		$ (413)
Loss per share, basic (in dollars per share)		$ (0.33)	$ (0.67)	$ (1.73)	[1]	$ (1.05)
Loss per share, diluted (in dollars per share)		$ (0.33)	$ (0.67)	$ (1.73)	[1]	$ (1.05)
Weighted Average Number of Shares Outstanding
Basic (in shares)	[2]	430	420	430		392
Diluted (in shares)	[3]	430	420	430		392
[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.
[3]	For all periods, 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.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Loss - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (143)	$ (283)	$ (745)	$ (413)
Net Loss Including Noncontrolling Interests	(144)	(283)	(746)	(413)
Other Items of Comprehensive Loss
Net Change in Mutual Fund Investment	0	0	0	(11)
Less Tax Expense	0	0	0	3
Net Change in Pension and Other	1	69	2	94
Less Tax Benefit	(1)	(23)	(1)	(33)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	0	46	1	53
Comprehensive Loss Including Noncontrolling Interests	(143)	(237)	(744)	(360)
Comprehensive Loss Including Noncontrolling Interests	(144)	(237)	(745)	(360)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 1	$ 0	$ 1	$ 0

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents	$ 1,819	$ 1,028
Accounts Receivable, Net	486	450
Commodity Derivative Assets	120	582
Other Current Assets	352	216
Total Current Assets	2,777	2,276
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	30,372	31,220
Property, Plant and Equipment, Other	919	858
Total Property, Plant and Equipment, Gross	31,291	32,078
Accumulated Depreciation, Depletion and Amortization	(12,186)	(10,778)
Total Property, Plant and Equipment, Net	19,105	21,300
Other Noncurrent Assets	587	620
Total Assets	22,469	24,196
Current Liabilities
Accounts Payable - Trade	786	1,128
Other Current Liabilities	742	677
Total Current Liabilities	1,528	1,805
Long-Term Debt	7,854	7,976
Deferred Income Taxes	2,103	2,826
Other Noncurrent Liabilities	1,139	1,219
Total Liabilities	12,624	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	6,417	6,360
Accumulated Other Comprehensive Loss	(32)	(33)
Treasury Stock, at Cost; 38 Million Shares	(696)	(688)
Retained Earnings	3,851	4,726
Noble Energy Share of Equity	9,545	10,370
Stockholders' Equity Attributable to Noncontrolling Interest	300	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	9,845	10,370
Total Liabilities and Equity	$ 22,469	$ 24,196

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 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
Preferred stock, shares issued (in shares)	0	0
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 - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Repayments of Long-term Lines of Credit		$ 0	$ 74
Cash Flows From Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		(745)	(413)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		1,859	1,444
Asset Impairments		0	43
Results of Operations, Dry Hole Costs		105	154
Impairment of Leasehold		81	0
Gain on Extinguishment of Debt	[1]	(80)	0
Finalization of Purchase Price Allocation for Rosetta Merger		(25)	0	[2]
Loss on Asset Due to Terminated Contract	[3]	44	0
Deferred Income Tax Benefit		(699)	(244)
Loss (Gain) on Commodity Derivative Instruments		53	(331)
Net Cash Received in Settlement of Commodity Derivative Instruments		454	683
Stock Based Compensation		61	69
Non-cash Pension Termination Expense		0	81
Other Adjustments for Noncash Items Included in Income		92	74
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable		6	370
Decrease in Accounts Payable		(124)	(248)
Increase (Decrease) in Current Income Taxes Payable		82	(118)
Other Current Assets and Liabilities, Net		(72)	(28)
Other Operating Assets and Liabilities, Net		(63)	(50)
Net Cash Provided by Operating Activities		1,054	1,486
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(1,164)	(2,519)
Cash Acquired in Rosetta Merger		0	61
Additions to Equity Method Investments		(8)	(86)
Proceeds from Divestitures and Other		786	151
Net Cash Used in Investing Activities		(386)	(2,393)
Cash Flows From Financing Activities
Dividends Paid, Common Stock		(129)	(214)
Proceeds from Term Loan Facility		1,400	0
Repayment of Senior Notes		(1,383)
Repayment of Capital Lease Obligation		(39)	(49)
Other		(25)	(11)
Net Cash Provided by Financing Activities		123	752
Increase (Decrease) in Cash and Cash Equivalents		791	(155)
Cash and Cash Equivalents at Beginning of Period		1,028	1,183
Cash and Cash Equivalents at End of Period		1,819	1,028
Noble Energy, Inc. [Member]
Cash Flows From Financing Activities
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs		0	1,112
Noble Midstream Partners LP [Member]
Cash Flows From Financing Activities
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs			$ 0
Noble Midstream | Noble Midstream Partners LP [Member]
Cash Flows From Financing Activities
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs		$ 299
[1]	Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.
[2]	Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.
[3]	Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid in Capital	Accumulated Other Comprehensive Loss	Treasury Stock at Cost	Retained Earnings	Noncontrolling Interest [Member]
Balance at Beginning of Period at Dec. 31, 2014	$ 10,325	$ 4	$ 3,624	$ (90)	$ (671)	$ 7,458	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(413)	0	0	0	0	(413)	0
Rosetta Merger	(1,529)	(1)	(1,528)	0	0	0	0
Stock-based Compensation	69	0	69	0	0	0	0
Dividends	(214)	0	0	0	0	(214)	0
Issuance of Noble Energy Common Stock, Net of Offering Costs	1,112	0	1,112	0	0	0	0
Other	42	0	9	53	(20)	0	0
Balance at End of Period at Sep. 30, 2015	12,450	5	6,342	(37)	(691)	6,831
Balance at Beginning of Period at Dec. 31, 2015	10,370	5	6,360	(33)	(688)	4,726	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(745)	0	0	0	0	(746)	1
Stock-based Compensation	57	0		0	0	0	0
Dividends	(129)	0	0	0	0	(129)	0
Issuance of Noble Energy Common Stock, Net of Offering Costs	299	0	0	0	0	0	299
Other	(7)	0	0	1	(8)	0	0
Balance at End of Period at Sep. 30, 2016	$ 9,845	$ 5	$ 6,417	$ (32)	$ (696)	$ 3,851	$ 300

Consolidated Statements of Sha8

Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.30	$ 0.54

Organization and Nature of Oper

Organization and Nature of Operations	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [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), and offshore in deepwater Gulf of Mexico, Eastern Mediterranean and West Africa.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [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 September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 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 and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 . In third quarter 2016, Noble Midstream Partners LP (Noble Midstream), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we will be presenting our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream. Noble Midstream and the initial public offering of common units are further discussed in Note 3. Noble Midstream Partners LP . 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, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream, which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. 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. Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream's economic performance; therefore, Noble Midstream is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream. 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 (so called phantom units, the 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. 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 up to four times the fair market value of a share of common stock of the Company, which was $31.65 , as of the grant date. 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 September 30, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 8. Fair Value Measurements and Disclosures . Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (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. We are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In March 2016, the 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 June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses , which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources . 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 or net realizable value. We follow the average cost method and do not believe adoption of ASU 2015-11 will have a material impact on our financial position and results of operations. In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . 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. We believe the impact of utilizing the sales method of accounting for our current domestic natural gas sales agreements will be de minimis. 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 do not believe adoption of this guidance will have a material impact on our consolidated financial statements and related disclosures as all material investments are accounted for under the equity method of accounting. In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments , to clarify how certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. 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. During third quarter 2016, Noble Midstream closed on its initial public offering of common units. In accordance with ASU 2015-02, Noble Midstream is considered a VIE as Noble Energy is considered the primary beneficiary. We have adopted the provisions of ASU 2015-02, which did not have a material effect on our financial statements or related disclosures. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Production Expense Lease Operating Expense $ 131 $ 133 $ 412 $ 419 Production and Ad Valorem Taxes 30 28 73 89 Transportation and Gathering Expense (1) 113 86 335 207 Total $ 274 $ 247 $ 820 $ 715 Other Operating (Income) Expense, Net (Gain) Loss on Asset Due to Terminated Contract (2) $ (3 ) $ — $ 44 $ — Marketing and Processing Expense, Net (3) 20 10 58 25 Loss on Divestitures — — 23 — Corporate Restructuring Expense — 21 — 39 Purchase Price Allocation Adjustment (4) — — (25 ) — Gain on Extinguishment of Debt (5) — — (80 ) — Asset Impairments — — — 43 Inventory Adjustment (6) 14 — 14 — Building Exit Cost 4 18 8 18 Rosetta Merger Expenses — 71 — 73 Pension Plan Expense — 67 — 88 Stacked Drilling Rig Expense 3 13 8 20 Other, Net 7 (12 ) 16 4 Total $ 45 $ 188 $ 66 $ 310 Other Non-Operating Expense (Income), Net Deferred Compensation Expense (Income) (7) $ 2 $ (13 ) $ 7 $ (19 ) Other (Income) Expense, Net (3 ) 1 (4 ) (1 ) Total $ (1 ) $ (12 ) $ 3 $ (20 ) (1) 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. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation. (2) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update . (3) For the three and nine months ended September 30, 2016 , amount includes $12 million and $39 million , respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015 , were previously presented within production expense. These amounts have been reclassified to conform to the current presentation. (4) Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger . (5) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt . (6) Amount relates to an adjustment of inventory to its net realizable value. (7) Amounts represent decreases (increases) 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) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 317 $ 298 Joint Interest Billings 66 20 Proceeds Receivable (1) 40 — Other 86 151 Allowance for Doubtful Accounts (23 ) (19 ) Total $ 486 $ 450 Other Current Assets Inventories, Materials and Supplies $ 75 $ 92 Inventories, Crude Oil 25 23 Assets Held for Sale (2) 214 67 Prepaid Expenses and Other Current Assets 38 34 Total $ 352 $ 216 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 460 $ 453 Mutual Fund Investments 83 90 Commodity Derivative Assets — 10 Other Assets 44 67 Total $ 587 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 121 $ 166 Commodity Derivative Liabilities 27 — Income Taxes Payable 168 86 Asset Retirement Obligations 128 128 Interest Payable 93 83 Current Portion of Capital Lease Obligations 61 53 Other 144 161 Total $ 742 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 232 $ 217 Asset Retirement Obligations 820 861 Production and Ad Valorem Taxes 35 68 Commodity Derivative Liabilities 8 — Other 44 73 Total $ 1,139 $ 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) Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures . Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream's current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas. Initial Public Offering of Noble Midstream Partners LP On September 15, 2016 , Noble Midstream common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016 , Noble Midstream completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ( $21.21 per common unit, net of underwriting discounts). In exchange for the contributed assets, Noble Energy received: • 1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream; • 15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream; • incentive distribution rights in Noble Midstream; and • the right to receive a cash distribution from Noble Midstream. In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream, which is not entitled to receive cash distributions. Noble Midstream generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million . In third quarter 2016, Noble Midstream made a distribution of $297 million to Noble Energy.

Noble Midstream Partners LP

Noble Midstream Partners LP	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Noble Midstream Partners LP	Basis of Presentation Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 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 and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 . In third quarter 2016, Noble Midstream Partners LP (Noble Midstream), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we will be presenting our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream. Noble Midstream and the initial public offering of common units are further discussed in Note 3. Noble Midstream Partners LP . 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, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream, which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. 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. Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream's economic performance; therefore, Noble Midstream is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream. 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 (so called phantom units, the 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. 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 up to four times the fair market value of a share of common stock of the Company, which was $31.65 , as of the grant date. 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 September 30, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 8. Fair Value Measurements and Disclosures . Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (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. We are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In March 2016, the 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 June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses , which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources . 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 or net realizable value. We follow the average cost method and do not believe adoption of ASU 2015-11 will have a material impact on our financial position and results of operations. In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . 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. We believe the impact of utilizing the sales method of accounting for our current domestic natural gas sales agreements will be de minimis. 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 do not believe adoption of this guidance will have a material impact on our consolidated financial statements and related disclosures as all material investments are accounted for under the equity method of accounting. In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments , to clarify how certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. 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. During third quarter 2016, Noble Midstream closed on its initial public offering of common units. In accordance with ASU 2015-02, Noble Midstream is considered a VIE as Noble Energy is considered the primary beneficiary. We have adopted the provisions of ASU 2015-02, which did not have a material effect on our financial statements or related disclosures. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Production Expense Lease Operating Expense $ 131 $ 133 $ 412 $ 419 Production and Ad Valorem Taxes 30 28 73 89 Transportation and Gathering Expense (1) 113 86 335 207 Total $ 274 $ 247 $ 820 $ 715 Other Operating (Income) Expense, Net (Gain) Loss on Asset Due to Terminated Contract (2) $ (3 ) $ — $ 44 $ — Marketing and Processing Expense, Net (3) 20 10 58 25 Loss on Divestitures — — 23 — Corporate Restructuring Expense — 21 — 39 Purchase Price Allocation Adjustment (4) — — (25 ) — Gain on Extinguishment of Debt (5) — — (80 ) — Asset Impairments — — — 43 Inventory Adjustment (6) 14 — 14 — Building Exit Cost 4 18 8 18 Rosetta Merger Expenses — 71 — 73 Pension Plan Expense — 67 — 88 Stacked Drilling Rig Expense 3 13 8 20 Other, Net 7 (12 ) 16 4 Total $ 45 $ 188 $ 66 $ 310 Other Non-Operating Expense (Income), Net Deferred Compensation Expense (Income) (7) $ 2 $ (13 ) $ 7 $ (19 ) Other (Income) Expense, Net (3 ) 1 (4 ) (1 ) Total $ (1 ) $ (12 ) $ 3 $ (20 ) (1) 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. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation. (2) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update . (3) For the three and nine months ended September 30, 2016 , amount includes $12 million and $39 million , respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015 , were previously presented within production expense. These amounts have been reclassified to conform to the current presentation. (4) Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger . (5) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt . (6) Amount relates to an adjustment of inventory to its net realizable value. (7) Amounts represent decreases (increases) 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) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 317 $ 298 Joint Interest Billings 66 20 Proceeds Receivable (1) 40 — Other 86 151 Allowance for Doubtful Accounts (23 ) (19 ) Total $ 486 $ 450 Other Current Assets Inventories, Materials and Supplies $ 75 $ 92 Inventories, Crude Oil 25 23 Assets Held for Sale (2) 214 67 Prepaid Expenses and Other Current Assets 38 34 Total $ 352 $ 216 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 460 $ 453 Mutual Fund Investments 83 90 Commodity Derivative Assets — 10 Other Assets 44 67 Total $ 587 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 121 $ 166 Commodity Derivative Liabilities 27 — Income Taxes Payable 168 86 Asset Retirement Obligations 128 128 Interest Payable 93 83 Current Portion of Capital Lease Obligations 61 53 Other 144 161 Total $ 742 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 232 $ 217 Asset Retirement Obligations 820 861 Production and Ad Valorem Taxes 35 68 Commodity Derivative Liabilities 8 — Other 44 73 Total $ 1,139 $ 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) Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures . Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream's current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas. Initial Public Offering of Noble Midstream Partners LP On September 15, 2016 , Noble Midstream common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016 , Noble Midstream completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ( $21.21 per common unit, net of underwriting discounts). In exchange for the contributed assets, Noble Energy received: • 1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream; • 15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream; • incentive distribution rights in Noble Midstream; and • the right to receive a cash distribution from Noble Midstream. In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream, which is not entitled to receive cash distributions. Noble Midstream generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million . In third quarter 2016, Noble Midstream made a distribution of $297 million to Noble Energy.

Rosetta Merger Rosetta Merger

Rosetta Merger Rosetta Merger	9 Months Ended
	Sep. 30, 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 final 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. The following table sets forth our final purchase price allocation: (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 Debt 1,992 Other Long Term Liabilities 23 Asset Retirement Obligation 27 Total purchase price plus liabilities assumed $ 3,708 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 Long Term Deferred Tax Asset 17 Goodwill (1) 138 Total Asset Value $ 3,708 (1) As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date. 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 were the most sensitive and 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 $119 million and $333 million and pre-tax net loss of $4 million and $17 million were generated from Rosetta assets during the three and nine months ended September 30, 2016 , respectively. 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 Nine Months Ended (in millions, except per share amounts) 2016 (1) 2015 2016 (1) 2015 Revenues $ 910 $ 846 $ 2,481 $ 2,619 Net Loss Attributable to Noble Energy $ (144 ) $ (202 ) $ (746 ) $ (338 ) Net Loss Attributable to Noble Energy Per Share of Common Stock Basic $ (0.33 ) $ (0.44 ) $ (1.73 ) $ (0.79 ) Diluted $ (0.33 ) $ (0.44 ) $ (1.73 ) $ (0.79 ) (1) No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Divestitures

Divestitures	9 Months Ended
	Sep. 30, 2016
Divestitures [Abstract]
Divestitures	Divestitures Onshore US Properties During the first nine months of 2016, we entered into certain onshore transactions for which we: • entered into a purchase and sale agreement for the divestiture of certain producing and non-producing crude oil and natural gas interests covering approximately 33,100 net acres in the DJ Basin for $505 million , subject to customary closing adjustments. We have received proceeds of $486 million and expect to receive the remaining proceeds, subject to post-close adjustments, in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss; • closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of $43 million , and recognized a $23 million loss on sale of assets; • closed a cashless acreage exchange within the DJ Basin to receive approximately 11,700 net acres within our Wells Ranch development area of the field in exchange for approximately 13,500 net acres primarily from our Bronco area of the field. No gain or loss was recognized for the transaction; and • sold certain other non-producing interests within the DJ Basin, generating net proceeds of $20 million , and other certain smaller onshore US property packages, resulting in net proceeds of $19 million , during the first nine months of 2016 . Proceeds received were applied to the respective field's basis with no recognition of gain or loss. Subsequent to third quarter 2016, we closed the divestiture of certain Eagle Ford assets that were classified as assets held for sale of $68 million as of September 30, 2016 . Total proceeds received will be applied to the field's basis with no recognition of gain or loss. During the first nine months of 2015, we sold certain onshore US crude oil and natural gas interests in the DJ Basin, generating net proceeds of $151 million . Proceeds were applied to the field's basis with no recognition of gain or loss. 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. Offshore Israel Assets On July 4, 2016, we signed a definitive agreement to divest a 3% working interest in the Tamar field, offshore Israel, for $369 million , subject to customary closing adjustments. Under the terms of the agreement, the purchaser has the option to elect, before closing, to purchase an additional 1% working interest at the same valuation. The divestiture has an effective date of January 1, 2016 and is expected to close in fourth quarter 2016. 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.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 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, natural gas and natural gas liquids pricing. 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 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Unsettled Commodity Derivative Instruments As of September 30, 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 2016 Call Option (1) NYMEX WTI 5,000 $ — $ — $ — $ 54.16 2016 Swaps NYMEX WTI 16,000 67.69 — — — 2016 Swaps (2) (3) 6,000 90.28 — — — 2016 Two-Way Collars NYMEX WTI 10,000 — — 40.50 53.42 2016 Three-Way Collars NYMEX WTI 8,000 — 54.50 65.63 79.03 2016 Swaps Dated Brent 9,000 97.96 — — — 2016 Three-Way Collars Dated Brent 8,000 — 72.50 86.25 101.79 1H17 (4) Swaps NYMEX WTI 6,000 55.08 — — — 1H17 (4) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (4) Swaps Dated Brent 3,000 62.80 — — — 2H17 (4) Call Option (1) NYMEX WTI 3,000 — — — 60.12 2H17 (4) Swaptions (5) Dated Brent 3,000 — — — 62.80 2H17 (4) Swaptions (5) NYMEX WTI 3,000 — — — 50.05 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.29 2017 Call Option (1) NYMEX WTI 3,000 — — — 57.00 2017 Swaptions (5) NYMEX WTI 4,000 — — — 47.34 2017 Three-Way Collars NYMEX WTI 15,000 — 36.33 46.33 60.68 2017 Three-Way Collars Dated Brent 2,000 — 35.00 45.00 66.33 2018 Three-Way Collars Dated Brent 3,000 — 40.00 50.00 70.41 (1) 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. (2) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (3) The indices for these derivative instruments are NYMEX WTI and Argus LLS. (4) We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year. (5) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. As of September 30, 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 2016 Swaps NYMEX HH 70,000 3.24 — — — 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 1H17 Swaps NYMEX HH 30,000 2.92 — — — 2H17 Swaptions (3) NYMEX HH 30,000 — — — 2.92 2017 Swaps NYMEX HH 30,000 3.15 — — — 2017 Swaptions (3) NYMEX HH 60,000 — — — 3.14 2017 Three-Way Collars NYMEX HH 180,000 — 2.50 2.93 3.58 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 70,000 — 2.50 2.80 3.76 (1) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (2) The index for these derivative instruments is Houston Ship Channel. (3) We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. Fair Value Amounts and Loss (Gain) 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 September 30, December 31, September 30, 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 $ 120 Current Assets $ 582 Current Liabilities $ 27 Current Liabilities $ — Noncurrent Assets — Noncurrent Assets 10 Noncurrent Liabilities 8 Noncurrent Liabilities — Total $ 120 $ 592 $ 35 $ — The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Cash Received in Settlement of Commodity Derivative Instruments Crude Oil $ (119 ) $ (235 ) $ (395 ) $ (578 ) Natural Gas (13 ) (42 ) (59 ) (98 ) NGLs — (7 ) — (7 ) Total Cash Received in Settlement of Commodity Derivative Instruments (132 ) (284 ) (454 ) (683 ) Non-cash Portion of Loss on Commodity Derivative Instruments Crude Oil 80 4 441 301 Natural Gas (3 ) 3 66 41 NGLs — 10 — 10 Total Non-cash Portion of Loss on Commodity Derivative Instruments 77 17 507 352 (Gain) Loss on Commodity Derivative Instruments Crude Oil (39 ) (231 ) 46 (277 ) Natural Gas (16 ) (39 ) 7 (57 ) NGLs — 3 — 3 Total Loss (Gain) on Commodity Derivative Instruments $ (55 ) $ (267 ) $ 53 $ (331 )

Debt

Debt	9 Months Ended
	Sep. 30, 2016
Debt [Abstract]
Debt	Debt Debt consists of the following: September 30, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — % $ — — % Noble Midstream Revolving Credit Facility, due September 20, 2021 — — % — — — % Capital Lease and Other Obligations 368 — % 403 — % Term Loan Facility, due January 6, 2019 1,400 1.70 % — — % 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 5.625 % 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 5.875 % 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 5.875 % 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 7,957 7,976 Unamortized Discount (23 ) (24 ) Unamortized Premium 17 113 Unamortized Debt Issuance Costs (36 ) (36 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,915 8,029 Less Amounts Due Within One Year Capital Lease Obligations (61 ) (53 ) Long-Term Debt Due After One Year $ 7,854 $ 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 this capacity is committed as of September 30, 2016 ). Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services, a subsidiary of Noble Midstream, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Revolving Credit Facility). The Noble Midstream Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Revolving Credit Facility may be increased by an additional $350 million subject to certain conditions and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream. Borrowings by Noble Midstream under the Noble Midstream Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream's option, either: • in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00% ; or • in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. The Noble Midstream Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated EBITDA and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Revolving Credit Facility, are guaranteed by Noble Midstream and all wholly-owned material subsidiaries of Noble Midstream. 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 1.70% as of September 30, 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. Subsequent Event On November 1, 2016, we prepaid $850 million of borrowings under our Term Loan Facility from cash on hand. See Note 8. 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	9 Months Ended
	Sep. 30, 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 6. 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) September 30, 2016 Financial Assets Mutual Fund Investments $ 83 $ — $ — $ — $ 83 Commodity Derivative Instruments — 133 — (13 ) 120 Financial Liabilities Commodity Derivative Instruments — (48 ) — 13 (35 ) Portion of Deferred Compensation Liability Measured at Fair Value (105 ) — — — (105 ) Portion of Stock Based Compensation Liability Measured at Fair Value (6 ) — — — (6 ) 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: Inventory Adjustment Materials and supplies inventories are stated at the lower of cost or net realizable value. For the nine months ended September 30, 2016, we recorded a downward adjustment of $ 14 million to reduce inventory to its estimated net realizable value. Asset Impairments We periodically evaluate our oil and gas properties for impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. In line with accounting standards, we use an undiscounted cash flow model as an indicator of possible impairment. Where circumstances warrant, we use 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. For the nine months ended September 30, 2016, no impairment was indicated. Impairments for the nine months ended September 30, 2015 were due primarily to increases in asset carrying values associated with increases in estimated abandonment costs. Assets Held for Sale In cases where assets meet the criteria to be classified as assets held for sale and a loss is expected, the underlying assets are written down to fair value less costs to sell. For the nine months ended September 30, 2016, we recorded a downward adjustment of $23 million to reflect the loss on divestiture of our Bowdoin property in northern Montana. See Note 4. Divestitures . 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) Nine Months Ended September 30, 2016 Material and Supplies Inventory Adjustment $ — $ — $ 91 $ 105 $ 14 Loss on Divestitures — — 42 65 23 Impaired Oil and Gas Properties — — — — — Nine Months Ended September 30, 2015 Impaired Oil and Gas Properties — — — 43 43 (1) Amount represents net book value at the date of assessment. 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 7. Debt . Fair value information regarding our debt is as follows: September 30, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 7,547 $ 7,976 $ 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	9 Months Ended
	Sep. 30, 2016
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs 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) Nine Months Ended September 30, 2016 Capitalized Exploratory Well Costs, Beginning of Period $ 1,353 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 83 Divestitures and Other (1) (143 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1 ) Capitalized Exploratory Well Costs Charged to Expense (2) (83 ) Capitalized Exploratory Well Costs, End of Period $ 1,209 (1) Includes $143 million relating to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) Includes amounts related to contract termination offshore Falkland Islands, Dolphin 1 exploratory well offshore Israel, and Silvergate exploratory well deepwater Gulf of Mexico. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: (millions) September 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 91 $ 95 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 1,118 1,258 Balance at End of Period $ 1,209 $ 1,353 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 13 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 September 30, 2016 : (millions) Total by Project Progress Country/Project: Deepwater Gulf of Mexico Troubadour $ 52 Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. Katmai 97 Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options. Offshore Equatorial Guinea Blocks I and O Diega (Block I) and Carmen (Block O) 240 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 in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Carla (Block O) 184 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 in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Yolanda (Block I) 22 A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. Felicita (Block O) 45 Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Offshore Cameroon YoYo (YoYo Block) 53 A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. Offshore Israel Leviathan 196 Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands. Leviathan-1 Deep 84 The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 31 Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. Offshore Cyprus Cyprus 88 During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and 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 allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. Other Individual Projects Less than $20 million 26 Continuing to assess and evaluate wells. Total $ 1,118 Undeveloped Leasehold Costs Undeveloped leasehold costs as of September 30, 2016 totaled $2.0 billion , comprising $1.9 billion related to core onshore US unproved properties, $116 million related to Gulf of Mexico unproved properties, and $32 million related to international unproved properties. As part of our quarterly impairment review, we evaluate our exploration opportunities. If, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record either (1) impairment expense related to individually significant leases or (2) a decrease in the valuation of our pool of individually insignificant leases. During third quarter 2016, we completed our geological evaluation of certain deepwater Gulf of Mexico and offshore Falkland Islands leases and licenses and determined that several, representing $105 million of undeveloped leasehold cost, should be relinquished or exited. As a result, we recognized $81 million of leasehold impairment expense and recorded a $24 million decrease in our valuation pool of individually insignificant leases.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 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: Nine Months Ended (millions) 2016 2015 Asset Retirement Obligations, Beginning Balance $ 989 $ 751 Liabilities Incurred 5 54 Liabilities Settled (87 ) (29 ) Revision of Estimate 4 79 Accretion Expense (1) 37 32 Asset Retirement Obligations, Ending Balance $ 948 $ 887 (1) Accretion expense is included in Depreciation, Depletion and Amortization (DD&A) expense in the consolidated statements of operations. For the nine months ended September 30, 2016 Liabilities incurred were due to new wells and facilities placed into service for onshore US and deepwater Gulf of Mexico. Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful life and primarily included activities for Gulf of Mexico of $42 million and onshore US of $40 million . For the nine months ended September 30, 2015 Liabilities incurred were due to new wells and facilities for onshore US and deepwater Gulf of Mexico as well as liabilities assumed in the Rosetta Merger. Liabilities settled primarily related to non-core, onshore US properties sold. Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing of abandonment and included $43 million for Eastern Mediterranean and $28 million for DJ Basin.

Loss Per Share

Loss Per Share	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Loss Per Share	Loss Per Share Noble Energy's basic loss per share of common stock is computed by using net loss attributable to Noble Energy divided by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted loss per share: Three Months Ended Nine Months Ended (millions, except per share amounts) 2016 2015 2016 2015 Net Loss Attributable to Noble Energy $ (144 ) $ (283 ) $ (746 ) $ (413 ) Weighted Average Number of Shares Outstanding, Basic (1) 430 420 430 392 Weighted Average Number of Shares Outstanding, Diluted (2) 430 420 430 392 Loss Per Share, Basic $ (0.33 ) $ (0.67 ) $ (1.73 ) $ (1.05 ) Loss Per Share, Diluted (0.33 ) (0.67 ) (1.73 ) (1.05 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 14 15 11 (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 all periods, 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	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax benefit consists of the following: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Current $ 148 $ (45 ) $ 213 $ 64 Deferred (285 ) 69 (699 ) (244 ) Total Income Tax (Benefit) Provision $ (137 ) $ 24 $ (486 ) $ (180 ) Effective Tax Rate 48.9 % (9.3 )% 39.5 % 30.4 % 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 US and, accordingly, we now record additional deferred income taxes, net of estimated foreign tax credits. Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized effective tax rate (ETR) to current year earnings or loss before tax, which can result in significant interim ETR fluctuations. Our ETR for the three and nine months ended September 30, 2016 , varied as compared with the three and nine months ended September 30, 2015 , resulting in a higher income tax benefit and ETR primarily due to: • a higher loss before income taxes for the first nine months of 2016 as compared with the first nine months of 2015; • a period to period shift of the individual components of net income (loss) among tax jurisdictions with different rates, which is also impacted by the timing and magnitude of divestiture activities. See Note 4. Divestitures and Note 13. Segment Information ; and • the change in our permanent reinvestment assumption, noted above, which 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, which reduced the income tax benefit. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2013 , Equatorial Guinea – 2011 and Israel – 2011 .

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Information	Segment Information We have operations throughout the world and manage our operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States (which includes consolidated accounts of Noble Midstream); 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 September 30, 2016 Revenues from Third Parties $ 882 $ 639 $ 93 $ 150 $ — Income from Equity Method Investees 28 8 20 — — Total Revenues 910 647 113 150 — DD&A 621 539 46 23 13 Gain on Commodity Derivative Instruments (55 ) (48 ) (7 ) — — (Loss) Income Before Income Taxes (280 ) (407 ) 47 135 (55 ) Three Months Ended September 30, 2015 Revenues from Third Parties $ 783 $ 510 $ 120 $ 152 $ 1 Income from Equity Method Investees 36 16 20 — — Total Revenues 819 526 140 152 1 DD&A 539 437 67 22 13 Gain on Commodity Derivative Instruments (267 ) (187 ) (80 ) — — (Loss) Income Before Income Taxes (259 ) (189 ) 98 107 (275 ) Nine Months Ended September 30, 2016 Revenues from Third Parties $ 2,411 $ 1,705 $ 299 $ 407 $ — Income from Equity Method Investees 70 39 31 — — Total Revenues 2,481 1,744 330 407 — DD&A 1,859 1,612 150 62 35 Loss on Divestitures 23 23 — — — Loss on Commodity Derivative Instruments 53 44 9 — — (Loss) Income Before Income Taxes (1,231 ) (882 ) 74 290 (713 ) Nine Months Ended September 30, 2015 Revenues from Third Parties $ 2,264 $ 1,448 $ 432 $ 378 $ 6 Income from Equity Method Investees 60 35 25 — — Total Revenues 2,324 1,483 457 378 6 DD&A 1,444 1,138 223 52 31 Gain on Commodity Derivative Instruments (331 ) (231 ) (100 ) — — (Loss) Income Before Income Taxes (593 ) (353 ) 195 227 (662 ) September 30, 2016 Total Assets $ 22,469 $ 17,752 $ 1,975 $ 2,515 $ 227 December 31, 2015 Total Assets 24,196 18,831 2,299 2,677 389

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 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 September 30, 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. The funding has been suspended since November 2014 due to lower natural gas prices. Based on the September 30, 2016 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months. On October 29, 2016, we entered into an agreement with CONSOL to separate ownership of our jointly owned Marcellus Shale acreage, satisfy and extinguish the remaining balance of our carried cost obligation and terminate the joint development agreement. See Part II. Other Information, Item 5. Other Information . Delivery and Firm Transportation Commitments We have commitments to deliver approximately 493 Bcf of natural gas produced onshore US (primarily in the Marcellus Shale) under long-term sales contracts and have also entered into various long-term gathering, processing and transportation contracts for approximately 271 MMBbls of crude oil and nearly 6 Tcf of natural gas for certain of our onshore US production (primarily in the Marcellus Shale, DJ Basin and Eagle Ford Shale). We enter into long-term contracts to provide production flow assurance in over-supplied basins and/or areas 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. For the three and nine months ended September 30, 2016 , we incurred expense of approximately $12 million and $39 million , respectively, 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 and 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 (APCD) 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 that applied to assets currently owned and operated by both Noble Energy and Noble Midstream Services, LLC. In May, 2016, Noble Energy on behalf of itself and its wholly owned subsidiary Noble Midstream Services, LLC, on behalf of itself and its wholly owned subsidiary Colorado River DevCo LP, reached a final resolution with the APCD, which requires completion of compliance testing, modification of certain permits, payment of a civil penalty of $44,695 , and an expenditure of no less than $178,780 on an approved SEP. This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Statement of Operations Information	Statements of Operations Information Other statements of operations information is as follows: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Production Expense Lease Operating Expense $ 131 $ 133 $ 412 $ 419 Production and Ad Valorem Taxes 30 28 73 89 Transportation and Gathering Expense (1) 113 86 335 207 Total $ 274 $ 247 $ 820 $ 715 Other Operating (Income) Expense, Net (Gain) Loss on Asset Due to Terminated Contract (2) $ (3 ) $ — $ 44 $ — Marketing and Processing Expense, Net (3) 20 10 58 25 Loss on Divestitures — — 23 — Corporate Restructuring Expense — 21 — 39 Purchase Price Allocation Adjustment (4) — — (25 ) — Gain on Extinguishment of Debt (5) — — (80 ) — Asset Impairments — — — 43 Inventory Adjustment (6) 14 — 14 — Building Exit Cost 4 18 8 18 Rosetta Merger Expenses — 71 — 73 Pension Plan Expense — 67 — 88 Stacked Drilling Rig Expense 3 13 8 20 Other, Net 7 (12 ) 16 4 Total $ 45 $ 188 $ 66 $ 310 Other Non-Operating Expense (Income), Net Deferred Compensation Expense (Income) (7) $ 2 $ (13 ) $ 7 $ (19 ) Other (Income) Expense, Net (3 ) 1 (4 ) (1 ) Total $ (1 ) $ (12 ) $ 3 $ (20 ) (1) 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. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation. (2) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update . (3) For the three and nine months ended September 30, 2016 , amount includes $12 million and $39 million , respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015 , were previously presented within production expense. These amounts have been reclassified to conform to the current presentation. (4) Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger . (5) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt . (6) Amount relates to an adjustment of inventory to its net realizable value. (7) Amounts represent decreases (increases) 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) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 317 $ 298 Joint Interest Billings 66 20 Proceeds Receivable (1) 40 — Other 86 151 Allowance for Doubtful Accounts (23 ) (19 ) Total $ 486 $ 450 Other Current Assets Inventories, Materials and Supplies $ 75 $ 92 Inventories, Crude Oil 25 23 Assets Held for Sale (2) 214 67 Prepaid Expenses and Other Current Assets 38 34 Total $ 352 $ 216 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 460 $ 453 Mutual Fund Investments 83 90 Commodity Derivative Assets — 10 Other Assets 44 67 Total $ 587 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 121 $ 166 Commodity Derivative Liabilities 27 — Income Taxes Payable 168 86 Asset Retirement Obligations 128 128 Interest Payable 93 83 Current Portion of Capital Lease Obligations 61 53 Other 144 161 Total $ 742 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 232 $ 217 Asset Retirement Obligations 820 861 Production and Ad Valorem Taxes 35 68 Commodity Derivative Liabilities 8 — Other 44 73 Total $ 1,139 $ 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) Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures

Rosetta Merger Rosetta Merger (

Rosetta Merger Rosetta Merger (Tables)	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Schedule of purchase price allocations	The following table sets forth our final purchase price allocation: (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 Debt 1,992 Other Long Term Liabilities 23 Asset Retirement Obligation 27 Total purchase price plus liabilities assumed $ 3,708 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 Long Term Deferred Tax Asset 17 Goodwill (1) 138 Total Asset Value $ 3,708 (1) As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date.
Schedule of pro forma information	Three Months Ended Nine Months Ended (in millions, except per share amounts) 2016 (1) 2015 2016 (1) 2015 Revenues $ 910 $ 846 $ 2,481 $ 2,619 Net Loss Attributable to Noble Energy $ (144 ) $ (202 ) $ (746 ) $ (338 ) Net Loss Attributable to Noble Energy Per Share of Common Stock Basic $ (0.33 ) $ (0.44 ) $ (1.73 ) $ (0.79 ) Diluted $ (0.33 ) $ (0.44 ) $ (1.73 ) $ (0.79 ) (1) No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Derivative Instruments and He25

Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unsettled Derivative Instruments	Unsettled Commodity Derivative Instruments As of September 30, 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 2016 Call Option (1) NYMEX WTI 5,000 $ — $ — $ — $ 54.16 2016 Swaps NYMEX WTI 16,000 67.69 — — — 2016 Swaps (2) (3) 6,000 90.28 — — — 2016 Two-Way Collars NYMEX WTI 10,000 — — 40.50 53.42 2016 Three-Way Collars NYMEX WTI 8,000 — 54.50 65.63 79.03 2016 Swaps Dated Brent 9,000 97.96 — — — 2016 Three-Way Collars Dated Brent 8,000 — 72.50 86.25 101.79 1H17 (4) Swaps NYMEX WTI 6,000 55.08 — — — 1H17 (4) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (4) Swaps Dated Brent 3,000 62.80 — — — 2H17 (4) Call Option (1) NYMEX WTI 3,000 — — — 60.12 2H17 (4) Swaptions (5) Dated Brent 3,000 — — — 62.80 2H17 (4) Swaptions (5) NYMEX WTI 3,000 — — — 50.05 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.29 2017 Call Option (1) NYMEX WTI 3,000 — — — 57.00 2017 Swaptions (5) NYMEX WTI 4,000 — — — 47.34 2017 Three-Way Collars NYMEX WTI 15,000 — 36.33 46.33 60.68 2017 Three-Way Collars Dated Brent 2,000 — 35.00 45.00 66.33 2018 Three-Way Collars Dated Brent 3,000 — 40.00 50.00 70.41 (1) 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. (2) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (3) The indices for these derivative instruments are NYMEX WTI and Argus LLS. (4) We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year. (5) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. As of September 30, 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 2016 Swaps NYMEX HH 70,000 3.24 — — — 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 1H17 Swaps NYMEX HH 30,000 2.92 — — — 2H17 Swaptions (3) NYMEX HH 30,000 — — — 2.92 2017 Swaps NYMEX HH 30,000 3.15 — — — 2017 Swaptions (3) NYMEX HH 60,000 — — — 3.14 2017 Three-Way Collars NYMEX HH 180,000 — 2.50 2.93 3.58 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 70,000 — 2.50 2.80 3.76 (1) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. (2) The index for these derivative instruments is Houston Ship Channel. (3) We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
Fair Value of Derivative Instruments	Fair Value Amounts and Loss (Gain) 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 September 30, December 31, September 30, 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 $ 120 Current Assets $ 582 Current Liabilities $ 27 Current Liabilities $ — Noncurrent Assets — Noncurrent Assets 10 Noncurrent Liabilities 8 Noncurrent Liabilities — Total $ 120 $ 592 $ 35 $ —
Derivative Instruments, (Gain) Loss	The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Cash Received in Settlement of Commodity Derivative Instruments Crude Oil $ (119 ) $ (235 ) $ (395 ) $ (578 ) Natural Gas (13 ) (42 ) (59 ) (98 ) NGLs — (7 ) — (7 ) Total Cash Received in Settlement of Commodity Derivative Instruments (132 ) (284 ) (454 ) (683 ) Non-cash Portion of Loss on Commodity Derivative Instruments Crude Oil 80 4 441 301 Natural Gas (3 ) 3 66 41 NGLs — 10 — 10 Total Non-cash Portion of Loss on Commodity Derivative Instruments 77 17 507 352 (Gain) Loss on Commodity Derivative Instruments Crude Oil (39 ) (231 ) 46 (277 ) Natural Gas (16 ) (39 ) 7 (57 ) NGLs — 3 — 3 Total Loss (Gain) on Commodity Derivative Instruments $ (55 ) $ (267 ) $ 53 $ (331 )

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt [Abstract]
Schedule of debt	Debt consists of the following: September 30, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — % $ — — % Noble Midstream Revolving Credit Facility, due September 20, 2021 — — % — — — % Capital Lease and Other Obligations 368 — % 403 — % Term Loan Facility, due January 6, 2019 1,400 1.70 % — — % 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 5.625 % 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 5.875 % 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 5.875 % 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 7,957 7,976 Unamortized Discount (23 ) (24 ) Unamortized Premium 17 113 Unamortized Debt Issuance Costs (36 ) (36 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,915 8,029 Less Amounts Due Within One Year Capital Lease Obligations (61 ) (53 ) Long-Term Debt Due After One Year $ 7,854 $ 7,976

Fair Value Measurements and D27

Fair Value Measurements and Disclosures (Tables)	9 Months Ended
	Sep. 30, 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) September 30, 2016 Financial Assets Mutual Fund Investments $ 83 $ — $ — $ — $ 83 Commodity Derivative Instruments — 133 — (13 ) 120 Financial Liabilities Commodity Derivative Instruments — (48 ) — 13 (35 ) Portion of Deferred Compensation Liability Measured at Fair Value (105 ) — — — (105 ) Portion of Stock Based Compensation Liability Measured at Fair Value (6 ) — — — (6 ) 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	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) Nine Months Ended September 30, 2016 Material and Supplies Inventory Adjustment $ — $ — $ 91 $ 105 $ 14 Loss on Divestitures — — 42 65 23 Impaired Oil and Gas Properties — — — — — Nine Months Ended September 30, 2015 Impaired Oil and Gas Properties — — — 43 43 (1) Amount represents net book value at the date of assessment.
Additional fair value disclosures	Fair value information regarding our debt is as follows: September 30, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 7,547 $ 7,976 $ 7,626 $ 7,105 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well 28

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)	9 Months Ended
	Sep. 30, 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) Nine Months Ended September 30, 2016 Capitalized Exploratory Well Costs, Beginning of Period $ 1,353 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 83 Divestitures and Other (1) (143 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1 ) Capitalized Exploratory Well Costs Charged to Expense (2) (83 ) Capitalized Exploratory Well Costs, End of Period $ 1,209 (1) Includes $143 million relating to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner. (2)
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) September 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 91 $ 95 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 1,118 1,258 Balance at End of Period $ 1,209 $ 1,353 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 13 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 September 30, 2016 : (millions) Total by Project Progress Country/Project: Deepwater Gulf of Mexico Troubadour $ 52 Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. Katmai 97 Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options. Offshore Equatorial Guinea Blocks I and O Diega (Block I) and Carmen (Block O) 240 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 in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Carla (Block O) 184 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 in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Yolanda (Block I) 22 A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. Felicita (Block O) 45 Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Offshore Cameroon YoYo (YoYo Block) 53 A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. Offshore Israel Leviathan 196 Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands. Leviathan-1 Deep 84 The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 31 Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. Offshore Cyprus Cyprus 88 During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and 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 allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. Other Individual Projects Less than $20 million 26 Continuing to assess and evaluate wells. Total $ 1,118

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in ARO are as follows: Nine Months Ended (millions) 2016 2015 Asset Retirement Obligations, Beginning Balance $ 989 $ 751 Liabilities Incurred 5 54 Liabilities Settled (87 ) (29 ) Revision of Estimate 4 79 Accretion Expense (1) 37 32 Asset Retirement Obligations, Ending Balance $ 948 $ 887 (1) Accretion expense is included in Depreciation, Depletion and Amortization (DD&A) expense in the consolidated statements of operations.

Loss Per Share (Tables)

Loss Per Share (Tables)	9 Months Ended
	Sep. 30, 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 Nine Months Ended (millions, except per share amounts) 2016 2015 2016 2015 Net Loss Attributable to Noble Energy $ (144 ) $ (283 ) $ (746 ) $ (413 ) Weighted Average Number of Shares Outstanding, Basic (1) 430 420 430 392 Weighted Average Number of Shares Outstanding, Diluted (2) 430 420 430 392 Loss Per Share, Basic $ (0.33 ) $ (0.67 ) $ (1.73 ) $ (1.05 ) Loss Per Share, Diluted (0.33 ) (0.67 ) (1.73 ) (1.05 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 14 15 11 (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 all periods, 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)	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Tax Provision (Benefit)	The income tax benefit consists of the following: Three Months Ended Nine Months Ended (millions) 2016 2015 2016 2015 Current $ 148 $ (45 ) $ 213 $ 64 Deferred (285 ) 69 (699 ) (244 ) Total Income Tax (Benefit) Provision $ (137 ) $ 24 $ (486 ) $ (180 ) Effective Tax Rate 48.9 % (9.3 )% 39.5 % 30.4 %

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Information	(millions) Consolidated United States West Africa Eastern Mediterranean Other Int'l & Corporate Three Months Ended September 30, 2016 Revenues from Third Parties $ 882 $ 639 $ 93 $ 150 $ — Income from Equity Method Investees 28 8 20 — — Total Revenues 910 647 113 150 — DD&A 621 539 46 23 13 Gain on Commodity Derivative Instruments (55 ) (48 ) (7 ) — — (Loss) Income Before Income Taxes (280 ) (407 ) 47 135 (55 ) Three Months Ended September 30, 2015 Revenues from Third Parties $ 783 $ 510 $ 120 $ 152 $ 1 Income from Equity Method Investees 36 16 20 — — Total Revenues 819 526 140 152 1 DD&A 539 437 67 22 13 Gain on Commodity Derivative Instruments (267 ) (187 ) (80 ) — — (Loss) Income Before Income Taxes (259 ) (189 ) 98 107 (275 ) Nine Months Ended September 30, 2016 Revenues from Third Parties $ 2,411 $ 1,705 $ 299 $ 407 $ — Income from Equity Method Investees 70 39 31 — — Total Revenues 2,481 1,744 330 407 — DD&A 1,859 1,612 150 62 35 Loss on Divestitures 23 23 — — — Loss on Commodity Derivative Instruments 53 44 9 — — (Loss) Income Before Income Taxes (1,231 ) (882 ) 74 290 (713 ) Nine Months Ended September 30, 2015 Revenues from Third Parties $ 2,264 $ 1,448 $ 432 $ 378 $ 6 Income from Equity Method Investees 60 35 25 — — Total Revenues 2,324 1,483 457 378 6 DD&A 1,444 1,138 223 52 31 Gain on Commodity Derivative Instruments (331 ) (231 ) (100 ) — — (Loss) Income Before Income Taxes (593 ) (353 ) 195 227 (662 ) September 30, 2016 Total Assets $ 22,469 $ 17,752 $ 1,975 $ 2,515 $ 227 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				9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015		Jul. 04, 2016	Feb. 01, 2016	Dec. 31, 2015
Oil, Gas and NGL Sales		$ 882		$ 783		$ 2,411		$ 2,264
Share Price											$ 31.65
Production Expense
Lease Operating Expense		131		133		412		419
Production and Ad Valorem Taxes		30		28		73		89
Transportation and Gathering Expense (1)	[1]	113		86		335		207
Total		274		247		820		715
Other Operating (Income) Expense, Net
Loss on Asset Due to Terminated Contract	[2]	(3)		0		44		0
Midstream Gathering and Processing (Income) Expense, Net	[3]	20		10		58		25
Asset Impairments		0		0		0		43
Inventory Write-down		14		0		14		0
Business Exit Costs		4		18		8		18
Business combination costs		0		71		0	[4]	73	[4]
Pension And Other Postretirement Plans, Termination Expense		0		67		0		88
Facility Costs		3		13		8		20
Gain on Extinguishment of Debt	[5]	0		0		(80)		0
Other, Net		7		(12)		16		4
Total		45		188		66		310
Other Non-Operating Expense (Income), Net
Deferred Compensation Expense	[6]	2		(13)		7		(19)
Other (Income) Expense, Net		(3)		1		(4)		(1)
Total		(1)		(12)		3		(20)
Additional expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments		12		6		39		15
Accounts Receivable, Net
Commodity Sales		317				317						$ 298
Joint Interest Billings		66				66						20
Proceeds Receivable	[7]	40				40						0
Other		86				86						151
Allowance for Doubtful Accounts		(23)				(23)						(19)
Total		486				486						450
Other Current Assets
Inventories, Materials and Supplies		75				75						92
Inventories, Crude Oil		25				25						23
Assets Held-for-Sale	[8]	214				214						67
Prepaid Expenses and Other Current Assets		38				38						34
Total		352				352						216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries		460				460						453
Mutual Fund Investments		83				83						90
Commodity Derivative Assets		0				0						10
Other Assets		44				44						67
Total		587				587						620
Other Current Liabilities
Production and Ad Valorem Taxes		121				121						166
Derivative Liability, Current		27				27						0
Income Taxes Payable		168				168						86
Asset Retirement Obligations		128				128						128
Interest Payable		93				93						83
Current Portion of Capital Lease Obligations		61				61						53
Other		144				144						161
Total		742				742						677
Other Noncurrent Liabilities
Deferred Compensation Liabilities		232				232						217
Asset Retirement Obligations		820				820						861
Accrual for Taxes Other than Income Taxes		35				35						68
Derivative Liability, Noncurrent		8				8						0
Other		44				44						73
Total		$ 1,139				$ 1,139						$ 1,219
Percentage of divestiture farmed out		35.00%				35.00%						35.00%
Gain (Loss) on Disposition of Oil and Gas Property		$ 0		0		$ (23)		0
Restructuring Charges		0		21		0		39
Finalization of Purchase Price Allocation for Rosetta Merger		0	[4]	$ 0	[4]	(25)		$ 0	[4]
Phantom Units [Member]
Shares issued											1
NGL Revenue Previously Netted with Expense [Member]
Oil, Gas and NGL Sales		18				37
Tamar Field, Offshore Israel [Member]
Other Current Assets
Assets Held-for-Sale	[8]	$ 127				$ 127
Other Noncurrent Liabilities
Percentage of divestiture farmed out										3.00%
Working interest		3.00%				3.00%
[1]	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. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation.
[2]	Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update
[3]	For the three and nine months ended September 30, 2016, amount includes $12 million and $39 million, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015, were previously presented within production expense. These amounts have been reclassified to conform to the current presentation.
[4]	Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.
[5]	Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.
[6]	Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.
[7]	Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.
[8]	Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures

Noble Midstream Partners LP (De

Noble Midstream Partners LP (Details) - USD ($) $ / shares in Units, $ in Millions	Sep. 20, 2016	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Noble Midstream Partners LP [Member]
Subsidiary, Sale of Stock [Line Items]
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs				$ 0
Noble Midstream | IPO [Member]
Subsidiary, Sale of Stock [Line Items]
Limited Partners' Offering Costs	$ 24
Payments of Capital Distribution		$ 297
Noble Midstream | IPO [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	14,375,000
Shares Issued, Price Per Share	$ 22.50
Shares Issued, Price Per Share, Net	$ 21.21
Noble Midstream | Over-Allotment Option [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	1,875,000
Noble Midstream | Noble Energy [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	1,527,584
Noble Midstream | Noble Energy [Member] | Subordinated Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	15,902,584
Noble Midstream | Affiliated Entity [Member] | Noble Energy [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	4.80%
Noble Midstream | Affiliated Entity [Member] | Noble Energy [Member] | Subordinated Units [Member]
Subsidiary, Sale of Stock [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	50.00%
Noble Midstream | Noble Midstream Partners LP [Member]
Subsidiary, Sale of Stock [Line Items]
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs			$ 299

Rosetta Merger - Narrative (Det

Rosetta Merger - Narrative (Details) $ / shares in Units, a in Thousands, shares in Millions, $ in Millions		Jul. 20, 2015USD ($)abusiness$ / sharesshares	Sep. 30, 2016USD ($)		Sep. 30, 2015USD ($)		Sep. 30, 2016USD ($)		Sep. 30, 2015USD ($)	[1]	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Other Noncash Income			$ 0	[1]	$ 0	[1]	$ 25		$ 0
Shares exchange in acquisition | shares		41
Rosetta Merger Expenses			0		$ 71		0	[1]	$ 73
Pro forma revenue			119				333
Pro forma pre-tax net income			$ 4				$ 17
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	[2]	$ 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]	Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.
[2]	(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) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Jul. 20, 2015		Sep. 30, 2016	[1]	Sep. 30, 2015	[1]	Sep. 30, 2016	Sep. 30, 2015	[1]	Dec. 31, 2015
Business Acquisition [Line Items]
Other Noncash Income			$ 0		$ 0		$ 25	$ 0
Shares of Noble Energy common stock issued to Rosetta shareholders (in shares)	41
Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Shares of Noble Energy common stock issued to Rosetta shareholders (in shares)	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 Debt	1,992
Other Long Term Liabilities	23
Asset Retirement Obligation	27
Total purchase price plus liabilities assumed	3,708
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
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Assets Noncurrent	17
Goodwill	138	[2]								$ 163
Total Asset Value	$ 3,708
[1]	Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.
[2]	As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date.

Rosetta Merger - Pro Forma Info

Rosetta Merger - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Business Combinations [Abstract]
Revenues	$ 846	$ 2,619
Net Loss Attributable to Noble Energy	$ (202)	$ (338)
Net Loss Attributable to Noble Energy Per Share of Common Stock
Basic (in dollars per share)	$ (0.44)	$ (0.79)
Diluted (in dollars per share)	$ (0.44)	$ (0.79)

Divestitures (Details)

Divestitures (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Nov. 02, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)a	Sep. 30, 2015USD ($)	Jul. 04, 2016	Mar. 31, 2016USD ($)	Dec. 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%				35.00%
Sales Proceeds				$ 786	$ 151
Gain (Loss) on Disposition of Oil and Gas Property		$ 0	$ 0	(23)	$ 0
MONTANA
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				43
Bowdoin property, Northern Montana [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				19
Gain (Loss) on Disposition of Oil and Gas Property				(23)
Alon A And Alon C [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value									$ 73
Percentage of divestiture farmed out								47.00%
Cyprus Block 12 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value		143		143				$ 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
Weld County, Colorado [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sales agreement, consideration		$ 505		505
Producing and Undeveloped Net Acres in the DJ Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				$ 486
Purchase and sales agreement, area | a				33,100
Wells Ranch Development Area [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Purchase And Sales Agreement, Land Exchanged | a				11,700
Bronco Development Area [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sales agreement, area | a				13,500
Tamar Field, Offshore Israel [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of divestiture farmed out						3.00%
Sales Proceeds				$ 369
Option to purchase additional interest						1.00%
Subsequent Event [Member] | Eagle Ford [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash Provided by (Used in) Investing Activities, Discontinued Operations	$ 68

Derivative Instruments and He39

Derivative Instruments and Hedging Activities (Details)	9 Months Ended
	Sep. 30, 2016bbl / dMMBTU / d$ / bbl$ / MMBTU
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX WTI
Bbls Per Day | bbl / d	16,000
Weighted Average Fixed Price	67.69
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	10,000
Weighted Average Floor Price	40.50
Weighted Average Ceiling Price	53.42
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	8,000
Weighted Average Short Put Price	54.50
Weighted Average Floor Price	65.63
Weighted Average Ceiling Price	79.03
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 2016 [Member]
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX WTI
Bbls Per Day | bbl / d	5,000
Weighted Average Ceiling Price	54.16
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
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX WTI
Bbls Per Day | bbl / d	15,000
Weighted Average Short Put Price	36.33
Weighted Average Floor Price	46.33
Weighted Average Ceiling Price	60.68
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	Dated Brent
Bbls Per Day | bbl / d	2,000
Weighted Average Short Put Price	35
Weighted Average Floor Price	45
Weighted Average Ceiling Price	66.33
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2018 [Member]
Derivative [Line Items]
Settlement Period	2,018
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Short Put Price	40
Weighted Average Floor Price	50
Weighted Average Ceiling Price	70.41
Natural Gas Commodity Contract | Swaps - NYMEX HH 2016
Derivative [Line Items]
Settlement Period	2,016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	70,000
Weighted Average Fixed Price | $ / MMBTU	3.24
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	30,000
Weighted Average Fixed Price | $ / MMBTU	3.15
Natural Gas Commodity Contract | Swaptions - NYMEX HH 2017 [Member] [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 | Three Way Collars - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	180,000
Weighted Average Short Put Price | $ / MMBTU	2.50
Weighted Average Floor Price | $ / MMBTU	2.93
Weighted Average Ceiling Price | $ / MMBTU	3.58
Natural Gas Commodity Contract | Two Way Collars - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	70,000
Weighted Average Floor Price | $ / MMBTU	2.93
Weighted Average Ceiling Price | $ / MMBTU	3.32
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2018 [Member]
Derivative [Line Items]
Settlement Period	2,018
Index	NYMEX HH
Bbls Per Day | MMBTU / d	70,000
Weighted Average Short Put Price | $ / MMBTU	2.50
Weighted Average Floor Price | $ / MMBTU	2.80
Weighted Average Ceiling Price | $ / MMBTU	3.76
Rosetta Resources, Inc [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2,016
Index	(3)
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 (4)
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 - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	50.05
Second half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (4)
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	62.80
Second half 2017 [Member] | Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Ceiling Price | $ / MMBTU	2.92
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	6,000
Weighted Average Fixed Price	55.08
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (4)
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 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	2,000
Weighted Average Floor Price	40
Weighted Average Ceiling Price	50.44
First half 2017 [Member] | Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	2.92

Derivative Instruments and He40

Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 120		$ 120		$ 592
Derivative Liability, Fair Value	35		35		0
(Gain) Loss on Commodity Derivative Instruments	(55)	$ (267)	53	$ (331)
Non-cash Portion of Loss on Commodity Derivative Instruments	(132)	(284)	(454)	(683)
(Gain) Loss on Commodity Derivative Instruments	77	17	507	352
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	120		120		582
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value					0
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0		0		10
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	8		8		$ 0
Crude Oil [Member]
Derivatives, Fair Value [Line Items]
(Gain) Loss on Commodity Derivative Instruments	(39)	(231)	46	(277)
Non-cash Portion of Loss on Commodity Derivative Instruments	(119)	(235)	(395)	(578)
(Gain) Loss on Commodity Derivative Instruments	80	4	441	301
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
(Gain) Loss on Commodity Derivative Instruments	(16)	(39)	7	(57)
Non-cash Portion of Loss on Commodity Derivative Instruments	(13)	(42)	(59)	(98)
(Gain) Loss on Commodity Derivative Instruments	(3)	3	66	41
Natural Gas Liquids [Member]
Derivatives, Fair Value [Line Items]
(Gain) Loss on Commodity Derivative Instruments	0	3	0	3
Non-cash Portion of Loss on Commodity Derivative Instruments	0	(7)		(7)
(Gain) Loss on Commodity Derivative Instruments	$ 0	$ 10	$ 0	$ 10

Debt (Details)

Debt (Details) - USD ($)		Nov. 01, 2016	Jan. 06, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Sep. 20, 2016	Aug. 27, 2015
Debt Instrument [Line Items]
Debt				$ 7,957,000,000		$ 7,957,000,000		$ 7,976,000,000
Unamortized Discount				(23,000,000)		(23,000,000)		(24,000,000)
Debt Instrument, Unamortized Premium				17,000,000		17,000,000		113,000,000
Total Debt, Net of Discount				7,915,000,000		7,915,000,000		8,029,000,000
Capital Lease Obligations, Current				(61,000,000)		(61,000,000)		(53,000,000)
Long-term Debt Due After One Year				7,854,000,000		7,854,000,000		7,976,000,000
Gain on tendered offers	[1]			0	$ 0	80,000,000	$ 0
Repayments of Long-term Lines of Credit						0	$ 74,000,000
Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt				$ 1,400,000,000		$ 1,400,000,000		$ 0
Debt stated rate				1.698%		1.698%		0.00%
Debt instrument, maturity date						Jan. 6, 2019
Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Debt				$ 0		$ 0		$ 0
Debt stated rate				0.00%		0.00%		0.00%
Debt instrument, maturity date						Aug. 27, 2020		Aug. 27, 2020
Maximum borrowing capacity				$ 4,000,000,000		$ 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		450,000,000
Credit facility interest rate, Eurodollar rate plus, minimum										0.90%
Credit facility interest rate, Eurodollar rate plus, maximum										1.50%
Noble Midstream Revolving Credit Facility, due September 20, 2021
Debt Instrument [Line Items]
Debt				$ 0		$ 0		$ 0
Debt stated rate				0.00%		0.00%		0.00%
Capital Lease and Other Obligations
Debt Instrument [Line Items]
Debt				$ 368,000,000		$ 368,000,000		$ 403,000,000
Debt stated rate				0.00%		0.00%		0.00%
Capital Lease Obligations, Current				$ (61,000,000)		$ (61,000,000)		$ (53,000,000)
8.25% Senior Notes, due March 1, 2019
Debt Instrument [Line Items]
Debt				$ 1,000,000,000		$ 1,000,000,000		$ 1,000,000,000
Debt stated rate				8.25%		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		$ 379,000,000		$ 693,000,000
Debt stated rate				5.625%		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		$ 1,000,000,000
Debt stated rate				4.15%		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		$ 18,000,000		$ 597,000,000
Debt stated rate				5.875%		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		$ 100,000,000
Debt stated rate				7.25%		7.25%		7.25%
Debt instrument, maturity date						Oct. 15, 2023		Oct. 15, 2023
Unamortized Debt Issuance Expense				$ (36,000,000)		$ (36,000,000)		$ (36,000,000)
5.875% Senior Notes, due June 1, 2024
Debt Instrument [Line Items]
Debt				$ 8,000,000		$ 8,000,000		$ 499,000,000
Debt stated rate				5.875%		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		$ 650,000,000
Debt stated rate				3.90%		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		$ 250,000,000
Debt stated rate				8.00%		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		$ 850,000,000
Debt stated rate				6.00%		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		$ 1,000,000,000
Debt stated rate				5.25%		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		$ 850,000,000
Debt stated rate				5.05%		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		$ 84,000,000
Debt stated rate				7.25%		7.25%		7.25%
Debt instrument, maturity date						Aug. 1, 2097		Aug. 1, 2097
Revolving Credit Facility, due August 27, 2020 | Term Loan Facility [Member]
Debt Instrument [Line Items]
Proceeds from Lines of Credit						$ 1,380,000,000
Debt Instrument, Term			3 years
Revolving Credit Facility, due August 27, 2020 | Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility fee rate basis points, minimum			0.10%
Credit facility fee rate basis points, maximum			0.75%
Revolving Credit Facility, due August 27, 2020 | Federal Funds Effective Swap Rate [Member] | Term Loan 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] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate			1.00%
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%
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
Noble Midstream | Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Maximum borrowing capacity									$ 350,000,000
Available increase in capacity									350,000,000
Debt Instrument, Term						5 years
Noble Midstream | Revolving Credit Facility, due August 27, 2020 | Federal Funds Effective Swap Rate [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate						0.50%
Noble Midstream | Revolving Credit Facility, due August 27, 2020 | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate						1.00%
Letter of Credit | Noble Midstream | Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Maximum borrowing capacity									$ 100,000,000
Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Lines of Credit		$ 850,000,000
[1]	Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

Fair Value Measurements and D42

Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Financial Assets [Abstract]
Mutual Fund Investments		$ 83	$ 90
Commodity Derivative Instruments		120	592
Financial Liabilities [Abstract]
Commodity Derivative Instruments		(35)	0
Portion of Deferred Compensation Liability Measured at Fair Value		(105)	(98)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability		(6)
Quoted Prices in Active Markets (Level 1)
Financial Assets [Abstract]
Mutual Fund Investments	[1]	83	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]	(105)	(98)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[1]	(6)
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]	133	600
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[3]	(48)	(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]	(13)	(8)
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[4]	13	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 D43

Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Nonrecurring Basis (Details 2) - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Inventory Write-down		$ 14,000,000	$ 0	$ 14,000,000	$ 0
Asset Impairment Charges				0
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties		0	0	0	43,000,000
Impairment Of Materials And Supply Inventory				14,000,000
Assets Held For Sale, Net Book Value		65,000,000		65,000,000
Impairments On Assets Held For Sale				23,000,000
Material and Supply Inventory, Net Book Value				105,000,000
Oil and Gas Property, Full Cost Method, Net	[1]			0	43,000,000
Gain (Loss) on Disposition of Oil and Gas Property		0	$ 0	(23,000,000)	0
Quoted Prices in Active Markets (Level 1)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties				0	0
Impairment Of Materials And Supply Inventory				0
Loss On Assets Held For Sale		0		0
Significant Other Observable Inputs (Level 2)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties				0	0
Impairment Of Materials And Supply Inventory				0
Loss On Assets Held For Sale		0		0
Significant Unobservable Inputs (Level 3)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties				0	$ 0
Impairment Of Materials And Supply Inventory				91,000,000
Loss On Assets Held For Sale		$ 42,000,000		$ 42,000,000
[1]	Amount represents net book value at the date of assessment.

Fair Value Measurements and D44

Fair Value Measurements and Disclosures (Details 3) - USD ($) $ in Millions		Sep. 30, 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]	$ 7,547	$ 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]	$ 7,976	$ 7,105
[1]	(1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well 45

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Details) - USD ($) $ in Millions		3 Months Ended	9 Months Ended
		Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
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			83
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves			(1)
Capitalized Exploratory Well Cost, Charged to Expense	[1]		(83)
Capitalized Exploratory Well Costs, End of Period		$ 1,209	1,209
Exploratory Well Costs Capitalized for a Period of One Year or Less					$ 91		$ 95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					1,118		1,258
Capitalized Exploratory Well Costs, End of Period		1,209	1,353		$ 1,209		$ 1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling					13		14
Percentage of divestiture farmed out					35.00%		35.00%
Capitalized undeveloped leasehold cost		105	2,000
Leasehold impairment		81	81	$ 0
Valuation allowance increase		$ 24
Onshore US [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost			1,900
International [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost			32
Deepwater Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost			$ 116
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					$ 97
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					52
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					240
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					184
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					53
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					196
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					84
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					31
Cyprus [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					88
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					26
Cyprus Block 12 [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Farmdown					$ (143)		$ (171)
Aging of Capitalized Exploratory Well Costs, Period One [Member] | 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						$ 45
Aging of Capitalized Exploratory Well Costs, Period One [Member] | 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						$ 22
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmY2MDg3ODRkZDk2OTRkYjQ4NmY5ZjE3ODJiNzcwMGMzfFRleHRTZWxlY3Rpb246QzgzOTkyOEJBNDJGNUY3M0EwRkI4RTlERjdBMkE2N0IM}

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance		$ 989	$ 751
Liabilities Incurred		5	54
Liabilities Settled		(87)	(29)
Revision of Estimate		4	79
Accretion Expense	[1]	37	32
Asset Retirement Obligations, Ending Balance		948	887
Eastern Mediterranean [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate			43
DJ Basin (Onshore US) [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate			$ 28
Deepwater Gulf of Mexico [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities Incurred		42
Onshore US [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities Incurred		$ 40
[1]	Accretion expense is included in Depreciation, Depletion and Amortization (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	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net Income (Loss) Attributable to Parent			$ (144)	$ (283)		$ (746)	$ (413)
Weighted Average, Number of Shares Outstanding, Basic (in shares)	[1]		430,000,000	420,000,000		430,000,000	392,000,000
Weighted Average, Number of Shares Outstanding, Diluted (in shares)	[2]		430,000,000	420,000,000		430,000,000	392,000,000
Earnings (Loss) from Continuing Operations Per Share, Basic (in dollars per share)			$ (0.33)	$ (0.67)		$ (1.73)	$ (1.05)
Earnings (Loss) from Continuing Operations Per Share, Diluted (in dollars per share)			$ (0.33)	$ (0.67)		$ (1.73)	$ (1.05)
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above (in shares)			14,000,000	14,000,000		15,000,000	11,000,000
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.
[2]	For all periods, 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 (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Tax Examination [Line Items]
Current	$ 148	$ (45)	$ 213	$ 64
Deferred	(285)	69		(244)
Total Income Tax (Benefit) Provision	$ (137)	$ 24	$ (486)	$ (180)
Effective Tax Rate	48.90%	(9.30%)	39.50%	30.40%
US
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination			2,013
Equatorial Guinea
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination			2,011
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues from Third Parties	$ 882	$ 783	$ 2,411	$ 2,264
Income from Equity Method Investees	28	36	70	60
Total Revenues	910	819	2,481	2,324
DD&A	621	539	1,859	1,444
Loss on Divestitures	0	0	23	0
Asset Impairments	0	0	0	43
(Gain) Loss on Commodity Derivative Instruments	(55)	(267)	53	(331)
(Loss) Income Before Income Taxes	(280)	(259)	(1,231)	(593)
Total Assets	22,469		22,469		$ 24,196
United States [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	639	510	1,705	1,448
Income from Equity Method Investees	8	16	39	35
Total Revenues	647	526	1,744	1,483
DD&A	539	437	1,612	1,138
Loss on Divestitures			23
(Gain) Loss on Commodity Derivative Instruments	(48)	(187)	44	(231)
(Loss) Income Before Income Taxes	(407)	(189)	(882)	(353)
Total Assets	17,752		17,752		18,831
West Africa [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	93	120	299	432
Income from Equity Method Investees	20	20	31	25
Total Revenues	113	140	330	457
DD&A	46	67	150	223
Loss on Divestitures			0
(Gain) Loss on Commodity Derivative Instruments	(7)	(80)	9	(100)
(Loss) Income Before Income Taxes	47	98	74	195
Total Assets	1,975		1,975		2,299
Eastern Mediterranean [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	150	152	407	378
Income from Equity Method Investees	0	0	0	0
Total Revenues	150	152	407	378
DD&A	23	22	62	52
Loss on Divestitures			0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
(Loss) Income Before Income Taxes	135	107	290	227
Total Assets	2,515		2,515		2,677
Other Int'l & Corporate [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	0	1	0	6
Income from Equity Method Investees	0	0	0	0
Total Revenues	0	1	0	6
DD&A	13	13	35	31
Loss on Divestitures			0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
(Loss) Income Before Income Taxes	(55)	$ (275)	(713)	$ (662)
Total Assets	$ 227		$ 227		$ 389

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details)	1 Months Ended	3 Months Ended		9 Months Ended
	May 31, 2016USD ($)	Sep. 30, 2016USD ($)TcfBcfMMBbls	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)$ / MMBTUTcfBcfMMBbls	Sep. 30, 2015USD ($)
Other Commitments [Line Items]
Additional expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments		$ 12,000,000	$ 6,000,000	$ 39,000,000	$ 15,000,000
Supplemental environmental projects	$ 178,780
Reduced penalty	$ 44,695
CONSOL Carried Cost Obligation [Member]
Other Commitments [Line Items]
Equity method investment, ownership percentage		50.00%		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
Natural Gas [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Available Amounts to be Received | Tcf		6		6
Crude Oil [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Available Amounts to be Received | MMBbls		271		271
Marcellus Shale [Member] | Natural Gas [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Available Amounts to be Received | Bcf		493		493

Uncategorized Items - nbl-20160

Label	Element	Value
Repayments of Senior Debt	us-gaap_RepaymentsOfSeniorDebt	$ 12,000,000