Noble Energy (NBL) 10-Q 2 May 17 2017 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	3 Months Ended
	Mar. 31, 2017shares
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	431,414,543
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Revenues
Oil, NGL and Gas Sales		$ 994	$ 705
Income from Equity Method Investees		42	19
Total		1,036	724
Costs and Expenses
Production Expense		303	276
Exploration Expense		42	163
Depreciation, Depletion and Amortization		528	617
General and Administrative		99	91
Other Operating Expense, Net		29	(1)
Total		1,001	1,146
Operating Income (Loss)		35	(422)
Other Expense (Income)
Gain on Commodity Derivative Instruments		(110)	(44)
Interest, Net of Amount Capitalized		87	79
Other Non-Operating Income, Net		(1)	(4)
Total		(24)	31
Income (Loss) Before Income Taxes		59	(453)
Income Tax Provision (Benefit)		12	(166)
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests		47	(287)
Less: Net Income and Comprehensive Income (Loss) Attributable to Noncontrolling Interests		11	0
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests		$ 36	$ (287)
Loss per share, basic (in dollars per share)		$ 0.08	$ (0.67)
Loss per share, diluted (in dollars per share)		$ 0.08	$ (0.67)
Weighted Average Number of Shares Outstanding
Basic (in shares)	[1]	431	429
Diluted (in shares)	[2]	434	429
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk1YmYwYzc1YTZjMzRiODlhMjM5ZGQxOWU2MGYxYWI5fFRleHRTZWxlY3Rpb246RkI3RUI3MTE2OEVENTI4N0FGQ0IxQUNENjZBNjVDOTAM}
[2]	For first quarter 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as the Company 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-dilut

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	$ 787	$ 1,180
Accounts Receivable, Net	523	615
Other Current Assets	135	160
Total Current Assets	1,445	1,955
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	31,301	30,355
Property, Plant and Equipment, Other	907	909
Total Property, Plant and Equipment, Gross	32,208	31,264
Accumulated Depreciation, Depletion and Amortization	(13,180)	(12,716)
Total Property, Plant and Equipment, Net	19,028	18,548
Other Noncurrent Assets	535	508
Total Assets	21,008	21,011
Current Liabilities
Accounts Payable - Trade	895	736
Other Current Liabilities	598	742
Total Current Liabilities	1,493	1,478
Long-Term Debt	6,995	7,011
Deferred Income Taxes	1,819	1,819
Other Noncurrent Liabilities	1,092	1,103
Total Liabilities	11,399	11,411
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; 473 Million and 471 Million Shares Issued, respectively	5	5
Additional Paid in Capital	6,472	6,450
Accumulated Other Comprehensive Loss	(31)	(31)
Treasury Stock, at Cost; 38 Million Shares	(703)	(692)
Retained Earnings	3,549	3,556
Noble Energy Share of Equity	9,292	9,288
Stockholders' Equity Attributable to Noncontrolling Interest	317	312
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	9,609	9,600
Total Liabilities and Equity	$ 21,008	$ 21,011

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
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)	473,000,000	471,000,000
Treasury stock, shares (in shares)	38,000,000	38,000,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flows From Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 47	$ (287)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	528	617
Results of Operations, Dry Hole Costs	0	93
Gain on Extinguishment of Debt	0	(80)	[1]
Deferred Income Tax Benefit	0	(186)
Gain on Commodity Derivative Instruments	(110)	(44)
Net Cash Received in Settlement of Commodity Derivative Instruments	3	178
Other Adjustments for Noncash Items Included in Income	20	96
Changes in Operating Assets and Liabilities
Decrease (Increase) in Accounts Receivable	59	(38)
Increase (Decrease) in Accounts Payable	45	(24)
(Decrease) in Current Income Taxes Payable	(23)	(16)
Other Current Assets and Liabilities, Net	(35)	(64)
Other Operating Assets and Liabilities, Net	2	6
Net Cash Provided by Operating Activities	536	251
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(587)	(496)
Asset Acquisition	(316)	0
Proceeds from Divestitures and Other	40	232
Net Cash Used in Investing Activities	(863)	(264)
Cash Flows From Financing Activities
Dividends Paid, Common Stock	(44)	(41)
Proceeds from Term Loan Facility	0	1,400
Repayment of Senior Notes	0	(1,383)
Other	(22)	(38)
Net Cash Used in Financing Activities	(66)	(62)
Decrease in Cash and Cash Equivalents	(393)	(75)
Cash and Cash Equivalents at Beginning of Period	1,180	1,028
Cash and Cash Equivalents at End of Period	$ 787	$ 953
[1]	.

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, 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	(287)	0	0	0	0	(287)	0
Stock-based Compensation	19	0	19	0	0	0	0
Dividends	(41)	0	0	0	0	(41)	0
Other	(9)	0	(1)	0	(8)	0	0
Balance at End of Period at Mar. 31, 2016	10,052	5	6,378	(33)	(696)	4,398	0
Balance at Beginning of Period at Dec. 31, 2016	9,600	5	6,450	(31)	(692)	3,556	312
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	47	0	0	0	0	36	11
Stock-based Compensation	13	0		0	0	0	0
Dividends	(44)	0	0	0	0	(44)	0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(6)	0	0	0	0	0	(6)
Other	(1)	0	9	0	(11)	1	0
Balance at End of Period at Mar. 31, 2017	$ 9,609	$ 5	$ 6,472	$ (31)	$ (703)	$ 3,549	$ 317

Consolidated Statements of Sha7

Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.10	$ 0.10

Organization and Nature of Oper

Organization and Nature of Operations	3 Months Ended
	Mar. 31, 2017
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 operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale; offshore US Gulf of Mexico; Eastern Mediterranean; and West Africa.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2017
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 March 31, 2017 and December 31, 2016 and for the three months ended March 31, 2017 and 2016 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. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income or loss is identical to comprehensive income or loss. Certain prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . 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, 2016 . Consolidation Our consolidated accounts include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), 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 Partners lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), 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 Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners. 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. Recently Issued Accounting Standards Leases 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. 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. At this time, we can not reasonably estimate the financial impact this ASU will have on our financial statements; however, we do believe adoption and implementation of this ASU will likely materially impact our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. Business Combinations - Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations - Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they meet the requirements of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. This ASU is designed to reduce the number of business transactions, which take more time and cost more than asset transactions. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our current Clayton Williams Energy Acquisition (defined below) will not be impacted by this guidance and we will apply the new guidance to applicable and qualifying transactions after our adoption in 2018. Financial Instruments - Credit Losses 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. Revenue Recognition 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, revenue recognition would occur upon 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. Currently, we do not have any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. Based upon our evaluation of the ASU and our analysis to-date, we have not identified any material impact on our financial statements other than enhanced disclosures. Statement of Cash Flows - Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows - Restricted Cash , which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures. Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments 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 eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. 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. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended (millions) 2017 2016 Production Expense Lease Operating Expense $ 139 $ 161 Production and Ad Valorem Taxes (1) 45 4 Gathering, Transportation and Processing Expense (2) 119 111 Total $ 303 $ 276 Other Operating (Income) Expense, Net Marketing Expense (3) $ 19 $ 18 Gain on Extinguishment of Debt (4) — (80 ) Loss on Asset Due to Terminated Contract (5) 4 42 Other, Net 6 19 Total $ 29 $ (1 ) Other Non-Operating Expense (Income), Net Other Income, Net (1 ) (4 ) Total $ (1 ) $ (4 ) (1) For first quarter 2017 , total production expense increased as compared with 2016 due to higher production taxes associated with higher realized commodity prices, as well as a $28 million US onshore severance tax refund recorded in first quarter 2016 and a $7 million US onshore severance tax charge recorded in first quarter 2017. (2) Certain of our processing expense was historically presented as a component of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect processing expense as a component of production expense. These costs are now included within gathering, transportation and processing expense. For the three month period ended March 31, 2017, these costs totaled $3 million , and the prior year amount of $4 million for the three months ended March 31, 2016 has been reclassified from marketing expense to conform to the current presentation. (3) Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (4) Amount relates to the tendering of senior notes. See Note 6. Debt . (5) Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance. Balance Sheet Information Other balance sheet information is as follows: (millions) March 31, December 31, Accounts Receivable, Net Commodity Sales $ 362 $ 403 Joint Interest Billings 119 106 Proceeds Receivable (1) — 40 Other 63 86 Allowance for Doubtful Accounts (21 ) (20 ) Total $ 523 $ 615 Other Current Assets Inventories, Materials and Supplies $ 71 $ 71 Inventories, Crude Oil 21 18 Restricted Cash (2) — 30 Prepaid Expenses and Other Current Assets 43 41 Total $ 135 $ 160 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 407 $ 400 Mutual Fund Investments 74 71 Other Assets 54 37 Total $ 535 $ 508 Other Current Liabilities Production and Ad Valorem Taxes $ 116 $ 115 Commodity Derivative Liabilities 23 102 Income Taxes Payable 30 53 Asset Retirement Obligations 160 160 Interest Payable 93 76 Current Portion of Capital Lease Obligations 66 63 Other 110 173 Total $ 598 $ 742 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 215 $ 218 Asset Retirement Obligations 772 775 Production and Ad Valorem Taxes 61 47 Other 44 63 Total $ 1,092 $ 1,103 (1) Balance at December 31, 2016 related to the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017. (2) Balance at December 31, 2016 represented amount held in escrow for the purchase of certain Delaware Basin properties. The transaction closed in first quarter 2017. See Note 4. Acquisitions and Divestitures .

Clayton Williams Energy Acquisi

Clayton Williams Energy Acquisition	3 Months Ended
	Mar. 31, 2017
Business Combinations [Abstract]
Clayton Williams Energy Acquisition	Clayton Williams Energy Acquisition In January 2017, we announced the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) which was approved by Clayton Williams Energy stockholders on April 24, 2017. On April 24, 2017 , subsequent to first quarter 2017, we completed the acquisition which increases our Southern Delaware position to approximately 118,000 net acres. The acquisition was effected through the issuance of approximately 55 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion , and cash consideration of $665 million , for total consideration of approximately $2.6 billion , in exchange for all outstanding shares of Clayton Williams Energy, including options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. The results of Clayton Williams Energy's operations will be included in our consolidated statements of operations beginning April 24, 2017 . We will account for the transaction as a business combination, using the acquisition method. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final reserve reports and operating information for the properties acquired, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the allocation, including any goodwill, will be revised if necessary.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2017
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 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Unsettled Commodity Derivative Instruments As of March 31, 2017 , 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 1H17 (2) Swaps NYMEX WTI 6,000 $ 55.08 $ — $ — $ — 1H17 (2) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (2) Swaps Dated Brent 3,000 62.80 — — — 2H17 (2) Call Option (1) NYMEX WTI 3,000 — — — 60.12 2H17 (2) Swaptions (3) Dated Brent 3,000 62.80 — — — 2H17 (2) Swaptions (3) NYMEX WTI 3,000 50.05 — — — 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.38 2017 Call Option (1) NYMEX WTI 3,000 — — — 57.00 2017 Swaps NYMEX WTI 4,000 50.90 — — — 2017 Three-Way Collars NYMEX WTI 24,000 — 39.08 47.71 61.20 2017 Three-Way Collars Dated Brent 2,000 — 35.00 45.00 66.33 2017 Three-Way Collars ICE Brent 2,000 — 43.00 50.00 63.15 2018 Three-Way Collars NYMEX WTI 10,000 — 45.50 52.50 69.09 2018 Swaptions (3) NYMEX WTI 3,000 56.10 — — — 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) We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year. (3) 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 March 31, 2017 , 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 1H17 Swaps NYMEX HH 30,000 $ 2.92 $ — $ — $ — 2H17 Swaps NYMEX HH 30,000 3.45 — — — 2H17 Swaptions (1) NYMEX HH 30,000 2.92 — — — 2017 Swaps NYMEX HH 110,000 3.19 — — — 2017 Three-Way Collars NYMEX HH 210,000 — 2.54 2.96 3.62 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 110,000 — 2.50 2.87 3.67 (1) 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 (Gain) Loss on Commodity Derivative Instruments The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments March 31, December 31, March 31, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 6 Current Assets $ — Current Liabilities $ 23 Current Liabilities $ 102 Noncurrent Assets 8 Noncurrent Assets — Noncurrent Liabilities — Noncurrent Liabilities 14 Total $ 14 $ — $ 23 $ 116 The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended (millions) 2017 2016 Cash Paid (Received) in Settlement of Commodity Derivative Instruments Crude Oil $ (5 ) $ (156 ) Natural Gas 2 (22 ) Total Cash Received in Settlement of Commodity Derivative Instruments (3 ) (178 ) Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (63 ) 127 Natural Gas (44 ) 7 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (107 ) 134 Gain on Commodity Derivative Instruments Crude Oil (68 ) (29 ) Natural Gas (42 ) (15 ) Total Gain on Commodity Derivative Instruments $ (110 ) $ (44 )

Debt

Debt	3 Months Ended
	Mar. 31, 2017
Debt [Abstract]
Debt	Debt Debt consists of the following: March 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — % $ — — % Noble Midstream Services Revolving Credit Facility, due September 20, 2021 — — % — — % Term Loan Facility, due January 6, 2019 550 2.20 % 550 2.01 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — % 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 % 379 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 % 18 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 % 8 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 % Capital Lease and Other Obligations 361 — % 375 — % Total 7,100 7,114 Unamortized Discount (22 ) (23 ) Unamortized Premium 15 17 Unamortized Debt Issuance Costs (32 ) (34 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,061 7,074 Less Amounts Due Within One Year Capital Lease Obligations (66 ) (63 ) Long-Term Debt Due After One Year $ 6,995 $ 7,011 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. Noble Midstream Services Revolving Credit Facility In 2016, Noble Midstream Services, LLC, a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility) which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners. Borrowings by Noble Midstream Partners under the Noble Midstream Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) 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 (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. Leviathan Term Loan Agreement On February 24, 2017, Noble Energy Mediterranean Ltd. (“NEML”), a wholly owned subsidiary of Noble Energy, entered into a facility agreement (“Leviathan Term Loan Facility”) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion , of which $625 million is initially committed. Any loans borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development (predominately for domestic supply and building the foundation for regional exports) of the Leviathan field offshore Israel. Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025 and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios. Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period. The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries. Term Loan Agreement and Completed Tender Offers In 2016, we entered into a term loan agreement (Term Loan Facility) which provides for a three -year term loan facility for a principal amount of $1.4 billion . The Term Loan Facility accrues 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) LIBOR plus 1.0% , plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) LIBOR plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in the Rosetta Merger. As a result, we recognized a gain of $80 million in first quarter 2016 which is reflected in other operating (income) expense, net in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of long-term debt outstanding under the Term Loan Facility from cash on hand. As of March 31, 2017, $550 million was outstanding under the facility. Subsequent Event On April 24, 2017, we borrowed $1.3 billion under our Revolving Credit Facility in connection with the Clayton Williams Energy Acquisition. The interest rate on our Revolving Credit Facility is a floating interest rate and was 2.0% on April 24, 2017. See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Fair Value Measurements and Dis

Fair Value Measurements and Disclosures	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements and Disclosures	Fair Value Measurements and Disclosures Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets. Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and enhanced swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 5. Derivative Instruments and Hedging Activities . Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above . Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period. Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement (millions) March 31, 2017 Financial Assets Mutual Fund Investments $ 74 $ — $ — $ 74 Commodity Derivative Instruments — 23 — (9 ) 14 Financial Liabilities Commodity Derivative Instruments — (32 ) — 9 (23 ) Portion of Deferred Compensation Liability Measured at Fair Value (89 ) — — — (89 ) Stock Based Compensation Liability Measured at Fair Value (10 ) — — — (10 ) December 31, 2016 Financial Assets Mutual Fund Investments $ 71 $ — $ — $ — $ 71 Commodity Derivative Instruments — 5 — (5 ) — Financial Liabilities Commodity Derivative Instruments — (121 ) — 5 (116 ) Portion of Deferred Compensation Liability Measured at Fair Value (88 ) — — — (88 ) Stock Based Compensation Liability Measured at Fair Value (9 ) — — — (9 ) (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 such as inventory, assets, and assets held for sale are measured at fair value on a nonrecurring basis in our consolidated balance sheets. For the three months ended March 31, 2017 and 2016, we had no adjustments in fair value related to these items. Additional Fair Value Disclosures Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy. Our Term Loan Facility is variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of our Term Loan Facility to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt . Fair value information regarding our debt is as follows: March 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,700 $ 7,200 $ 6,699 $ 7,112 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	3 Months Ended
	Mar. 31, 2017
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) Three Months Ended March 31, 2017 Capitalized Exploratory Well Costs, Beginning of Period $ 768 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 6 Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1) (203 ) Capitalized Exploratory Well Costs, End of Period $ 571 (1) Amount relates to the approval and sanction of the first phase of development of the Leviathan field offshore Israel. Initial Leviathan field proved reserves are expected to be recorded in 2017. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions) March 31, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 58 $ 69 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1) 513 699 Balance at End of Period $ 571 $ 768 (1) The decrease from December 31, 2016 is attributable to the reclassification of the Leviathan field to development work in process, partially offset by the capitalization of interest during the period on remaining exploratory wells. Undeveloped Leasehold Costs Undeveloped leasehold costs as of March 31, 2017 totaled $2.3 billion , primarily comprised of $2.2 billion related to US onshore unproved properties. These costs were derived from allocated fair values as a result of a business combination or other purchase of unproved properties and, in that the properties are primarily held by production, they are subject to impairment testing utilizing a future cash flows analysis. The remaining undeveloped leasehold costs as of March 31, 2017 included $86 million related to Gulf of Mexico unproved properties and $52 million related to international unproved properties. These costs are evaluated as part of our periodic impairment review. 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 impairment expense related to the respective leases. During first quarter 2017 , we completed a geological evaluation of certain deepwater Gulf of Mexico leases and determined that $18 million of undeveloped leasehold cost should be written-off.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Three Months Ended (millions) 2017 2016 Asset Retirement Obligations, Beginning Balance $ 935 $ 989 Liabilities Incurred 1 2 Liabilities Settled (9 ) (8 ) Revision of Estimate (7 ) 5 Accretion Expense (1) 12 12 Asset Retirement Obligations, Ending Balance $ 932 $ 1,000 (1) Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations. For the three months ended March 31, 2017 Liabilities incurred were due to new wells and facilities placed into service for US onshore. Liabilities settled primarily related to US onshore property abandonments. Revisions of estimates related to changes in cost estimates of $7 million for deepwater Gulf of Mexico. For the three months ended March 31, 2016 Liabilities incurred were due to new wells and facilities for US onshore. Liabilities settled primarily related to US onshore property abandonments. Revisions of estimates relate to changes in cost estimates of $5 million for Equatorial Guinea.

Loss Per Share

Loss Per Share	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Loss Per Share	Income (Loss) Per Share Attributable to Noble Energy Noble Energy's basic income (loss) per share of common stock is computed by using net income (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 income (loss) per share: Three Months Ended (millions, except per share amounts) 2017 2016 Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy $ 36 $ (287 ) Weighted Average Number of Shares Outstanding, Basic 431 429 Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (1) 3 — Weighted Average Number of Shares Outstanding, Diluted 434 429 Income (Loss) Per Share, Basic $ 0.08 $ (0.67 ) Income (Loss) Per Share, Diluted 0.08 (0.67 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 15 (1) For first quarter 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as the Company incurred a net loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted loss per share would be anti-dilutive.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax provision (benefit) consists of the following: Three Months Ended (millions) 2017 2016 Current $ 12 $ 20 Deferred — (186 ) Total Income Tax Provision (Benefit) $ 12 $ (166 ) Effective Tax Rate 20.3 % 36.6 % 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 months ended March 31, 2017 , varied as compared with the three months ended March 31, 2016 , primarily due to: • income before income taxes for first quarter 2017 as compared with a loss before income taxes for first quarter 2016; and • discrete items with a disproportionate impact to the rate due to lower earnings during first quarter 2017. Our deferred income tax provision for first quarter 2017 had a de minimis impact which was attributable to the deferred tax expense created by non-cash increases in the fair value of our commodity derivative instruments, offset by the expected deferred tax benefit. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2013 , Equatorial Guinea – 2011 and Israel – 2015 .

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2017
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 Partners); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); and Other International and Corporate. Other International includes Falkland Islands, Suriname, Newfoundland and new ventures. (millions) Consolidated United States Eastern Mediterranean West Africa Other Int'l & Corporate Three Months Ended March 31, 2017 Revenues from Third Parties $ 994 $ 770 $ 131 $ 93 $ — Income from Equity Method Investees 42 14 — 28 — Total Revenues 1,036 784 131 121 — DD&A 528 463 19 34 12 Gain on Commodity Derivative Instruments (110 ) (102 ) — (8 ) — Income (Loss) Before Income Taxes 59 96 101 66 (204 ) Three Months Ended March 31, 2016 Revenues from Third Parties $ 705 $ 489 $ 126 $ 90 $ — Income from Equity Method Investees 19 16 — 3 — Total Revenues 724 505 126 93 — DD&A 617 530 20 55 12 Gain on Commodity Derivative Instruments (44 ) (37 ) — (7 ) — Income (Loss) Before Income Taxes (453 ) (292 ) 84 9 (254 ) March 31, 2017 Total Assets $ 21,008 $ 16,997 $ 2,391 $ 1,401 $ 219 December 31, 2016 Total Assets 21,011 17,029 2,233 1,479 270

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. 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 also being expended in accordance with schedules established in the Consent Decree. During 2015 and 2016, we spent approximately $54.7 million to undertake injunctive relief at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree. Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and 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 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. 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 Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and /or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Air Compliance Order on Consent In April 2017, 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 compliance testing of certain engines subject to various General Permit 02 conditions and/or individual permit conditions. The COC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. At present, the COC seeks payment of a reduced penalty of $123,500 , of which up to 80% may be mitigated by pursuing a supplemental environment project or projects. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	3 Months Ended
	Mar. 31, 2017
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 (millions) 2017 2016 Production Expense Lease Operating Expense $ 139 $ 161 Production and Ad Valorem Taxes (1) 45 4 Gathering, Transportation and Processing Expense (2) 119 111 Total $ 303 $ 276 Other Operating (Income) Expense, Net Marketing Expense (3) $ 19 $ 18 Gain on Extinguishment of Debt (4) — (80 ) Loss on Asset Due to Terminated Contract (5) 4 42 Other, Net 6 19 Total $ 29 $ (1 ) Other Non-Operating Expense (Income), Net Other Income, Net (1 ) (4 ) Total $ (1 ) $ (4 ) (1) For first quarter 2017 , total production expense increased as compared with 2016 due to higher production taxes associated with higher realized commodity prices, as well as a $28 million US onshore severance tax refund recorded in first quarter 2016 and a $7 million US onshore severance tax charge recorded in first quarter 2017. (2) Certain of our processing expense was historically presented as a component of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect processing expense as a component of production expense. These costs are now included within gathering, transportation and processing expense. For the three month period ended March 31, 2017, these costs totaled $3 million , and the prior year amount of $4 million for the three months ended March 31, 2016 has been reclassified from marketing expense to conform to the current presentation. (3) Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (4) Amount relates to the tendering of senior notes. See Note 6. Debt . (5) Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance.
Balance Sheet Information Table	Balance Sheet Information Other balance sheet information is as follows: (millions) March 31, December 31, Accounts Receivable, Net Commodity Sales $ 362 $ 403 Joint Interest Billings 119 106 Proceeds Receivable (1) — 40 Other 63 86 Allowance for Doubtful Accounts (21 ) (20 ) Total $ 523 $ 615 Other Current Assets Inventories, Materials and Supplies $ 71 $ 71 Inventories, Crude Oil 21 18 Restricted Cash (2) — 30 Prepaid Expenses and Other Current Assets 43 41 Total $ 135 $ 160 Other Noncurrent Assets Investments in Unconsolidated Subsidiaries $ 407 $ 400 Mutual Fund Investments 74 71 Other Assets 54 37 Total $ 535 $ 508 Other Current Liabilities Production and Ad Valorem Taxes $ 116 $ 115 Commodity Derivative Liabilities 23 102 Income Taxes Payable 30 53 Asset Retirement Obligations 160 160 Interest Payable 93 76 Current Portion of Capital Lease Obligations 66 63 Other 110 173 Total $ 598 $ 742 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 215 $ 218 Asset Retirement Obligations 772 775 Production and Ad Valorem Taxes 61 47 Other 44 63 Total $ 1,092 $ 1,103 (1) Balance at December 31, 2016 related to the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017.

Derivative Instruments and He21

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unsettled Derivative Instruments	Unsettled Commodity Derivative Instruments As of March 31, 2017 , 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 1H17 (2) Swaps NYMEX WTI 6,000 $ 55.08 $ — $ — $ — 1H17 (2) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (2) Swaps Dated Brent 3,000 62.80 — — — 2H17 (2) Call Option (1) NYMEX WTI 3,000 — — — 60.12 2H17 (2) Swaptions (3) Dated Brent 3,000 62.80 — — — 2H17 (2) Swaptions (3) NYMEX WTI 3,000 50.05 — — — 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.38 2017 Call Option (1) NYMEX WTI 3,000 — — — 57.00 2017 Swaps NYMEX WTI 4,000 50.90 — — — 2017 Three-Way Collars NYMEX WTI 24,000 — 39.08 47.71 61.20 2017 Three-Way Collars Dated Brent 2,000 — 35.00 45.00 66.33 2017 Three-Way Collars ICE Brent 2,000 — 43.00 50.00 63.15 2018 Three-Way Collars NYMEX WTI 10,000 — 45.50 52.50 69.09 2018 Swaptions (3) NYMEX WTI 3,000 56.10 — — — 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) We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year. (3) 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 March 31, 2017 , 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 1H17 Swaps NYMEX HH 30,000 $ 2.92 $ — $ — $ — 2H17 Swaps NYMEX HH 30,000 3.45 — — — 2H17 Swaptions (1) NYMEX HH 30,000 2.92 — — — 2017 Swaps NYMEX HH 110,000 3.19 — — — 2017 Three-Way Collars NYMEX HH 210,000 — 2.54 2.96 3.62 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 110,000 — 2.50 2.87 3.67 (1) 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 (Gain) Loss on Commodity Derivative Instruments The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments March 31, December 31, March 31, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 6 Current Assets $ — Current Liabilities $ 23 Current Liabilities $ 102 Noncurrent Assets 8 Noncurrent Assets — Noncurrent Liabilities — Noncurrent Liabilities 14 Total $ 14 $ — $ 23 $ 116
Derivative Instruments, (Gain) Loss	The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended (millions) 2017 2016 Cash Paid (Received) in Settlement of Commodity Derivative Instruments Crude Oil $ (5 ) $ (156 ) Natural Gas 2 (22 ) Total Cash Received in Settlement of Commodity Derivative Instruments (3 ) (178 ) Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (63 ) 127 Natural Gas (44 ) 7 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (107 ) 134 Gain on Commodity Derivative Instruments Crude Oil (68 ) (29 ) Natural Gas (42 ) (15 ) Total Gain on Commodity Derivative Instruments $ (110 ) $ (44 )

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2017
Debt [Abstract]
Schedule of debt	Debt consists of the following: March 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — % $ — — % Noble Midstream Services Revolving Credit Facility, due September 20, 2021 — — % — — % Term Loan Facility, due January 6, 2019 550 2.20 % 550 2.01 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — % 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 % 379 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 % 18 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 % 8 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 % Capital Lease and Other Obligations 361 — % 375 — % Total 7,100 7,114 Unamortized Discount (22 ) (23 ) Unamortized Premium 15 17 Unamortized Debt Issuance Costs (32 ) (34 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,061 7,074 Less Amounts Due Within One Year Capital Lease Obligations (66 ) (63 ) Long-Term Debt Due After One Year $ 6,995 $ 7,011

Fair Value Measurements and D23

Fair Value Measurements and Disclosures (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement (millions) March 31, 2017 Financial Assets Mutual Fund Investments $ 74 $ — $ — $ 74 Commodity Derivative Instruments — 23 — (9 ) 14 Financial Liabilities Commodity Derivative Instruments — (32 ) — 9 (23 ) Portion of Deferred Compensation Liability Measured at Fair Value (89 ) — — — (89 ) Stock Based Compensation Liability Measured at Fair Value (10 ) — — — (10 ) December 31, 2016 Financial Assets Mutual Fund Investments $ 71 $ — $ — $ — $ 71 Commodity Derivative Instruments — 5 — (5 ) — Financial Liabilities Commodity Derivative Instruments — (121 ) — 5 (116 ) Portion of Deferred Compensation Liability Measured at Fair Value (88 ) — — — (88 ) Stock Based Compensation Liability Measured at Fair Value (9 ) — — — (9 ) (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	three months ended March 31, 2017
Additional fair value disclosures	Fair value information regarding our debt is as follows: March 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,700 $ 7,200 $ 6,699 $ 7,112 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well 24

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)	3 Months Ended
	Mar. 31, 2017
Capitalized Exploratory Well Costs [Abstract]
Changes in Capitalized Exploratory Well Costs	Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions) Three Months Ended March 31, 2017 Capitalized Exploratory Well Costs, Beginning of Period $ 768 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 6 Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1) (203 ) Capitalized Exploratory Well Costs, End of Period $ 571 (1) Amount relates to the approval and sanction of the first phase of development of the Leviathan field offshore Israel.
Aging of Capitalized Well Costs	The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions) March 31, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 58 $ 69 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1) 513 699 Balance at End of Period $ 571 $ 768
Aging of Exploratory Well Costs

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in ARO are as follows: Three Months Ended (millions) 2017 2016 Asset Retirement Obligations, Beginning Balance $ 935 $ 989 Liabilities Incurred 1 2 Liabilities Settled (9 ) (8 ) Revision of Estimate (7 ) 5 Accretion Expense (1) 12 12 Asset Retirement Obligations, Ending Balance $ 932 $ 1,000 (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)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Schedule of earnings per share	The following table summarizes the calculation of basic and diluted income (loss) per share: Three Months Ended (millions, except per share amounts) 2017 2016 Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy $ 36 $ (287 ) Weighted Average Number of Shares Outstanding, Basic 431 429 Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (1) 3 — Weighted Average Number of Shares Outstanding, Diluted 434 429 Income (Loss) Per Share, Basic $ 0.08 $ (0.67 ) Income (Loss) Per Share, Diluted 0.08 (0.67 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 15 (1) For first quarter 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as the Company 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-dilut

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Provision (Benefit)	The income tax provision (benefit) consists of the following: Three Months Ended (millions) 2017 2016 Current $ 12 $ 20 Deferred — (186 ) Total Income Tax Provision (Benefit) $ 12 $ (166 ) Effective Tax Rate 20.3 % 36.6 %

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Segment Information	(millions) Consolidated United States Eastern Mediterranean West Africa Other Int'l & Corporate Three Months Ended March 31, 2017 Revenues from Third Parties $ 994 $ 770 $ 131 $ 93 $ — Income from Equity Method Investees 42 14 — 28 — Total Revenues 1,036 784 131 121 — DD&A 528 463 19 34 12 Gain on Commodity Derivative Instruments (110 ) (102 ) — (8 ) — Income (Loss) Before Income Taxes 59 96 101 66 (204 ) Three Months Ended March 31, 2016 Revenues from Third Parties $ 705 $ 489 $ 126 $ 90 $ — Income from Equity Method Investees 19 16 — 3 — Total Revenues 724 505 126 93 — DD&A 617 530 20 55 12 Gain on Commodity Derivative Instruments (44 ) (37 ) — (7 ) — Income (Loss) Before Income Taxes (453 ) (292 ) 84 9 (254 ) March 31, 2017 Total Assets $ 21,008 $ 16,997 $ 2,391 $ 1,401 $ 219 December 31, 2016 Total Assets 21,011 17,029 2,233 1,479 270

Basis of Presentation (Details)

Basis of Presentation (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016		Dec. 31, 2016
Oil, NGL and Gas Sales		$ 994	$ 705
Production Expense
Lease Operating Expense		139	161
Production and Ad Valorem Taxes (1)		45	4
Gathering, Transportation and Processing Expense (2)	[1]	119	111
Total		303	276
Other Operating (Income) Expense, Net
Loss on Asset Due to Terminated Contract	[2]	4
Midstream Gathering and Processing (Income) Expense, Net	[3]	19	18
Business combination costs			42
Gain on Extinguishment of Debt		0	(80)	[4]
Other, Net		6	19
Total		29	(1)
Other Non-Operating Expense (Income), Net
Other Income, Net		(1)	(4)
Total		(1)	(4)
Severance tax refunds		7	28
Accounts Receivable, Net
Commodity Sales		362			$ 403
Joint Interest Billings		119			106
Proceeds Receivable	[5]	0			40
Other		63			86
Allowance for Doubtful Accounts		(21)			(20)
Total		523			615
Other Current Assets
Inventories, Materials and Supplies		71			71
Inventories, Crude Oil		21			18
Restricted Cash and Cash Equivalents, Current		0			30
Prepaid Expenses and Other Current Assets		43			41
Total		135			160
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries		407			400
Mutual Fund Investments		74			71
Other Assets		54			37
Total		535			508
Other Current Liabilities
Production and Ad Valorem Taxes		116			115
Derivative Liability, Current		23			102
Income Taxes Payable		30			53
Asset Retirement Obligations		160			160
Interest Payable		93			76
Current Portion of Capital Lease Obligations		66			63
Other		110			173
Total		598			742
Other Noncurrent Liabilities
Deferred Compensation Liabilities		215			218
Asset Retirement Obligations		772			775
Accrual for Taxes Other than Income Taxes		61			47
Other		44			63
Total		$ 1,092			$ 1,103
Percentage of divestiture farmed out		35.00%			35.00%
Scenario, Previously Reported [Member]
Other Operating (Income) Expense, Net
Midstream Gathering and Processing (Income) Expense, Net		$ 3	$ 4
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk1YmYwYzc1YTZjMzRiODlhMjM5ZGQxOWU2MGYxYWI5fFRleHRTZWxlY3Rpb246RUYyRjFEQzc0QTk1NTdGOUEwRDQ1RjlDRTMzNUM1NjAM}
[2]	Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance.
[3]	.
[4]	.
[5]	35%

Clayton Williams Energy Acqui30

Clayton Williams Energy Acquisition (Details) $ / shares in Units, a in Thousands, shares in Millions, $ in Millions	Apr. 24, 2017USD ($)a$ / sharesshares	Mar. 31, 2017USD ($)well
Business Acquisition [Line Items]
Number of Wells Operated by Company | well		4
Consideration		$ 300
Subsequent Event [Member]
Business Acquisition [Line Items]
Stock price ($ per share) | $ / shares	$ 34.17
Subsequent Event [Member] | Clayton Williams Energy
Business Acquisition [Line Items]
Area acquired (acres) | a	118
Shares exchange in acquisition (shares) | shares	55
Consideration	$ 1,900
Cash consideration	665
Consideration	2,600
Credit facility draw	$ 1,300

Divestitures (Details)

Divestitures (Details) $ in Millions		May 01, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)well	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration				$ 300
Proceeds Allocated to Undeveloped Leasehold Cost				$ 246
Percentage of divestiture farmed out				35.00%		35.00%
Sales Proceeds				$ 40	$ 232
Accounts and Other Receivables, Net, Current	[1]			$ 0		$ 40
Number Of Wells | well				7
Number of Wells Operated by Company | well				4
2016 Asset Sales [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds					20
Marcellus Shale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Assets				$ 3,300
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%
Disposal Group, Including Discontinued Operation, Assets					$ 67
Disposal Group, Including Discontinued Operations, Adjustment To Consideration					$ 6
Cyprus Block 12 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received from farm-out agreement				131
Accounts and Other Receivables, Net, Current				$ 40
Subsequent Event [Member] | Marcellus Shale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value		$ 1,200
Sales Proceeds		1,100
Disposal Group, Including Discontinued Operations, Adjustment To Consideration		$ 100
Scenario, Forecast [Member] | Marcellus Shale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets			$ 2,200
[1]	35%

Derivative Instruments and He32

Derivative Instruments and Hedging Activities (Details)	3 Months Ended
	Mar. 31, 2017bbl / dMMBTU / d$ / bbl$ / MMBTU
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 Fixed Price	50.90
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	53.38
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	24,000
Weighted Average Short Put Price	39.08
Weighted Average Floor Price	47.71
Weighted Average Ceiling Price	61.20
Crude Oil Commodity Contract | Swaptions - NYMEX WTI 2018 [Member]
Derivative [Line Items]
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Fixed Price	56.10
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 - ICE Brent 2017 [Member]
Derivative [Line Items]
Index	ICE Brent
Bbls Per Day | bbl / d	2,000
Weighted Average Short Put Price	43
Weighted Average Floor Price	50
Weighted Average Ceiling Price	63.15
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2018 [Member]
Derivative [Line Items]
Settlement Period	2,018
Index	NYMEX WTI
Bbls Per Day | bbl / d	10,000
Weighted Average Short Put Price	45.50
Weighted Average Floor Price	52.50
Weighted Average Ceiling Price	69.09
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 2017 [Member]
Derivative [Line Items]
Settlement Period	2,017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	110,000
Weighted Average Fixed Price | $ / MMBTU	3.19
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	210,000
Weighted Average Short Put Price | $ / MMBTU	2.54
Weighted Average Floor Price | $ / MMBTU	2.96
Weighted Average Ceiling Price | $ / MMBTU	3.62
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	110,000
Weighted Average Short Put Price | $ / MMBTU	2.50
Weighted Average Floor Price | $ / MMBTU	2.87
Weighted Average Ceiling Price | $ / MMBTU	3.67
Second half 2017 [Member] | Crude Oil Commodity Contract | Call - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (2)
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 (2)
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Fixed Price	50.05
Second half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (2)
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Fixed Price	62.80
Second half 2017 [Member] | Crude Oil Commodity Contract | Swaptions - NYMEX WTI 2018 [Member]
Derivative [Line Items]
Settlement Period	2,018
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 Fixed Price | $ / MMBTU	3.45
Second half 2017 [Member] | Natural Gas Commodity Contract | Swaptions - NYMEX HH 2017 [Member] [Member]
Derivative [Line Items]
Settlement Period	2H17
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	2.92
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (2)
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 (2)
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 (2)
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 He33

Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 14		$ 0
Derivative Liability, Fair Value	23		116
Gain on Commodity Derivative Instruments	(110)	$ (44)
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(3)	(178)
Gain on Commodity Derivative Instruments	(107)	134
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value			0
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value			102
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	8		0
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	0		$ 14
Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Gain on Commodity Derivative Instruments	(68)	(29)
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(5)	(156)
Gain on Commodity Derivative Instruments	(63)	127
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Gain on Commodity Derivative Instruments	(42)	(15)
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	2	(22)
Gain on Commodity Derivative Instruments	$ (44)	$ 7

Debt (Details)

Debt (Details) - USD ($)	Jan. 06, 2016	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	[1]	Dec. 31, 2016	Apr. 24, 2017	Feb. 24, 2017	Sep. 20, 2016	Aug. 27, 2015
Debt Instrument [Line Items]
Debt		$ 7,100,000,000	$ 7,114,000,000			$ 7,114,000,000
Unamortized Discount		(22,000,000)	(23,000,000)			(23,000,000)
Debt Instrument, Unamortized Premium		15,000,000	17,000,000			17,000,000
Total Debt, Net of Discount		7,061,000,000	7,074,000,000			7,074,000,000
Capital Lease Obligations, Current		(66,000,000)	(63,000,000)			(63,000,000)
Long-term Debt Due After One Year		6,995,000,000	7,011,000,000			7,011,000,000
Gain on tendered offers		0		$ 80,000,000
Repayments			850,000,000
Leviathan Term Loan
Debt Instrument [Line Items]
Debt		$ 0	$ 0			$ 0
Debt stated rate		0.00%	0.00%			0.00%
Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt		$ 550,000,000	$ 550,000,000			$ 550,000,000
Debt stated rate		2.20%	2.01%			2.01%
Debt instrument, maturity date		Jan. 6, 2019
Maximum borrowing capacity			$ 1,400,000,000			$ 1,400,000,000
Line of Credit
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
Credit facility fee rate basis points, minimum										0.10%
Credit facility fee rate basis points, maximum										0.25%
Credit facility interest rate, Eurodollar rate plus, minimum										0.90%
Credit facility interest rate, Eurodollar rate plus, maximum										1.50%
Noble Midstream Services 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		$ 361,000,000	$ 375,000,000			$ 375,000,000
Debt stated rate		0.00%	0.00%			0.00%
Capital Lease Obligations, Current		$ (66,000,000)	$ (63,000,000)			$ (63,000,000)
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			$ 379,000,000
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			$ 18,000,000
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		$ (32,000,000)	$ (34,000,000)			$ (34,000,000)
5.875% Senior Notes, due June 1, 2024
Debt Instrument [Line Items]
Debt		$ 8,000,000	$ 8,000,000			$ 8,000,000
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
Line of Credit | Term Loan Facility [Member]
Debt Instrument [Line Items]
Proceeds from Lines of Credit						$ 1,380,000,000
Debt Instrument, Term	3 years
Line of Credit | 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%
Line of Credit | Federal Funds Effective Swap Rate [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate	0.50%
Line of Credit | London Interbank Offered Rate (LIBOR) [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate	1.00%
Line of Credit | 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] | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Gain on tendered offers						$ 80,000,000
Noble Midstream | Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity									$ 350,000,000
Noble Midstream | Line of Credit | Federal Funds Effective Swap Rate [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate						0.50%
Noble Midstream | Line of Credit | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate						1.00%
Line of Credit | Leviathan Term Loan
Debt Instrument [Line Items]
Maximum borrowing capacity								$ 1,000,000,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		1.00%
Long-term Line of Credit		$ 625,000,000
Line of Credit Facility, Maximum Final Balloon Payment Allowable as of Loans Outstanding		35.00%
Line of Credit | LIBOR Prior to Production Startup [Member] | Leviathan Term Loan
Debt Instrument [Line Items]
Debt instrument, variable rate		3.50%
Line of Credit | LIBOR After Startup Prior to Two Years Before Maturity [Member] | Leviathan Term Loan
Debt Instrument [Line Items]
Debt instrument, variable rate		3.25%
Line of Credit | LIBOR Last Two years Until Maturity [Member] | Leviathan Term Loan
Debt Instrument [Line Items]
Debt instrument, variable rate		3.75%
Clayton Williams Energy | Subsequent Event [Member]
Debt Instrument [Line Items]
Long-term Line of Credit							$ 1,300,000,000
[1]	.

Fair Value Measurements and D35

Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Financial Assets [Abstract]
Mutual Fund Investments		$ 74	$ 71
Commodity Derivative Instruments		14	0
Financial Liabilities [Abstract]
Commodity Derivative Instruments		(23)	(116)
Portion of Deferred Compensation Liability Measured at Fair Value		(89)	(88)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability		(10)	(9)
Quoted Prices in Active Markets (Level 1)
Financial Assets [Abstract]
Mutual Fund Investments	[1]	74	71
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]	(89)	(88)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability		(10)	(9)
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	0
Significant Other Observable Inputs (Level 2)
Financial Assets [Abstract]
Mutual Fund Investments	[3]		0
Commodity Derivative Instruments	[3]	23	5
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[3]	(32)	(121)
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	0
Scenario, Adjustment [Member]
Financial Assets [Abstract]
Mutual Fund Investments	[4]	0	0
Commodity Derivative Instruments	[4]	(9)	(5)
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[4]	9	5
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	$ 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 D36

Fair Value Measurements and Disclosures (Details 3) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	[1]	$ 6,700	$ 6,699
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]	$ 7,200	$ 7,112
[1]	(1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Capitalized Exploratory Well 37

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized Exploratory Well Costs, Beginning of Period	$ 768
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	6
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1)	(203)
Capitalized Exploratory Well Costs, End of Period	571
Exploratory Well Costs Capitalized for a Period of One Year or Less		$ 58	$ 69
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1)		513	699
Capitalized Exploratory Well Costs, End of Period	768	$ 571	$ 768
Percentage of divestiture farmed out		35.00%	35.00%
Capitalized undeveloped leasehold cost	2,300
Onshore US [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost	2,200
International [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost	52
Deepwater Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost	86
Gulf of Mexico and Falkland Island [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost	$ 18

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance		$ 935	$ 989
Liabilities Incurred		1	2
Liabilities Settled		(9)	(8)
Revision of Estimate		(7)	5
Accretion Expense	[1]	12	12
Asset Retirement Obligations, Ending Balance		932	1,000
EQUATORIAL GUINEA
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate			$ 5
Deepwater Gulf of Mexico [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate		$ 7
[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, shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net Income (Loss) Attributable to Parent		$ 36	$ (287)
Weighted Average, Number of Shares Outstanding, Basic (in shares)	[1]	431	429
Weighted Average Number Diluted Shares Outstanding Adjustment	[2]	3	0
Weighted Average, Number of Shares Outstanding, Diluted (in shares)	[2]	434	429
Earnings (Loss) from Continuing Operations Per Share, Basic (in dollars per share)		$ 0.08	$ (0.67)
Earnings (Loss) from Continuing Operations Per Share, Diluted (in dollars per share)		$ 0.08	$ (0.67)
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above (in shares)		14	15
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk1YmYwYzc1YTZjMzRiODlhMjM5ZGQxOWU2MGYxYWI5fFRleHRTZWxlY3Rpb246RkI3RUI3MTE2OEVENTI4N0FGQ0IxQUNENjZBNjVDOTAM}
[2]	For first quarter 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as the Company 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-dilut

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Examination [Line Items]
Current	$ 12	$ 20
Deferred		(186)
Total Income Tax Provision (Benefit)	$ 12	$ (166)
Effective Tax Rate	20.30%	36.60%
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	2,015

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenues from Third Parties	$ 994	$ 705
Income from Equity Method Investees	42	19
Total Revenues	1,036	724
DD&A	528	617
Gain on Commodity Derivative Instruments	(110)	(44)
Income (Loss) Before Income Taxes	59	(453)
Total Assets	21,008		$ 21,011
United States [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	770	489
Income from Equity Method Investees	14	16
Total Revenues	784	505
DD&A	463	530
Gain on Commodity Derivative Instruments	(102)	(37)
Income (Loss) Before Income Taxes	96	(292)
Total Assets	16,997		17,029
West Africa [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	93	90
Income from Equity Method Investees	28	3
Total Revenues	121	93
DD&A	34	55
Gain on Commodity Derivative Instruments	(8)	(7)
Income (Loss) Before Income Taxes	66	9
Total Assets	1,401		1,479
Eastern Mediterranean [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	131	126
Income from Equity Method Investees	0	0
Total Revenues	131	126
DD&A	19	20
Gain on Commodity Derivative Instruments	0	0
Income (Loss) Before Income Taxes	101	84
Total Assets	2,391		2,233
Other Int'l & Corporate [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	0	0
Income from Equity Method Investees	0	0
Total Revenues	0	0
DD&A	12	12
Gain on Commodity Derivative Instruments	0	0
Income (Loss) Before Income Taxes	(204)	$ (254)
Total Assets	$ 219		$ 270

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	24 Months Ended
	Apr. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Consent Decree [Member]
Other Commitments [Line Items]
Civil penalty		$ 4,950	$ 54,700
Mitigation projects		4,500
Supplemental environmental projects		$ 4,000
Subsequent Event [Member]
Other Commitments [Line Items]
Reduced penalty	$ 124
Maximum penalty reduction	80.00%