Noble Energy (NBL) 10-K 20 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2017
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 Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 13.8
Entity Common Stock, Shares Outstanding	486,902,907
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Oil, Gas and NGL Sales	$ 4,060	$ 3,389	$ 3,093
Income from Equity Method Investees and Other	196	102	90
Total Revenues	4,256	3,491	3,183
Costs and Expenses
Production Expense	1,141	1,100	996
Exploration Expense	188	925	488
Depreciation, Depletion and Amortization	2,053	2,454	2,131
General and Administrative	415	399	396
Loss on Marcellus Shale Upstream Divestiture	2,379	0	0
Asset Impairments	70	92	533
Goodwill Impairment	0	0	779
Other Operating (Income) Expense, Net	(188)	(103)	332
Total Operating Expenses	6,058	4,867	5,655
Operating Loss	(1,802)	(1,376)	(2,472)
Other Expense (Income)
(Gain) Loss on Commodity Derivative Instruments	(63)	139	(501)
Loss (Gain) on Extinguishment of Debt	98	(80)	0
Interest, Net of Amount Capitalized	354	328	263
Other Non-Operating Expense (Income), Net	0	9	(15)
Total Other Expense (Income)	389	396	(253)
Loss Before Income Taxes	(2,191)	(1,772)	(2,219)
Income Tax (Benefit) Provision	(1,141)	(787)	222
Net Loss Including Noncontrolling Interests	(1,050)	(985)	(2,441)
Less: Net Income Attributable to Noncontrolling Interests	68	13	0
Net Loss Attributable to Noble Energy	$ (1,118)	$ (998)	$ (2,441)
Net Loss Attributable to Noble Energy per Share of Common Stock
Basic and Diluted (in dollars per share)	$ (2.38)	$ (2.32)	$ (6.07)
Weighted Average Number of Shares Outstanding
Basic and Diluted (in shares)	469	430	402

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Loss Including Noncontrolling Interests	$ (1,050)	$ (985)	$ (2,441)
Other Items of Comprehensive Loss
Net Change in Mutual Fund Investment	0	0	(11)
Less Tax Expense	0	0	4
Net Change in Pension and Other	3	3	99
Less Tax Benefit	(1)	(1)	(35)
Other Comprehensive Income	2	2	57
Comprehensive Loss Including Noncontrolling Interests	(1,048)	(983)	(2,384)
Less: Comprehensive Income Attributable to Noncontrolling Interests	68	13	0
Comprehensive Loss Attributable to Noble Energy	$ (1,116)	$ (996)	$ (2,384)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	$ 675	$ 1,180
Accounts Receivable, Net	748	615
Other Current Assets	780	160
Total Current Assets	2,203	1,955
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	29,678	30,355
Property, Plant and Equipment, Other	879	909
Total Property, Plant and Equipment, Gross	30,557	31,264
Accumulated Depreciation, Depletion and Amortization	(13,055)	(12,716)
Total Property, Plant and Equipment, Net	17,502	18,548
Goodwill	1,310	0
Other Noncurrent Assets	461	508
Total Assets	21,476	21,011
Current Liabilities
Accounts Payable - Trade	1,161	736
Other Current Liabilities	578	742
Total Current Liabilities	1,739	1,478
Long-Term Debt	6,746	7,011
Net Deferred Income Tax Liability	1,127	1,819
Other Noncurrent Liabilities	1,245	1,103
Total Liabilities	10,857	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; 1 Billion Shares Authorized; 529 Million and 471 Million Shares Issued, Respectively	5	5
Additional Paid in Capital	8,438	6,450
Accumulated Other Comprehensive Loss	(30)	(31)
Treasury Stock, at Cost; 39 Million and 38 Million Shares, Respectively	(725)	(692)
Retained Earnings	2,248	3,556
Noble Energy Share of Equity	9,936	9,288
Noncontrolling Interests	683	312
Total Equity	10,619	9,600
Total Liabilities and Equity	$ 21,476	$ 21,011

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 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)	528,743,381	471,360,427
Treasury Stock (in shares)	38,786,969	37,961,316

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows From Operating Activities
Net Loss Including Noncontrolling Interests	$ (1,050)	$ (985)	$ (2,441)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	2,053	2,454	2,131
Asset Impairments	70	92	533
Loss on Marcellus Shale Upstream Divestiture	2,379	0	0
Goodwill Impairment	0	0	779
Dry Hole Cost	9	579	266
Deferred Income Taxes	(1,227)	(984)	116
(Gain) Loss on Commodity Derivative Instruments	(63)	139	(501)
Net Cash Received in Settlement of Commodity Derivative Instruments	13	569	1,009
Gain on Divestitures	(326)	(238)	0
Stock Based Compensation	104	77	86
Non-cash Pension Plan Termination Expense	0	0	82
Loss (Gain) on Debt Extinguishment	98	(80)	0
Undeveloped Leasehold Impairment	62	93	21
Expiration and Amortization of Undeveloped Leaseholds	0	55	92
Other Adjustments for Noncash Items Included in Income	(21)	40	18
Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed
(Increase) Decrease in Accounts Receivable	(171)	(164)	453
Increase (Decrease) in Accounts Payable	248	(111)	(364)
(Decrease) Increase in Current Income Taxes Payable	(36)	(32)	(94)
(Decrease) Increase in Other Current Liabilities	(101)	(63)	(70)
Other Operating Assets and Liabilities, Net	(90)	(90)	(54)
Net Cash Provided by Operating Activities	1,951	1,351	2,062
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(2,649)	(1,541)	(2,979)
Proceeds from Divestitures	2,073	1,241	151
Clayton Williams Energy Acquisition, Net of Cash Received	(616)	0	0
Other Acquisitions	(327)	0	0
Marcellus Shale Acreage Exchange Consideration	0	(213)	0
Other	(87)	82	(43)
Net Cash Used in Investing Activities	(1,606)	(431)	(2,871)
Cash Flows From Financing Activities
Dividends Paid, Common Stock	(190)	(172)	(291)
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs	0	0	1,112
Proceeds from Revolving Credit Facility	1,585	0	0
Repayment of Revolving Credit Facility	(1,355)	0	(70)
Repayment of Clayton Williams Energy Long-term Debt	(595)	0	0
Proceeds from Term Loan Facility	0	1,400	0
Repayment of Term Loan Facility	(550)	(850)	0
Proceeds from Issuance of Senior Notes, Net	1,086	0	0
Repayment of Senior Notes	(1,114)	(1,383)	(12)
Proceeds from Noble Midstream Services Revolving Credit Facility	325	0	0
Repayment of Noble Midstream Services Revolving Credit Facility	(240)	0	0
Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs	312	299	0
Other	(114)	(62)	(85)
Net Cash (Used in) Provided By Financing Activities	(850)	(768)	654
(Decrease) Increase in Cash and Cash Equivalents	(505)	152	(155)
Cash and Cash Equivalents at Beginning of Period	1,180	1,028	1,183
Cash and Cash Equivalents at End of Period	$ 675	$ 1,180	$ 1,028

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	Non-controlling Interests
Shareholders Equity, Beginning Balance at Dec. 31, 2014	$ 10,325	$ 4	$ 3,624	$ (90)	$ (671)	$ 7,458	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(2,441)					(2,441)
Merger and Acquisition	1,529	1	1,528
Stock-based Compensation	86		86
Exercise of Stock Options	8		8
Dividends	(291)					(291)
Issuance of Stock, Net of Offering Costs	1,112		1,112
Net Change in Other	42		2	57	(17)
Shareholders Equity, Ending Balance at Dec. 31, 2015	10,370	5	6,360	(33)	(688)	4,726	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(985)					(998)	13
Stock-based Compensation	68		68
Exercise of Stock Options	24		24
Dividends	(172)					(172)
Issuance of Stock, Net of Offering Costs	299						299
Net Change in Other	(4)		(2)	2	(4)
Shareholders Equity, Ending Balance at Dec. 31, 2016	9,600	5	6,450	(31)	(692)	3,556	312
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(1,050)					(1,118)	68
Merger and Acquisition	1,851		1,876		(25)
Stock-based Compensation	100		100
Exercise of Stock Options	10		10
Dividends	(190)					(190)
Issuance of Stock, Net of Offering Costs	312						312
Distributions to Noncontrolling Interest Owners	(28)						(28)
Net Change in Other	14		2	1	(8)		19
Shareholders Equity, Ending Balance at Dec. 31, 2017	$ 10,619	$ 5	$ 8,438	$ (30)	$ (725)	$ 2,248	$ 683

Consolidated Statements of Sha8

Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.4	$ 0.4	$ 0.72

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 1. Summary of Significant Accounting Policies General 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 historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico; Eastern Mediterranean; and West Africa. Our Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider an essential component of our business and a necessary and integral element to our value chain involving the monetization of natural gas. With our partners, we engage in joint strategic operational and financial decision making for these entities. In order to reflect the economics associated with our integrated upstream value chain described above, we include income from equity method investees as a component of revenues in our consolidated statements of operations. We carry equity method investments at our share of net assets of the equity investees plus loans and advances, and include the investments in other noncurrent assets in our consolidated balance sheets. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations. See Note 7. Equity Method Investments . Noncontrolling Interests In third quarter 2016, Noble Midstream Partners LP (Noble Midstream Partners), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners. See Note 16. Additional Shareholders' Equity Information. 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 variable interest entity (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. Use of 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. Estimated quantities of crude oil, natural gas and NGL reserves are the most significant of our estimates. All the reserves data included in this Annual Report Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President – Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited) . Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill, exit costs and asset retirement obligations (AROs), valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in commodity prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. See Supplemental Oil and Gas Information (Unaudited) . Reclassifications In Note 14. Segment Information , we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation. Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows: • Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. • 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. • Level 3 measurements are fair value measurements which use unobservable inputs. The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 13. Fair Value Measurements and Disclosures . Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of cost or net realizable value. The cost of crude oil inventory includes production costs and DD&A of oil and gas properties. See Note 2. Additional Financial Statement Information . Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Costs related to repair and maintenance activities are expensed as incurred. Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above. We recorded property impairment charges in 2017 , 2016 and 2015 and it is possible that other proved oil and gas properties could become impaired in the future due to commodity price declines and/or field performance. See Note 5. Asset Impairments . Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method over an average holding period. We recorded undeveloped leasehold impairment expense in 2017 . It is possible that unproved oil and gas properties, including undeveloped leases, could become impaired in the future if commodity prices decline or if there are changes in exploration plans or the timing and extent of development activities. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. Assets Held for Sale We occasionally market oil and gas properties for sale. At the end of each reporting period, we evaluate properties being marketed to determine whether any should be reclassified as held for sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale in our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See Note 4. Acquisitions, Divestitures and Merger . Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as buildings and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from three to thirty years. Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment. Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average rate we pay on long-term debt, including our unsecured revolving credit facility (Revolving Credit Facility) and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $49 million in 2017 , $84 million in 2016 , and $144 million in 2015 . Asset Retirement Obligations AROs consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in DD&A expense in the consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability, and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 9. Asset Retirement Obligations . Goodwill 2017 Goodwill As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion . This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit, a component of our US reportable and operating segment. See Note 3. Clayton Williams Energy Acquisition . Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for recently issued accounting guidance regarding future goodwill impairment testing. We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill. Certain negative indicators as of September 30 2017 included the current onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as the current commodity price environment, our current and future drilling and development plans for the Texas assets and synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties, which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability. Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware Basin. Having assessed the totality of such events and circumstances described above, we determined that, while there existed certain negative factors, the overall qualitative assessment did not indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless of the outcome of the qualitative review, we decided to proceed with Step 1 of the impairment test as part of our annual review. As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, and therefore, the Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017. If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. 2015 Goodwill At December 31, 2015, we reviewed our goodwill balance of $779 million for impairment in accordance with our accounting policy and identified factors, including continuing declines in commodity prices and the market value of our common stock, indicating that the fair value of goodwill could have fallen below its book value. We determined that the goodwill was fully impaired and recognized a loss of $779 million . This goodwill related primarily to the excess purchase price over amounts assigned to assets acquired and liabilities assumed in the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger) in 2015 and the Patina Merger in 2005 and was associated with our US reporting unit. During 2015, prior to the impairment, goodwill increased $163 million due to the Rosetta Merger and decreased $4 million due to allocations of goodwill to US onshore properties sold. For purposes of determining the 2015 goodwill impairment, we estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The analysis supported that the implied fair value of goodwill was zero and, as such, goodwill was fully impaired. Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Accrued exit costs at December 31, 2017 relate primarily to estimated costs associated with retained Marcellus Shale firm transportation contracts. The recognition and fair value estimation of an exit cost liability require that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 17. Commitments and Contingencies . Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows include the non-cash portion of gain and loss on commodity derivative instruments, which represents the difference between the total gain and loss on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during the period. We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master agreement with netting clauses. Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. In 2016, we issued cash-settled awards to certain employees in lieu of a portion of restricted stock and stock options. We recognize the value of cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation – Stock Compensation . The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 12. Stock-Based and Other Compensation Plans . Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to accumulated other comprehensive loss (AOCL), net of tax. The amount remaining in AOCL at December 31, 2017 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and actuarial losses relating to the pension plan from AOCL to earnings. Income Taxes and Impact of Tax Reform Legislation Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law affecting us. See Note 11. Income Taxes . Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured. Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 17. Commitments and Contingencies . We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss. Foreign Currency The US dollar is considered the functional currency for each of our

Additional Financial Statement

Additional Financial Statement Information	12 Months Ended
	Dec. 31, 2017
Additional Financial Statement Information [Abstract]
Additional Financial Statement Information	Note 2. Additional Financial Statement Information Additional statements of operations information is as follows: Year Ended December 31, (millions) 2017 2016 2015 Production Expense Lease Operating Expense $ 571 $ 542 $ 563 Production and Ad Valorem Taxes 138 78 127 Gathering, Transportation and Processing Expense (1) 432 480 306 Total $ 1,141 $ 1,100 $ 996 Exploration Expense Leasehold Impairment and Amortization (2) $ 62 $ 148 $ 113 Dry Hole Cost 9 579 266 Seismic, Geological and Geophysical 27 76 34 Staff Expense 55 77 43 Other 35 45 32 Total $ 188 $ 925 $ 488 Loss on Marcellus Shale Upstream Divestiture Loss on Sale $ 2,270 $ — $ — Firm Transportation Commitment (2) 93 — — Other (3) 16 — — Total $ 2,379 $ — $ — Other Operating (Income) Expense, Net Marketing Expense (4) $ 47 $ 58 $ 33 Clayton Williams Acquisition Expenses (5) 100 — — Corporate Restructuring Expense (6) — 8 51 Pension Plan Expense (7) — — 88 Impact of Rosetta Merger (8) — (25 ) 81 North Sea Remediation Project Revision (9) (42 ) — — Loss on Asset Due to Terminated Contract (10) — 41 — Gain on Divestitures, Net (11) (326 ) (238 ) — Other, Net 33 53 79 Total $ (188 ) $ (103 ) $ 332 (1) Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense.For the years ended December 31, 2016 and 2015, these costs totaled $17 million and $17 million , respectively, and have been reclassified from other operating expense, net to conform to current presentation. (2) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (3) Expense relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 17. Commitments and Contingencies . (4) Amount includes costs for legal and advisory services and employee severance charges. (5) Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (6) See Note 3. Clayton Williams Energy Acquisition . (7) Expenses are associated with corporate organizational activities. (8) Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss). (9) Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 4. Acquisitions, Divestitures and Merger . (10) See Note 9. Asset Retirement Obligations . (11) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. (12) See Note 4. Acquisitions, Divestitures and Merger . Additional balance sheet information is as follows: December 31, (millions) 2017 2016 Accounts Receivable, Net Commodity Sales $ 455 $ 403 Joint Interest Billings 207 106 Proceeds Receivable (1) — 40 Other 103 86 Allowance for Doubtful Accounts (17 ) (20 ) Total $ 748 $ 615 Other Current Assets Inventories, Materials and Supplies $ 66 $ 71 Inventories, Crude Oil 16 18 Assets Held for Sale (2) 629 18 Restricted Cash (3) 38 30 Prepaid Expenses and Other Assets, Current 31 23 Total $ 780 $ 160 Other Noncurrent Assets Equity Method Investments $ 305 $ 400 Mutual Fund Investments 57 71 Net Deferred Income Tax Asset 25 — Other Assets, Noncurrent 74 37 Total $ 461 $ 508 Other Current Liabilities Production and Ad Valorem Taxes $ 84 $ 115 Commodity Derivative Liabilities, Current 58 102 Income Taxes Payable 18 53 Asset Retirement Obligations, Current 51 160 Interest Payable 67 76 Compensation and Benefits Payable 98 110 Current Portion of Capital Lease and Other Obligations 61 63 Other Liabilities, Current 141 63 Total $ 578 $ 742 Other Noncurrent Liabilities Deferred Compensation Liabilities, Noncurrent $ 197 $ 218 Asset Retirement Obligations, Noncurrent 824 775 Production and Ad Valorem Taxes 69 47 Marcellus Firm Transportation Commitment, Noncurrent (4) 76 — Other Liabilities, Noncurrent 79 63 Total $ 1,245 $ 1,103 (1) Proceeds relate to the farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 4. Acquisitions, Divestitures and Merger . (2) Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar and Dalit fields, offshore Israel, certain non-strategic assets acquired in the Clayton Williams Energy Acquisition and the CONE investments. Assets held for sale at December 31, 2016 include assets in the Greeley Crescent area of the DJ Basin. See Note 4. Acquisitions, Divestitures and Merger . (3) Balance at December 31, 2017 represents amount held in escrow for the purchase of a midstream entity. Balance at December 31, 2016 represents amount held in escrow for the purchase of certain Delaware Basin properties. See Note 4. Acquisitions, Divestitures and Merger . (4) Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 4. Acquisitions, Divestitures and Merger . Supplemental statements of cash flow information is as follows: Year Ended December 31, (millions) 2017 2016 2015 Cash Paid During the Year For Interest, Net of Amount Capitalized $ 346 $ 327 $ 260 Income Taxes Paid, Net 121 236 202 Non-Cash Financing and Investing Activities Increase in Capital Lease and Other Obligations — 5 55

Clayton Williams Energy Acquisi

Clayton Williams Energy Acquisition (Notes)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Clayton Williams Energy Acquisition	Note 3. Clayton Williams Energy Acquisition In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholders and closed on April 24, 2017 . Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the United States. In total, the acquisition increased our Delaware Basin position to approximately 117,000 net acres. See Supplemental Oil and Gas Information (Unaudited) , below for discussion of proved reserves acquired. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering. The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million , for total consideration of approximately $2.5 billion , in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange (NYSE) 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 Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 10. Long-Term Debt . In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of $100 million to date, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted stock and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance. Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis of 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 value of the assets and liabilities, including any goodwill, may be revised as appropriate. The following table sets forth our preliminary purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,876 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,513 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 509 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,817 The fair values of Clayton Williams Energy's identifiable assets are as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 70 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Cost 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 63 Other Property Plant and Equipment 12 Implied Goodwill 1,310 Total Asset Value $ 3,817 In connection with the acquisition, we assumed, and then subsequently retired, all of Clayton Williams Energy's long-term debt at a cost to us of $595 million . The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs. The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook. The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering, processing and servicing of future production in the basin. Results of Operations The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017 . We generated revenues of $99 million and a pre-tax loss of $19 million from the Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017. Pro Forma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2017 were adjusted to exclude acquisition-related costs of $100 million incurred by Noble Energy and $23 million incurred by Clayton Williams Energy. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. Year Ended December 31, (millions, except per share amounts) 2017 2016 Revenues $ 4,304 $ 3,651 Net Loss and Comprehensive Loss Attributable to Noble Energy (678 ) (1,082 ) Net Loss Attributable to Noble Energy per Common Share Basic and Diluted $ (1.39 ) $ (2.23 ) Note 4. Acquisitions, Divestitures and Merger We maintain an ongoing portfolio management program and have engaged in various transactions over recent years. Year Ended December 31, 2017 Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion , and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. To date, conditions for the recognition of the contingent consideration are not probable and, therefore, no amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 10. Long-Term Debt . For the year ended December 31, 2017, we recognized a total loss of $2.4 billion , or $1.5 billion after-tax, on this divestiture. The aggregate net book value of the properties sold was approximately $3.4 billion , which included approximately $883 million of undeveloped leasehold cost. As part of the loss, we accrued non-cash exit costs of $41 million , discounted, relating to a retained transportation contract that is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. In addition, we recorded a $52 million accrual, discounted, relating to future commitments to a third party who assumed a portion of our retained capacity relating to other pipeline projects. Both charges are included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations in accordance with accounting for exit or disposal activities under ASC 420 – Exit or Disposal Cost Obligations. Other retained Marcellus Shale firm transportation contracts relate to pipeline projects that are not yet commercially available to us. These projects that are not yet available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we will incur additional firm transportation costs associated with this exit activity in the future. See Note 2. Additional Financial Statement Information and Note 17. Commitments and Contingencies . Production from the Marcellus Shale upstream assets represented 204 MMcfe/d of total consolidated sales volumes for the year ended December 31, 2017. See Supplemental Oil and Gas Information (Unaudited) , below for discussion of reserves divested. Divestiture of 7.5% Interest in Tamar and Dalit Fields The terms of the Israel Natural Gas Framework (Framework) require us to reduce our current ownership interest in the Tamar and Dalit fields from 32.5% to 25% by year-end 2021. On January 29, 2018, we signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd. (TASE: TMRP) (Tamar Petroleum) for cash proceeds of approximately $560 million and 38.5 million shares of Tamar Petroleum. Closing of the transaction is expected by the end of first quarter 2018, subject to satisfactory conclusion of Tamar Petroleum's debt financing and customary approvals, terms and conditions. As of December 31, 2017, the net book value of the 7.5% interest, $293 million , was included in assets held for sale. Divestiture of Southwest Royalties In January 2018, we signed an agreement to sell our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, and acquired as part of Clayton Williams Energy Acquisition. We received proceeds of $60 million on sale of these assets. As of December 31, 2017, the asset value of these properties of $102 million and associated asset retirement obligation of $42 million were included in assets and liabilities held for sale. Other US Onshore Transactions We conducted the following additional transactions in 2017: • US Onshore Divestitures During 2017, we received total proceeds of $671 million resulting from the sale of certain US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ Basin operated properties, in the amount of approximately $40 million , is expected to occur in mid-2018. • Sale of Mineral and Royalty Assets We received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota. • Delaware Basin Acquisition In January 2017, we completed the acquisition of Delaware Basin properties, including seven producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration totaled $301 million , approximately $246 million of which was allocated to undeveloped leasehold cost. Initial consideration of $30 million was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset in our consolidated balance sheet as of December 31, 2016. Marcellus Shale CONE Gathering Divestiture In December 2017, we signed an agreement to sell our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale. At December 31, 2017 , our total investment of $181 million in the CONE entities was included in assets held for sale. We closed the sale in January 2018, receiving proceeds of $308 million in cash and utilized proceeds to pay down borrowings under the Revolving Credit Facility. We now hold 21.7 million common units representing a 33.5% limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million . Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million . Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area. The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand. Noble Midstream Partners Advantage Joint Venture On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50 /50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed approximately $67 million of cash to the Advantage Joint Venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. See Note 7. Equity Method Investments . Noble Midstream Partners serves as operator of the Advantage Pipeline System, which includes a 70 -mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of shipping capacity and 490 MBbls of storage capacity. Noble Midstream Partners Black Diamond Gathering In December 2017, Noble Midstream Partners and Greenfield Midstream, LLC, a portfolio company of EnCap Flatrock Midstream Gathering, formed an entity, Black Diamond Gathering, LLC (Black Diamond Gathering). Black Diamond Gathering subsequently entered into definitive agreements to acquire Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). The Saddle Butte purchase closed on January 31, 2018, for total cash consideration of approximately $638.5 million . Noble Midstream Partners funded its share of the purchase price with proceeds from its December 2017 common unit offering, cash on hand and borrowings under its unsecured revolving credit facility. See Note 10. Long-Term Debt . Noble Midstream partners received a 54.4% ownership interest in Black Diamond. Noble Midstream Partners fully consolidates the assets and liabilities of Black Diamond Gathering. Noble Midstream Partners will serve as operator of Saddle Butte assets which include a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation, 300 MBbls per day of delivery capacity and approximately 210 MBbls of crude oil storage capacity. Saddle Butte has approximately 141,000 dedicated acres from six customers under fixed fee arrangements. Subsequent Event - Gulf of Mexico Divestiture On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico for cash consideration of $480 million . As part of the transaction, the buyer will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million . We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1, 2018. Year Ended December 31, 2016 Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL Energy Inc. (CONSOL) agreed to terminate our 50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange. DJ Basin Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No gain or loss was recognized. 2016 Divestitures During 2016, we engaged in the following sales transactions: • entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net acres in the DJ Basin for proceeds of $505 million . We closed the sale on a portion of the properties in 2016, receiving proceeds of $486 million , with the remainder of the sale closing in 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss; • sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller US onshore properties, generating total net proceeds of $152 million , a net loss of $23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions; • sold our 47% interest in the Alon A and Alon C licenses, which included the Karish and Tanin fields, offshore Israel, for a total sales price of $73 million ( $67 million for asset consideration and $6 million from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss; • sold a 3.5% working interest in the Tamar and Dalit fields, offshore Israel, in compliance with the terms of the Framework, which requires us to reduce our ownership interest in the fields to 25% by year-end 2021. The sales price totaled $431 million , and we received net cash proceeds of $316 million , after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the fields basis and resulted in the recognition of a $261 million gain; and • received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. We received the remaining proceeds of $40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss. Year Ended December 31, 2015 2015 Divestitures In 2015, we sold certain non-strategic US onshore properties, receiving proceeds of $151 million , with no gain or loss recorded. Rosetta Merger On July 20, 2015, Noble Energy completed the Rosetta Merger. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new US onshore shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Delaware Basin ( 45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $81 million , including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and are included in other operating (income) expense, net. Purchase Price Allocation The merger was accounted for as a business combination, using the acquisition method. The allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed was based on the fair values at the merger date, with the excess of the purchase price over the fair values of the identifiable net assets acquired recorded as goodwill. Results of Operations The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $457 million and pre-tax net loss of $20 million , exclusive of a $25 million purchase price allocation adjustment, from Rosetta were generated for the year ended December 31, 2016. Revenues of $181 million and pre-tax net loss of $120 million , inclusive of a $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015. See Supplemental Oil and Gas Information (Unaudited) , below, for discussion of proved reserves added or divested in connection with the above transactions.

Acquisitions, Divestitures and

Acquisitions, Divestitures and Merger	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions, Divestitures and Merger	Note 3. Clayton Williams Energy Acquisition In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholders and closed on April 24, 2017 . Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the United States. In total, the acquisition increased our Delaware Basin position to approximately 117,000 net acres. See Supplemental Oil and Gas Information (Unaudited) , below for discussion of proved reserves acquired. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering. The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million , for total consideration of approximately $2.5 billion , in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange (NYSE) 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 Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 10. Long-Term Debt . In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of $100 million to date, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted stock and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance. Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis of 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 value of the assets and liabilities, including any goodwill, may be revised as appropriate. The following table sets forth our preliminary purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,876 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,513 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 509 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,817 The fair values of Clayton Williams Energy's identifiable assets are as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 70 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Cost 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 63 Other Property Plant and Equipment 12 Implied Goodwill 1,310 Total Asset Value $ 3,817 In connection with the acquisition, we assumed, and then subsequently retired, all of Clayton Williams Energy's long-term debt at a cost to us of $595 million . The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs. The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook. The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering, processing and servicing of future production in the basin. Results of Operations The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017 . We generated revenues of $99 million and a pre-tax loss of $19 million from the Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017. Pro Forma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2017 were adjusted to exclude acquisition-related costs of $100 million incurred by Noble Energy and $23 million incurred by Clayton Williams Energy. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. Year Ended December 31, (millions, except per share amounts) 2017 2016 Revenues $ 4,304 $ 3,651 Net Loss and Comprehensive Loss Attributable to Noble Energy (678 ) (1,082 ) Net Loss Attributable to Noble Energy per Common Share Basic and Diluted $ (1.39 ) $ (2.23 ) Note 4. Acquisitions, Divestitures and Merger We maintain an ongoing portfolio management program and have engaged in various transactions over recent years. Year Ended December 31, 2017 Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion , and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. To date, conditions for the recognition of the contingent consideration are not probable and, therefore, no amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 10. Long-Term Debt . For the year ended December 31, 2017, we recognized a total loss of $2.4 billion , or $1.5 billion after-tax, on this divestiture. The aggregate net book value of the properties sold was approximately $3.4 billion , which included approximately $883 million of undeveloped leasehold cost. As part of the loss, we accrued non-cash exit costs of $41 million , discounted, relating to a retained transportation contract that is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. In addition, we recorded a $52 million accrual, discounted, relating to future commitments to a third party who assumed a portion of our retained capacity relating to other pipeline projects. Both charges are included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations in accordance with accounting for exit or disposal activities under ASC 420 – Exit or Disposal Cost Obligations. Other retained Marcellus Shale firm transportation contracts relate to pipeline projects that are not yet commercially available to us. These projects that are not yet available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we will incur additional firm transportation costs associated with this exit activity in the future. See Note 2. Additional Financial Statement Information and Note 17. Commitments and Contingencies . Production from the Marcellus Shale upstream assets represented 204 MMcfe/d of total consolidated sales volumes for the year ended December 31, 2017. See Supplemental Oil and Gas Information (Unaudited) , below for discussion of reserves divested. Divestiture of 7.5% Interest in Tamar and Dalit Fields The terms of the Israel Natural Gas Framework (Framework) require us to reduce our current ownership interest in the Tamar and Dalit fields from 32.5% to 25% by year-end 2021. On January 29, 2018, we signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd. (TASE: TMRP) (Tamar Petroleum) for cash proceeds of approximately $560 million and 38.5 million shares of Tamar Petroleum. Closing of the transaction is expected by the end of first quarter 2018, subject to satisfactory conclusion of Tamar Petroleum's debt financing and customary approvals, terms and conditions. As of December 31, 2017, the net book value of the 7.5% interest, $293 million , was included in assets held for sale. Divestiture of Southwest Royalties In January 2018, we signed an agreement to sell our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, and acquired as part of Clayton Williams Energy Acquisition. We received proceeds of $60 million on sale of these assets. As of December 31, 2017, the asset value of these properties of $102 million and associated asset retirement obligation of $42 million were included in assets and liabilities held for sale. Other US Onshore Transactions We conducted the following additional transactions in 2017: • US Onshore Divestitures During 2017, we received total proceeds of $671 million resulting from the sale of certain US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ Basin operated properties, in the amount of approximately $40 million , is expected to occur in mid-2018. • Sale of Mineral and Royalty Assets We received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota. • Delaware Basin Acquisition In January 2017, we completed the acquisition of Delaware Basin properties, including seven producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration totaled $301 million , approximately $246 million of which was allocated to undeveloped leasehold cost. Initial consideration of $30 million was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset in our consolidated balance sheet as of December 31, 2016. Marcellus Shale CONE Gathering Divestiture In December 2017, we signed an agreement to sell our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale. At December 31, 2017 , our total investment of $181 million in the CONE entities was included in assets held for sale. We closed the sale in January 2018, receiving proceeds of $308 million in cash and utilized proceeds to pay down borrowings under the Revolving Credit Facility. We now hold 21.7 million common units representing a 33.5% limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million . Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million . Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area. The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand. Noble Midstream Partners Advantage Joint Venture On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50 /50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed approximately $67 million of cash to the Advantage Joint Venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. See Note 7. Equity Method Investments . Noble Midstream Partners serves as operator of the Advantage Pipeline System, which includes a 70 -mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of shipping capacity and 490 MBbls of storage capacity. Noble Midstream Partners Black Diamond Gathering In December 2017, Noble Midstream Partners and Greenfield Midstream, LLC, a portfolio company of EnCap Flatrock Midstream Gathering, formed an entity, Black Diamond Gathering, LLC (Black Diamond Gathering). Black Diamond Gathering subsequently entered into definitive agreements to acquire Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). The Saddle Butte purchase closed on January 31, 2018, for total cash consideration of approximately $638.5 million . Noble Midstream Partners funded its share of the purchase price with proceeds from its December 2017 common unit offering, cash on hand and borrowings under its unsecured revolving credit facility. See Note 10. Long-Term Debt . Noble Midstream partners received a 54.4% ownership interest in Black Diamond. Noble Midstream Partners fully consolidates the assets and liabilities of Black Diamond Gathering. Noble Midstream Partners will serve as operator of Saddle Butte assets which include a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation, 300 MBbls per day of delivery capacity and approximately 210 MBbls of crude oil storage capacity. Saddle Butte has approximately 141,000 dedicated acres from six customers under fixed fee arrangements. Subsequent Event - Gulf of Mexico Divestiture On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico for cash consideration of $480 million . As part of the transaction, the buyer will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million . We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1, 2018. Year Ended December 31, 2016 Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL Energy Inc. (CONSOL) agreed to terminate our 50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange. DJ Basin Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No gain or loss was recognized. 2016 Divestitures During 2016, we engaged in the following sales transactions: • entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net acres in the DJ Basin for proceeds of $505 million . We closed the sale on a portion of the properties in 2016, receiving proceeds of $486 million , with the remainder of the sale closing in 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss; • sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller US onshore properties, generating total net proceeds of $152 million , a net loss of $23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions; • sold our 47% interest in the Alon A and Alon C licenses, which included the Karish and Tanin fields, offshore Israel, for a total sales price of $73 million ( $67 million for asset consideration and $6 million from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss; • sold a 3.5% working interest in the Tamar and Dalit fields, offshore Israel, in compliance with the terms of the Framework, which requires us to reduce our ownership interest in the fields to 25% by year-end 2021. The sales price totaled $431 million , and we received net cash proceeds of $316 million , after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the fields basis and resulted in the recognition of a $261 million gain; and • received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. We received the remaining proceeds of $40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss. Year Ended December 31, 2015 2015 Divestitures In 2015, we sold certain non-strategic US onshore properties, receiving proceeds of $151 million , with no gain or loss recorded. Rosetta Merger On July 20, 2015, Noble Energy completed the Rosetta Merger. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new US onshore shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Delaware Basin ( 45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $81 million , including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and are included in other operating (income) expense, net. Purchase Price Allocation The merger was accounted for as a business combination, using the acquisition method. The allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed was based on the fair values at the merger date, with the excess of the purchase price over the fair values of the identifiable net assets acquired recorded as goodwill. Results of Operations The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $457 million and pre-tax net loss of $20 million , exclusive of a $25 million purchase price allocation adjustment, from Rosetta were generated for the year ended December 31, 2016. Revenues of $181 million and pre-tax net loss of $120 million , inclusive of a $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015. See Supplemental Oil and Gas Information (Unaudited) , below, for discussion of proved reserves added or divested in connection with the above transactions.

Asset Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2017
Asset Impairment Charges [Abstract]
Asset Impairments	Note 5. Asset Impairments Pre-tax (non-cash) asset impairment charges were as follows: Year Ended December 31, (millions) 2017 2016 2015 Gulf of Mexico $ 63 $ — $ 158 Israel — 88 36 Equatorial Guinea — — 339 Other International 7 4 — Total $ 70 $ 92 $ 533 2017 Asset Impairments During 2017, we recorded a non-cash property impairment charge related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico. 2016 Asset Impairments While the Leviathan natural gas development project, offshore Israel, was not formally sanctioned at December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development and wrote off $88 million associated with certain development concepts that were not selected. 2015 Asset Impairments During 2015, certain properties were written down to their estimated fair values using a discounted cash flow model. The cash flow model included management’s estimates of future crude oil and natural gas production, commodity prices based on forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and discount rates. Impairment charges of $481 million resulted from reductions in the forward crude oil prices as of December 31, 2015. We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field abandonment and other costs for properties in the Gulf of Mexico and offshore Israel and $5 million related to the pending sale of our interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields.

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs and Undeveloped Leashold Costs	12 Months Ended
	Dec. 31, 2017
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	Note 6. 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. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost. In addition, wells costs associated with a discovery may be charged to impairment expense if we choose not to pursue development activities. Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: Year Ended December 31, (millions) 2017 2016 2015 Capitalized Exploratory Well Costs, Beginning of Period $ 768 $ 1,353 $ 1,337 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 20 84 123 Divestitures and Other (1) — (143 ) — Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) (203 ) (1 ) (19 ) Capitalized Exploratory Well Costs Charged to Expense (3) (65 ) (525 ) (88 ) Capitalized Exploratory Well Costs, End of Period $ 520 $ 768 $ 1,353 (1) The 2016 amount relates to the farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel. The 2015 amount relates primarily to US onshore exploration activity. (3) Capitalized exploratory well costs charged to expense are included within exploration or impairment expense in our consolidated statements of operations. The 2017 amount relates primarily to the write-off of costs associated with the Troubadour natural gas discovery, Gulf of Mexico, for which we chose not to pursue development activities. See Note 5. Asset Impairments . The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with the Silvergate exploratory well in the Gulf of Mexico. The well did not encounter commercial hydrocarbons and was plugged and abandoned. The 2015 amount relates primarily to a property in northeast Nevada. After assessing its commercial viability in the current commodity price environment, we elected to discontinue exploration efforts. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: December 31, (millions) 2017 2016 2015 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 10 $ 69 $ 95 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 510 699 1,258 Balance at End of Period $ 520 $ 768 $ 1,353 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 8 10 14 The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2017 : Suspended Since Country/Project (millions) Total 2015 - 2016 2013 - 2014 2012 & Prior Progress Gulf of Mexico Katmai $ 147 $ 56 $ 91 $ — Progressing a development scenario for this 2014 crude oil discovery. We are currently conducting feasibility and front-end engineering and design studies on host platform options. Offshore Equatorial Guinea Felicita (Block O) 47 3 12 32 Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Yolanda (Block I) 23 1 6 16 A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. Offshore Cameroon YoYo (YoYo Block) 55 4 6 45 A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with both governments to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. In June 2017, we converted our mining concession license for the YoYo block into a PSC. Offshore Israel Leviathan-1 Deep 91 8 10 73 The well did not reach the target interval in 2012. We continue to reprocess and review seismic information for this discovery, based on information obtained from other recent discoveries in the region, and develop future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 32 3 5 24 Our future development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. See also Note 4. Acquisitions, Divestitures and Merger. Offshore Cyprus Cyprus 97 15 52 30 In 2016, we farmed-down a 35% interest in Block 12 and submitted an updated development plan. We continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. During 2017, we submitted an updated development plan, progressed capital project cost improvement and continued regional natural gas marketing efforts. Other Projects less than $20 million 18 (9 ) 21 6 Continuing to assess and evaluate wells. Total $ 510 $ 81 $ 203 $ 226 Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when proved reserves, including PUDs, become attributable to the property as a result of our exploration and development activities. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses. As of December 31, 2017 , we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $2.8 billion , including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $1.1 billion and $149 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. The remaining balance of undeveloped leasehold costs as of December 31, 2017 included $44 million related to Gulf of Mexico unproved properties and $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review. During 2017 , we completed geological evaluations of certain Gulf of Mexico leases and licenses and leases and licenses associated with other international unproved properties. We determined that several leases and licenses should be relinquished or exited. As a result, we recognized undeveloped leasehold impairment expense of $62 million primarily attributable to Gulf of Mexico leases. We recorded leasehold impairment expense of $93 million in 2016 and $21 million in 2015. This expense is included in exploration expense in the consolidated statements of operations.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Note 7. Equity Method Investments Equity Method Investments Investments accounted for under the equity method consist primarily of the following: • 50% interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See Note 4 – Acquisitions, Divestitures and Merger ); • 50% interest in CONE Gathering, which owns and operates natural gas gathering facilities servicing the Marcellus Shale (See Note 4 – Acquisitions, Divestitures and Merger ); • 34% interest in CONE Midstream, a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale; • 45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and • 28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas (LPG) processing plant in Equatorial Guinea. CONE Midstream Dropdown Transaction In fourth quarter 2016, CONE Midstream completed an acquisition of midstream assets (dropdown) from CONE Gathering. CONE Gathering subsequently distributed $70 million cash and additional CONE Midstream common units to us. Equity method investments are as follows: December 31, (millions) 2017 2016 Equity Method Investments CONE Investments (1) $ — $ 172 AMPCO 129 120 Alba Plant 80 82 Advantage Pipeline 70 — Other 26 26 Total Equity Method Investments $ 305 $ 400 (1) CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31, 2017. Other At December 31, 2017 , consolidated retained earnings included $90 million related to the undistributed earnings of equity method investees. The carrying value of our AMPCO investment was $12 million higher than the underlying net assets of the investee at December 31, 2017 . The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant. Summarized, 100% combined financial information for equity method investees is as follows: December 31, (millions) 2017 2016 Balance Sheet Information Current Assets $ 390 $ 313 Noncurrent Assets 588 1,390 Current Liabilities 171 149 Noncurrent Liabilities 90 256 Year Ended December 31, (millions) 2017 2016 2015 Statements of Operations Information Operating Revenues $ 790 $ 667 $ 645 Operating Expenses 303 355 393 Operating Income 487 312 252 Other (Income) Net (15 ) (7 ) (9 ) Income Before Income Taxes 502 319 261 Income Tax Provision 136 60 46 Net Income $ 366 $ 259 $ 215

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 8. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We may enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, two-way and three-way collars, basis swaps and/or put options. The fixed price swap and two-way collar contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period. A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment. For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium at the time of settlement. If the index price settles at or above the floor price of the put option, we pay only the put option premium at the time of settlement. We had no outstanding put options as of December 31, 2017 . While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices. See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. Unsettled Derivative Instruments As of December 31, 2017 , we had entered into the following crude oil derivative instruments: 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 2018 Three-Way Collars NYMEX WTI 10,000 $ — $ 45.50 $ 52.50 $ 69.09 2018 Swaps NYMEX WTI 24,000 57.09 — — — 2018 Two-Way Collars NYMEX WTI 18,000 — — 50.42 58.82 2018 Three-Way Collars Dated Brent 3,000 — 40.00 50.00 70.41 2018 Swaps ICE Brent 2,000 59.00 — — — 2018 Two-Way Collars ICE Brent 2,000 — — 50.00 55.25 2018 Three-Way Collars ICE Brent 5,000 — 43.00 50.00 59.50 2018 Basis Swaps (1) 12,000 (0.60 ) — — — 2019 Swaps NYMEX WTI 3,000 55.07 — — — 2019 Swaps ICE Brent 5,000 57.00 — — — 2019 Three-Way Collars ICE Brent 3,000 — 43.00 50.00 64.07 2019 Basis Swaps (1) 12,000 (1.01 ) — — — (1) We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts. As of December 31, 2017 , we had entered into the following natural gas derivative instruments: Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2018 Three-Way Collars NYMEX HH 120,000 $ 2.50 $ 2.88 $ 3.65 Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments (1) Asset Derivative Instruments Liability Derivative Instruments December 31, December 31, December 31, December 31, Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value (millions) Commodity Derivative Instruments Current Assets $ 2 Current Assets $ — Current Liabilities $ 58 Current Liabilities $ 102 Noncurrent Assets — Noncurrent Assets — Noncurrent Liabilities 15 Noncurrent Liabilities 14 Total $ 2 $ — $ 73 $ 116 (1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities for a discussion of our netting policy. The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2017 2016 2015 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (14 ) $ (499 ) $ (844 ) Natural Gas 1 (70 ) (147 ) NGLs (1) — — (18 ) Total Cash Received in Settlement of Commodity Derivative Instruments (13 ) (569 ) (1,009 ) Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil 18 582 423 Natural Gas (68 ) 126 65 NGLs (1) — — 20 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (50 ) 708 508 (Gain) Loss on Commodity Derivative Instruments Crude Oil 4 83 (421 ) Natural Gas (67 ) 56 (82 ) NGLs (1) — — 2 Total (Gain) Loss on Commodity Derivative Instruments $ (63 ) $ 139 $ (501 ) (1) Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 9. Asset Retirement Obligations Asset retirement obligations (AROs) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in AROs were as follows: Year Ended December 31, (millions) 2017 2016 Asset Retirement Obligations, Beginning Balance $ 935 $ 989 Liabilities Incurred 94 21 Liabilities Settled (82 ) (120 ) Revision of Estimate (65 ) (3 ) Reclassification to Liabilities Associated with Assets Held for Sale (54 ) — Accretion Expense 47 48 Asset Retirement Obligations, Ending Balance $ 875 $ 935 Year Ended December 31, 2017 Liabilities incurred include $63 million related to the Clayton Williams Energy Acquisition and $31 million primarily for other US onshore wells and midstream facilities placed into service. Liabilities settled include $43 million related to abandonment of US onshore properties, $19 million related to properties sold in the Greeley Crescent (DJ Basin) acreage divestiture, $12 million related to properties sold in the Marcellus Shale upstream divestiture and $8 million related to other offshore domestic and international properties. Revisions of estimates include a $42 million decrease related to changes in cost and timing associated with the North Sea abandonment project and a $38 million decrease for US onshore and Gulf of Mexico properties, partially offset by an increase of $15 million for West Africa. In 2017, we also transferred $42 million and $12 million of ARO liabilities associated with Southwest Royalties and Tamar field, offshore Israel, respectively, to liabilities associated with assets held for sale. Refer to Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger . Year Ended December 31, 2016 Liabilities incurred were due to new wells and facilities placed into service for US onshore, Gulf of Mexico, and offshore Israel. Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful lives and to assets sold. Settlements included $ 65 million related to abandonment of Gulf of Mexico properties, $49 million related to US onshore properties abandoned or sold, $5 million related to offshore Israel properties and $1 million related to the North Sea.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-term Debt	Note 10. Long-Term Debt Our debt consists of the following: December 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ 230 2.27 % $ — — % Noble Midstream Services Revolving Credit Facility, due September 20, 2021 85 2.49 % — — % Term Loan Facility, due January 6, 2019 (1) — — % 550 2.01 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — Senior Notes, due March 1, 2019 (2) — — % 1,000 8.25 % Senior Notes, due May 1, 2021 379 5.63 % 379 5.63 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % Senior Notes, due June 1, 2022 (1) — — % 18 5.88 % Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % Senior Notes, due January 15, 2028 (2) 600 3.85 % — — % Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % Senior Notes, due August 15, 2047 (2) 500 4.95 % — — % Other Senior Notes and Debentures (3) 92 7.13 % 92 7.13 % Capital Lease and Other Obligations (4) 273 — % 375 — % Total $ 6,859 $ 7,114 Unamortized Discount (24 ) (23 ) Unamortized Premium (2) 12 17 Unamortized Debt Issuance Costs (40 ) (34 ) Total Debt, Net of Discount $ 6,807 $ 7,074 Less Amounts Due Within One Year Capital Lease and Other Obligations (61 ) (63 ) Long-Term Debt Due After One Year $ 6,746 $ 7,011 (1) In fourth quarter 2017, we repaid $550 million of borrowings under the Term Loan Facility and $18 million of our outstanding Senior Notes due June 1, 2022. (2) In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047. (3) Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13% . (4) The reduction from 2016 includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $60 million of capital lease principal payments. All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Revolving Credit Facility Our 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) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating. The Revolving Credit Facility requires that our total debt to capitalization ratio (as defined in the Revolving Credit Facility), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the Revolving Credit Facility and require the immediate repayment of any outstanding advances under the Revolving Credit Facility. As of December 31, 2017 , we were in compliance with our debt covenants. The Revolving Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Revolving Credit Facility have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses. Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility). The Noble Midstream Services Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Services Revolving Credit Facility may be increased by an additional $350 million , subject to certain conditions, and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners. Borrowings by Noble Midstream Services under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Service's option, either: • in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the London interbank offered rate (LIBOR) for an interest period of one month plus 1.00% ; or • in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. The Noble Midstream Services Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated adjusted earnings before interest expense, income taxes, depreciation, depletion, and amortization (EBITDA) and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Services Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Services Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Debt issuance costs associated with this facility were de minimis. On January 31, 2018, in connection with the acquisition of Saddle Butte, Noble Midstream Partners drew an additional $300 million under the Noble Midstream Services Revolving Credit Facility and partially exercised the accordion feature, increasing the commitments under the credit agreement to $530 million . Senior Notes Issuance and Completed Tender Offer On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million , both of which are reflected as a reduction of long-term debt and are amortized over the life of the notes. Proceeds of $1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1 billion of our 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income) expense in our consolidated statements of operations. Leviathan Term Loan Facility 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 amounts 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 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, and 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 Facility and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility), which provided for a three -year term loan facility for a principal amount of $1.4 billion . Provisions of the Term Loan Facility were consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility could be prepaid prior to maturity without premium. The Term Loan Facility accrued interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5% , and (iii) a LIBOR plus 1.0% , plus a margin that ranged from 10 basis points to 75 basis points depending upon our credit rating, or (b) a LIBOR, plus a margin that ranged 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 in 2015. As a result of the tender offers, we recognized a gain of $80 million in first quarter 2016 which is reflected in other non-operating (income) expense in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of the amount outstanding under the Term Loan Facility from cash on hand. In fourth quarter 2017, we repaid the remaining outstanding balance of $550 million under this facility using proceeds received from the sale of non-core Greeley Crescent and Bronco acreage in the DJ Basin. Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt. Capital Lease and Other Obligations The amount of the capital lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligation is expected to be reduced during the next 12 months. See Note 17. Commitments and Contingencies for future capital lease payments. Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2017 are as follows: (millions) Debt Principal Payments 2018 $ — 2019 — 2020 230 2021 1,464 2022 — Thereafter 4,892 Total $ 6,586

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 11. Income Taxes Recent Changes in US Tax Law On December 22, 2017, the US Congress enacted the Tax Reform Legislation, which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21% effective January 1, 2018. Under US GAAP, we are required to recognize the effect of a rate change on deferred tax assets and liabilities in the period in which the tax rate change is enacted. Therefore, the rate change enacted by the Tax Reform Legislation resulted in the recognition of a deferred tax benefit of $500 million at December 31, 2017. Further, the Tax Reform Legislation provides for a transition tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Based on current interpretations of the law, we have recognized additional taxable income of $767 million associated with the transition tax, which is fully offset by current year net operating losses and have recorded corresponding deemed foreign tax credits of $164 million , against which we have recorded a full valuation allowance. The Tax Reform Legislation also repealed corporate alternative minimum tax (AMT) for tax years beginning January 1, 2018, and provides that existing AMT credit carryovers are refundable beginning in 2018. We have approximately $3 million of AMT credit carryovers that are expected to be fully refunded by 2022. In addition, the Tax Reform Legislation preserves deductibility of intangible drilling costs and provides for 100% bonus depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from 100% beginning in 2023 to 0% for years after 2026. The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, that are not expected to materially affect us. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount may be adjusted in future periods, as an adjustment to income tax expense or benefit, in the period in which the final amounts are determined. Income Tax Disclosures Components of income (loss) from operations before income taxes are as follows: Year Ended December 31, (millions) 2017 2016 2015 Domestic $ (2,831 ) $ (1,859 ) $ (2,338 ) Foreign 640 87 119 Total $ (2,191 ) $ (1,772 ) $ (2,219 ) The income tax provision (benefit) consists of the following: Year Ended December 31, (millions) 2017 2016 2015 Current Taxes Federal $ (11 ) $ (4 ) $ (1 ) State 1 5 — Foreign 96 196 107 Total Current $ 86 $ 197 $ 106 Deferred Taxes Federal $ (1,258 ) $ (784 ) $ 216 State (8 ) (24 ) (5 ) Foreign 39 (176 ) (95 ) Total Deferred $ (1,227 ) $ (984 ) $ 116 Total Income Tax (Benefit) Provision Attributable to Noble Energy $ (1,141 ) $ (787 ) $ 222 Effective Tax Rate 52.1 % 44.4 % (10.0 )% A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, (percentages) 2017 2016 2015 Federal Statutory Rate (1) 35.0 % 35.0 % 35.0 % Effect of Earnings of Equity Method Investees 1.9 1.0 0.6 Noncontrolling Interests 1.1 0.4 — US and Foreign Statutory Rate Change (1) 23.5 1.6 — Transition Tax (1) (4.8 ) — — State Taxes, Net of Federal Benefit 0.3 1.3 0.3 Difference Between US and Foreign Rates 1.8 (0.1 ) 2.6 Foreign Exploration Loss — 0.1 2.7 Change in Valuation Allowance (1) (17.4 ) (2.0 ) — Oil Profits Tax - Israel (0.1 ) — 0.1 Tax Contingency 0.1 0.2 0.4 Accumulated Undistributed Foreign Earnings (1) 11.0 7.2 (37.7 ) Goodwill Impairment — — (12.3 ) Other, Net (0.3 ) (0.3 ) (1.7 ) Effective Rate 52.1 % 44.4 % (10.0 )% (1) See Recent Changes in US Tax Law, above. Rate will decrease to 21.0% for fiscal year 2018. In addition, see discussion regarding accumulated undistributed foreign earnings above. Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2017 2016 Deferred Tax Assets Loss Carryforwards $ 902 $ 474 Employee Compensation and Benefits 97 150 Mark to Market of Commodity Derivative Instruments 7 44 Foreign Tax Credits 366 — Other 104 49 Total Deferred Tax Assets $ 1,476 $ 717 Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits (549 ) (242 ) Net Deferred Tax Assets $ 927 $ 475 Deferred Tax Liabilities Accumulated Undistributed Foreign Earnings (1) — (240 ) Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (2,029 ) (2,054 ) Total Deferred Tax Liability $ (2,029 ) $ (2,294 ) Net Deferred Tax Liability $ (1,102 ) $ (1,819 ) (1) At December 31, 2017, we reversed the deferred tax liability associated with the removal of the assertion of indefinitely reinvested earnings, resulting in recognition of a deferred tax benefit of $240 million . Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2017 2016 Deferred Income Tax Asset - Noncurrent $ 25 $ — Deferred Income Tax Liability - Noncurrent (1,127 ) (1,819 ) Net Deferred Tax Liability $ (1,102 ) $ (1,819 ) Deferred Tax Assets Our estimated US federal income tax net operating loss (NOL) carryforwards totaled approximately $3.2 billion at December 31, 2017 . Included in the resulting deferred tax assets are acquired NOLs associated with the Clayton Williams Energy Acquisition in 2017 and the Rosetta Merger in 2015. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. Based on the level of historical taxable income and projections for future taxable income, we believe it is more likely than not that we will realize the benefits of these NOL carryforwards. However, the amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $183 million in 2017 and $242 million in 2016 . The changes to the valuation allowance for the loss carryforwards between periods was attributable to the offset of the valuation allowance against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were recognized along with the additional taxable income associated with the transition tax. A full valuation allowance of $366 million has been recorded against all foreign tax credits based on current interpretation of the Tax Reform Legislation and the expected future utilization of NOL carryforwards. Clayton Williams Energy Acquisition On April 24, 2017 , we completed the Clayton Williams Energy Acquisition. For federal income tax purposes, the transaction qualified as a tax free merger and we acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. After the fair market valuation, we have currently recorded an opening balance sheet deferred tax liability of $307 million , adjusted for the new US statutory tax rate, which includes a deferred tax asset for federal pre-tax net operating losses of approximately $450 million . The merger resulted in a change of control for federal income tax purposes, and the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the merger. We anticipate full utilization of the total NOL prior to expiration. Accumulated Undistributed Earnings of Foreign Subsidiaries In 2015, we changed our indefinite reinvestment assertion (APB 23 assertion) based on the continued and prolonged decline in global commodity prices and an evaluation of our operations’ anticipated capital requirements and projected foreign cash positions given the adoption of the Israel Natural Gas Framework in December 2015. During 2016, we reviewed capital requirements and foreign cash positions, and reduced the deferred tax liability associated with unremitted earnings, net of foreign tax credits, to $240 million as of December 31, 2016 . In 2017, as a result of Tax Reform Legislation, which establishes a new territorial tax regime, the deferred tax liability recorded as of December 31, 2016 was reversed, resulting in a deferred tax benefit of $240 million for the year ended December 31, 2017 . We do not expect a withholding tax impact upon actual distribution of earnings and as such have not recorded any additional tax associated with the unremitted earnings. Effective Tax Rate Our effective tax rate increased in 2017 as compared with 2016 primarily due to the recognition of a deferred tax benefit related to the Tax Reform Legislation. The deferred tax benefit resulted from the revaluation of the ending deferred tax liability at the reduced future tax rate and the transition to the new territorial tax regime. Our effective tax rate increased in 2016 as compared with 2015 primarily due to adjustments to deferred taxes for removal of the APB 23 assertion, as noted above, decreased earnings in foreign jurisdictions with rates that vary from the US statutory rate, a decrease in the Israeli income tax rate, and the 2015 impact of foreign dividend repatriation and goodwill impairment. Israeli Tax Law Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreased the deferred tax expense for 2017 by $12 million . Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Profits Tax). The Profits Tax is calculated by dividing net accumulated revenue generated by each separate project by its cumulative investments as defined within the Law. Once the revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Profits Tax increases progressively up to a maximum rate of 50%. The Profits Tax provides for a corporate tax rate adjustment based on the corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the Profits Tax rate is calculated. At the current corporate tax rate, the Profits Tax rate is 46.8%. The Profits Tax is deductible for corporate Israeli tax purposes. Our Tamar and Leviathan projects are both subject to the Profits Tax and are expected to pay at the maximum rate. Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results. In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2014 , Israel - 2015 and Equatorial Guinea - 2012 . Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows: (millions) Twelve Months Ended December 31, 2017 Unrecognized Tax Benefits, Beginning Balance $ 3 Reductions for Tax Positions of Prior Years (3 ) Unrecognized Tax Benefits, Ending Balance $ — The changes to our unrecognized tax benefits during 2017 primarily resulted from changes in various foreign tax return filings, positions and audit settlements. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net income. During 2017 , we recognized and accrued a de minimis amount of interest and no penalties.

Stock-Based and Other Compensat

Stock-Based and Other Compensation Plans	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based and Other Compensation Plans	Note 12. Stock-Based and Other Compensation Plans We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2017 2016 2015 Stock-Based Compensation Expense Included in: General and Administrative Expense $ 56 $ 62 $ 50 Exploration Expense and Other 48 15 36 Total Stock-Based Compensation Expense $ 104 $ 77 $ 86 Tax Benefit Recognized $ (36 ) $ (27 ) $ (30 ) Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below. 2017 Long-Term Incentive Plan On April 25, 2017, our stockholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon stockholder approval, the 2017 Plan superceded and replaced the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grants would be made under the 1992 Plan. The 1992 Plan continues to govern awards that were outstanding as of the date of its suspension, which remain in effect pursuant to their terms. Under the 2017 Plan, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 2017 Plan is 29 million shares of common stock. At December 31, 2017 , 28,987,609 shares of our common stock were reserved for issuance, including 28,972,832 shares available for future grants and awards, under the 2017 Plan. Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three -year period. Restricted stock awards made under the 2017 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided otherwise in accordance with the terms of the 2017 Plan, the recipient of restricted stock would be the record owner of the shares and have all the rights of a stockholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution, which will transfer to the Company. Restricted stock awards with a time-vested restriction vest over a two or three -year period. Performance share awards cliff vest after a three -year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group. 2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996 . At December 31, 2017 , 674,025 shares of our common stock were reserved for issuance, including 463,096 shares available for future grants and awards, under the 2015 Plan. Stock Option Grants The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below: • Expected term The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date. • Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term. • Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant. • Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three -year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three -year period ended prior to the date of grant. The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2017 2016 2015 Expected Term (in Years) 6.4 6.3 6.0 Expected Volatility 33.2 % 32.4 % 32.6 % Risk-Free Rate 2.2 % 1.6 % 1.4 % Expected Dividend Yield 0.9 % 0.7 % 1.2 % Weighted Average Grant-Date Fair Value $ 13.26 $ 10.10 $ 13.93 Stock option activity was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (in years) (in millions) Outstanding at December 31, 2016 15,088,862 $ 43.49 Granted 1,819,819 39.40 Exercised (382,882 ) 37.57 Forfeited (976,577 ) 43.93 Outstanding at December 31, 2017 15,549,222 $ 43.42 5.0 $ 6 Exercisable at December 31, 2017 12,101,890 $ 44.98 4.0 $ 6 The total intrinsic value of options exercised was $4 million in 2017, $10 million in 2016 and $7 million in 2015. As of December 31, 2017 , $21 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options. Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three -year period ended prior to the date of award. The risk-free rate is based on a three-year period for US Treasury securities as of the year ended prior to the date of award. The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2017 2016 2015 Number of Simulations 500,000 500,000 500,000 Expected Volatility 35 % 38 % 30 % Risk-Free Rate 1.5 % 1.0 % 0.8 % Restricted stock activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Shares Weighted Average Award Date Fair Value Number of Shares Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2016 1,371,780 $ 36.37 1,502,992 $ 27.43 Awarded (1) 3,201,504 36.26 464,608 24.25 Vested (1) (2,515,383 ) 34.93 (219,883 ) 44.61 Forfeited (218,164 ) 37.66 (535,012 ) 33.12 Outstanding at December 31, 2017 1,839,737 $ 37.21 1,212,705 $ 25.55 (1) During 2017, we awarded approximately 1.9 million shares of restricted stock for the conversion of Clayton Williams Energy shares into Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are included in the above table. See Note 3. Clayton Williams Energy Acquisition . The total fair value of restricted stock that vested was $34 million in 2017 , $24 million in 2016 , and $62 million in 2015 . The weighted average award-date fair value of restricted stock awarded was $35.45 per share in 2017 , $29.99 per share in 2016 , and $35.53 per share in 2015 . As of December 31, 2017 , $41 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock. Cash-Settled Awards On February 1, 2016, we issued cash-settled awards to certain employees under the 1992 Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model and assumed 500,000 simulations, 38 % expected volatility and a risk-free rate of 0.9 %. These phantom units represent a hypothetical interest in the Company, and, once vested, are settled in cash. The phantom unit value at vesting will equal the lesser of the fair market value of a share of common stock of the Company as of the vesting date ( 2 -year cliff vesting for officers and 3 -year cliff vesting for non-officers) or up to four times the fair market value of a share of common stock of the Company, which was $31.65 , as of the grant date. As of December 31, 2017 , we had accrued a liability of $10 million related to the phantom units. No phantom units were awarded in 2017. Phantom unit activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Units Weighted Number of Units Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2016 712,089 $ 31.65 209,504 $ 6.82 Vested (13,305 ) 31.65 — — Forfeited (88,625 ) 31.65 (42,021 ) 6.82 Outstanding at December 31, 2017 610,159 $ 31.65 167,483 $ 6.82 As of December 31, 2017 , $6 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.1 years. The total fair value of phantom units that vested in 2017 was de minimis. Common stock dividends accrue on phantom units and will be paid upon vesting. Other Compensation Plans 401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $31 million in 2017 , $32 million in 2016 , and $35 million in 2015 . Deferred Compensation Plan We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of that rabbi trust are as follows: December 31, (millions, except share amounts) 2017 2016 Rabbi Trust Assets Mutual Fund Investments $ 57 $ 62 Noble Energy Common Stock (at Fair Value) 14 26 Total Rabbi Trust Assets $ 71 $ 88 Liability Under Related Deferred Compensation Plan $ 71 $ 88 Number of Shares of Noble Energy Common Stock Held by Rabbi Trust 470,030 671,269 Assets of that rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair value. See Note 13. Fair Value Measurements and Disclosures . The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets. Shares of our common stock held by the rabbi trust holding common stock are accounted for as treasury stock (recorded at cost, $16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock. Approximately 400,000 shares, or 85% , of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2017 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next two years. Distributions of 200,000 shares were made in each of 2017 , 2016 and 2015 . In addition, plan participants sold 1,238 shares of our common stock in 2017 , 1,009 shares in 2016 , and 1,009 shares in 2015 . Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $21 million in 2017 , $22 million in 2016 and $18 million in 2015 . All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense (income) of $9 million in 2017 , $11 million in 2016 and $(12) million in 2015 . We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities of $116 million and $121 million were outstanding at December 31, 2017 and 2016 , respectively, under those other plans.

Fair Value Measurements and Dis

Fair Value Measurements and Disclosures	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 13. 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, enhanced swaps and basis 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 8. 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. See Note 12. Stock-Based and Other Compensation Plans . Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Adjustment (2) Fair Value Measurement December 31, 2017 Financial Assets Mutual Fund Investments $ 57 $ — $ — $ — $ 57 Commodity Derivative Instruments — 7 — (5 ) 2 Financial Liabilities Commodity Derivative Instruments — (78 ) — 5 (73 ) Portion of Deferred Compensation Liability Measured at Fair Value (71 ) — — — (71 ) 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) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Asset Impairments In 2017, 2016, and 2015, we determined that the carrying amounts of certain oil and gas assets were not recoverable from future cash flows and, therefore, were impaired. The assets were reduced to their estimated fair values as noted below. Inventory Impairment In 2016, and 2015, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value or not recoverable from future cash flows. These assets were, therefore, adjusted as noted below. Marcellus Shale Firm Transportation Liability As of December 31, 2017 , we had recorded a $90 million liability representing the discounted present value of our remaining obligation under firm transportation contracts. See Note 17 – Commitments and Contingencies . Information about the impaired assets is as follows: Fair Value Measurements Using Description Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Net Book Value (2) Total Pre-tax (Non-cash) Impairment Loss (millions) Year Ended December 31, 2017 Impaired Oil and Gas Properties $ — $ — $ — $ 70 $ 70 Year Ended December 31, 2016 Impaired Oil and Gas Properties — — — 92 92 Impaired Materials and Supplies Inventory — — 91 105 14 Year Ended December 31, 2015 Impaired Oil and Gas Properties — — 752 1,285 533 Impaired Materials and Supplies Inventory — — 61 81 20 (1) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents net book value at the date of assessment. The fair values of properties held and used were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future crude oil and natural gas production, commodity prices based on commodities sales contract terms or commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10% . The fair values of assets held for sale were based on anticipated sales proceeds less costs to sell. Costs associated with abandoned properties were completely written off. See Note 5. Asset Impairments . 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. At December 31, 2017, our variable-rate, non-public debt included the Revolving Credit Facility and the Noble Midstream Services Revolving Credit Facility. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 10. Long-Term Debt . Fair value information regarding our debt is as follows: December 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,586 $ 7,142 $ 6,739 $ 7,112 (1) Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Note 14. Segment Information During second quarter 2017 , as a result of the strategic changes in our US onshore portfolio, we established our Midstream business as a new reportable segment. The Midstream segment, which includes the consolidated accounts of Noble Midstream Partners, additional US onshore midstream assets and US onshore equity method investments, was previously reported within the United States reportable segment. As a result, we now have the following reportable segments: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland (Canada), Suriname, Falkland Islands and new ventures); and Midstream. The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production or E&P). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative expenses are recorded at the corporate level. Prior period amounts are presented on a comparable basis. Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2017 Oil, NGL and Gas Sales from Third Parties (2) $ 4,060 $ 3,156 $ 534 $ 370 $ — $ — $ — $ — Income from Equity Method Investees and Other (3) 196 — — 120 — 76 — — Intersegment Revenues — — — — — 277 (277 ) — Total Revenues 4,256 3,156 534 490 — 353 (277 ) — Lease Operating Expense 571 466 29 90 — — (14 ) — Production and Ad Valorem Taxes 138 135 — — — 3 — — Gathering, Transportation and Processing Expense 432 550 — — — 70 (188 ) — Total Production Expense 1,141 1,151 29 90 — 73 (202 ) — DD&A 2,053 1,739 76 146 4 30 (5 ) 63 Clayton Williams Energy Acquisition Expenses 100 100 — — — — — — Loss on Debt Extinguishment 98 — — — — — — 98 Loss on Marcellus Shale Upstream Divestiture 2,379 2,379 — — — — — — Asset Impairments 70 63 — — 7 — — — Gain on Commodity Derivative Instruments (63 ) (92 ) — 29 — — — — (Loss) Income Before Income Taxes (2,191 ) (2,365 ) 413 203 (54 ) 233 (62 ) (559 ) Equity Method Investments 305 — — 225 — 80 — — Additions to Long Lived Assets 2,851 1,994 411 34 (34 ) 423 (79 ) 102 Goodwill (4) 1,310 1,310 — — — — — — Total Assets at End of Year (5) 21,476 15,767 2,846 1,308 114 1,357 (163 ) 247 Year Ended December 31, 2016 Oil, NGL and Gas Sales from Third Parties (2) $ 3,389 $ 2,416 $ 540 $ 433 $ — $ — $ — $ — Income from Equity Method Investees and Other 102 — — 50 — 52 — — Intersegment Revenues — — — — — 200 (200 ) — Total Revenues 3,491 2,416 540 483 — 252 (200 ) — Lease Operating Expense 542 418 37 105 — — (18 ) — Production and Ad Valorem Taxes 78 76 — — — 2 — — Gathering, Transportation and Processing Expense 480 564 — — — 44 (128 ) — Total Production Expense 1,100 1,058 37 105 — 46 (146 ) — DD&A 2,454 2,103 81 205 6 19 — 40 Asset Impairments 92 — 88 — 4 — — — Loss on Commodity Derivative Instruments 139 126 — 13 — — — (Loss) Income Before Income Taxes (1,772 ) (1,277 ) 543 (338 ) (199 ) 176 (51 ) (626 ) Equity Method Investments 400 — — 217 — 183 — — Additions to Long Lived Assets 1,526 1,353 88 54 (6 ) 58 (53 ) 32 Total Assets at End of Year (5) 21,011 16,153 2,233 1,479 89 851 (98 ) 304 Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2015 Oil, NGL and Gas Sales from Third Parties (2) $ 3,093 $ 2,011 $ 497 $ 580 $ 5 $ — $ — $ — Income from Equity Method Investees and Other 90 — — 39 — 51 — — Intersegment Revenues — — — — — 119 (119 ) — Total Revenues 3,183 2,011 497 619 5 170 (119 ) — Lease Operating Expense 563 398 42 131 4 — (12 ) — Production and Ad Valorem Taxes 127 126 — — — 1 — — Gathering, Transportation and Processing Expense 306 366 — — — 25 (85 ) — Total Production Expense 996 890 42 131 4 26 (97 ) — DD&A 2,131 1,677 70 326 — 14 — 44 Asset Impairments 533 158 36 339 — — — — Gain on Commodity Derivative Instruments (501 ) (347 ) — (154 ) — — — — (Loss) Income Before Income Taxes (2,219 ) (1,693 ) 313 (90 ) (229 ) 123 (21 ) (622 ) Equity Method Investments 453 — — 227 — 226 — — Additions to Long Lived Assets 3,062 2,409 147 124 177 146 (21 ) 80 Total Assets at End of Year (5) 24,196 18,043 2,676 2,299 205 799 (46 ) 220 (1) Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. (2) Revenues from third parties for all foreign countries, in total, were $904 million in 2017, $973 million in 2016, and $1.1 billion in 2015. (3) The midstream segment includes revenues of $19 million from third party customers. (4) Goodwill is associated with the Texas reporting unit. See Note 1. Summary of Significant Accounting Policies . (5) Long-lived assets located in all foreign countries, in total, were $2.8 billion , $3.0 billion , and $3.9 billion at December 31, 2017, 2016, and 2015, respectively.

Concentration of Risk

Concentration of Risk	12 Months Ended
	Dec. 31, 2017
Concentration of Risk [Abstract]
Concentration of Risk	Note 15. Concentration of Risk Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows: Percentage of Crude Oil Sales Percentage of Total Oil, Gas & NGL Sales Year Ended December 31, 2017 BP (1) 15 % 10 % Shell (2) 22 % 13 % Year Ended December 31, 2016 Glencore Energy UK Ltd 22 % 12 % Shell (2) 24 % 13 % Year Ended December 31, 2015 Glencore Energy UK Ltd 30 % 18 % Shell (2) 18 % 11 % (1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company. (2) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited. We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production. Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk. A significant portion of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness. Our accounts receivable result from sales of crude oil, NGL and natural gas production, and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, especially in deepwater or remote international locations, can be very capital cost intensive. Thus the receivables from our joint venture partners can become significant. Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less . We continually monitor the creditworthiness of the counterparties, some of which are not as creditworthy as we are and may experience liquidity problems. We have obtained credit enhancements from some parties, including one of our significant crude oil purchasers, in the way of parental guarantees or letters of credit. However, we do not have all of our trade credit or joint interest receivables protected through guarantees or credit support. Nonperformance by a trade creditor or joint venture partner could result in losses. Our hedging activity may increase counterparty credit risk, especially during periods of falling commodity prices. We conduct our hedging activities with a diverse group of investment grade major banks and market participants. We monitor the creditworthiness of our hedge counterparties, and our internal hedge policies provide for mark-to-market exposure limits. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election.

Additional Shareholders' Equity

Additional Shareholders' Equity Information	12 Months Ended
	Dec. 31, 2017
Additional Shareholders' Equity Information [Abstract]
Additional Shareholders' Equity Information	Note 16. Additional Shareholders’ Equity Information Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows: Year Ended December 31, 2017 2016 Common Stock Shares Issued Shares, Beginning of Period 471,360,427 469,718,512 Exercise of Common Stock Options 382,882 954,898 Restricted Stock Awarded, Net of Forfeitures (1) 2,912,936 687,017 Shares Exchanged in Clayton Williams Energy Acquisition 54,087,136 — Shares, End of Period 528,743,381 471,360,427 Treasury Stock Shares, Beginning of Period 37,961,316 37,925,625 Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (2) 1,026,891 236,700 Rabbi Trust Shares Distributed and/or Sold (201,238 ) (201,009 ) Shares, End of Period 38,786,969 37,961,316 Additional Information Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (2) — — Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Loss per Share 15,619,276 14,218,319 (1) The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. See Note 3. Clayton Williams Energy Acquisition . (2) The 2017 amount includes approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale agreement. (3) For the years ended December 31, 2017 and 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. Issuance of Noble Midstream Partners Common Units On December 15, 2017, Noble Midstream Partners closed an offering of 3,680,000 common units, generating net proceeds of approximately $174 million, net of offering costs. On June 26, 2017, Noble Midstream Partners engaged in a private placement offering of 3,525,000 common units, generating proceeds of approximately $138 million , net of offering costs. In third quarter 2016, Noble Midstream Partners completed its initial public offering of 14,375,000 common units, generating proceeds of $299 million , net of offering costs. Subsequent Event - Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors authorized a share repurchase program of $750 million which expires December 31, 2020. All purchases will be made in accordance with applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may be discontinued at any time. Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included: Accumulated Other Comprehensive Loss (millions) Interest Rate Cash Flow Hedges Pension- Related and Other Total December 31, 2014 $ (23 ) $ (67 ) $ (90 ) Realized Amounts Reclassified Into Earnings 1 62 63 Unrealized Change in Fair Value — (6 ) (6 ) December 31, 2015 (22 ) (11 ) (33 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (3 ) (3 ) December 31, 2016 (21 ) (10 ) (31 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (4 ) (4 ) December 31, 2017 $ (20 ) $ (10 ) $ (30 ) All amounts in the table above are reported net of tax, using an effective income tax rate of 35% . AOCL at December 31, 2017 included deferred losses of $20 million , net of tax, related to interest rate derivative instruments. This amount is being reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March 2041.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 17. 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 US District Court for the District of Colorado 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. Over the last three years, 2015 through 2017, we spent approximately $72.0 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 Oil & Gas Conservation Commission Administrative Order on Consent In November 2017, we received a proposed Administrative Order on Consent (AOC) from the COGCC to resolve allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. 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. In May 2017, we reached a final resolution with the APCD and executed the COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s). This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows. Transportation and Gathering Obligations As part of our Marcellus Shale upstream divestiture, we retained certain transportation and gathering obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of two to 16 years, is approximately $1.4 billion, undiscounted. The agreements for firm transportation primarily relate to services on certain pipelines which were recently placed into service in late 2017/early 2018 or for services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems with estimated in-service dates in late 2018. The associated commitments are included in the table below. See Note 1. Summary of Significant Accounting Policies – Exit Costs . We also have transportation and gathering obligations to flow DJ Basin, Eagle Ford Shale, and Gulf of Mexico production to various markets. Our financial commitment for these agreements, which have remaining terms of one to 11 years, is approximately $781 million , undiscounted. The commitment is included in the table below. Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment and other property. Rental expense for office buildings and oil and gas operations equipment was $69 million in 2017 , $76 million in 2016 , and $84 million in 2015 . Minimum commitments as of December 31, 2017 consist of the following: (millions) Drilling, Equipment, and Purchase Obligations Transportation and Gathering Obligations Operating Lease Obligations Capital Lease and Other Obligations (1) Total 2018 $ 636 $ 215 $ 44 $ 74 $ 969 2019 167 252 33 45 497 2020 40 247 32 42 361 2021 13 223 32 29 297 2022 8 182 33 21 244 2023 and Thereafter 32 1,355 156 124 1,667 Total $ 896 $ 2,474 $ 330 $ 335 $ 4,035 (1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt .

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation and Consolidation	Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider an essential component of our business and a necessary and integral element to our value chain involving the monetization of natural gas. With our partners, we engage in joint strategic operational and financial decision making for these entities. In order to reflect the economics associated with our integrated upstream value chain described above, we include income from equity method investees as a component of revenues in our consolidated statements of operations. We carry equity method investments at our share of net assets of the equity investees plus loans and advances, and include the investments in other noncurrent assets in our consolidated balance sheets. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations. See Note 7. Equity Method Investments . Noncontrolling Interests In third quarter 2016, Noble Midstream Partners LP (Noble Midstream Partners), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners.
Use of Estimates	Use of 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. Estimated quantities of crude oil, natural gas and NGL reserves are the most significant of our estimates. All the reserves data included in this Annual Report Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President – Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited) . Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill, exit costs and asset retirement obligations (AROs), valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in commodity prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates.
Reclassification	Reclassifications In Note 14. Segment Information , we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation.
Fair Value Measurements	Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows: • Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. • 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. • Level 3 measurements are fair value measurements which use unobservable inputs. The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated.
Inventories	Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of cost or net realizable value. The cost of crude oil inventory includes production costs and DD&A of oil and gas properties.
Property, Plant and Equipment	Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Costs related to repair and maintenance activities are expensed as incurred. Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above. We recorded property impairment charges in 2017 , 2016 and 2015 and it is possible that other proved oil and gas properties could become impaired in the future due to commodity price declines and/or field performance. See Note 5. Asset Impairments . Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method over an average holding period. We recorded undeveloped leasehold impairment expense in 2017 . It is possible that unproved oil and gas properties, including undeveloped leases, could become impaired in the future if commodity prices decline or if there are changes in exploration plans or the timing and extent of development activities. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. Assets Held for Sale We occasionally market oil and gas properties for sale. At the end of each reporting period, we evaluate properties being marketed to determine whether any should be reclassified as held for sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale in our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See Note 4. Acquisitions, Divestitures and Merger . Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as buildings and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from three to thirty years. Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment. Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average rate we pay on long-term debt, including our unsecured revolving credit facility (Revolving Credit Facility) and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $49 million in 2017 , $84 million in 2016 , and $144 million in 2015 . Asset Retirement Obligations AROs consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in DD&A expense in the consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability, and the amounts continue to be amortized over the useful life of the related long-lived asset.
Goodwill	Goodwill 2017 Goodwill As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion . This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit, a component of our US reportable and operating segment. See Note 3. Clayton Williams Energy Acquisition . Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for recently issued accounting guidance regarding future goodwill impairment testing. We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill. Certain negative indicators as of September 30 2017 included the current onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as the current commodity price environment, our current and future drilling and development plans for the Texas assets and synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties, which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability. Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware Basin. Having assessed the totality of such events and circumstances described above, we determined that, while there existed certain negative factors, the overall qualitative assessment did not indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless of the outcome of the qualitative review, we decided to proceed with Step 1 of the impairment test as part of our annual review. As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, and therefore, the Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017. If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.
Exit Costs	Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Accrued exit costs at December 31, 2017 relate primarily to estimated costs associated with retained Marcellus Shale firm transportation contracts. The recognition and fair value estimation of an exit cost liability require that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows include the non-cash portion of gain and loss on commodity derivative instruments, which represents the difference between the total gain and loss on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during the period. We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master agreement with netting clauses.
Stock-Based Compensation	Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations.
Pension and Other Postretirement Benefit Plans	Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to accumulated other comprehensive loss (AOCL), net of tax. The amount remaining in AOCL at December 31, 2017 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and actuarial losses relating to the pension plan from AOCL to earnings.
Income Taxes and Impact of Tax Reform Legislation	Income Taxes and Impact of Tax Reform Legislation Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
Treasury Stock	Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets.
Revenue Recognition and Imbalances	Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
Basic and Diluted Earnings (Loss) Per Share	Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss.
Contingencies	Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 17. Commitments and Contingencies . We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency	Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations.
Segment Information	Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments.
Revolving Credit Facilities	Revolving Credit Facilities In accordance with our accounting policy, we net intra-quarter revolving credit facility activity to zero for purposes of consolidated statements of cash flows disclosure.
Recently Issued Accounting Standards	Recently Issued Accounting Standards Revenue Recognition In May 2014, the Financial Accounting Standards Board (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. We continue to evaluate the impact of ASU 2014-09 on our accounting policies, internal controls, and consolidated financial statements and related disclosures. We are performing a review of contracts for each of our revenue streams and developing accounting policies to address the provisions of ASU 2014-09. ASU 2014-09 also includes provisions regarding future revenues and expenses under a gross-versus-net presentation. We are evaluating the impact, if any, on the presentation of future revenues and expenses under this gross-versus-net presentation guidance. Based upon assessments performed to date, we do not expect ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to domestic natural gas processing revenues and expenses. The impact of such presentation changes will not impact our net income. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new standard on January 1, 2018, using the modified retrospective approach. Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our financial statements. 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 are 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. ASU 2017-01 is designed to reduce the number of transactions accounted for as business transactions, which take more time and cost more to analyze than asset transactions. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our recent Clayton Williams Energy Acquisition was not impacted by this guidance, which we will apply to applicable and qualifying transactions after adoption on January 1, 2018. 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. ASU 2016-18 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our consolidated statements 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 will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our consolidated statements of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. ASU 2016-02 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. We will adopt the new standard on the effective date of January 1, 2019. At this time, we cannot reasonably estimate the impact ASU 2016-02 will have on our consolidated financial statements; however, we believe adoption and implementation of ASU 2016-02 will have a material impact on our consolidated balance sheet resulting from an increase in both assets and liabilities relating to leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to ASU 2016-02 and have begun contract review and documentation. Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new guidance, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early adopt. 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 will adopt the new standard on the effective date of January 1, 2020 and are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. SAB 118 On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) to address the application of US GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects relating to the Tax Reform Legislation. SAB 118 provides guidance for registrants under three scenarios: 1) if measurement​ ​of​ ​certain​ ​income​ ​tax​ ​effects​ ​is​ ​complete, registrants must reflect the tax effects of the Tax Reform Legislation for which the accounting is complete; 2) if measurement​ ​of​ ​certain​ ​income​ ​tax​ ​effects​ ​can​ ​be​ ​reasonably​ ​estimated, registrants must report provisional amounts for those specific income tax effects of the Tax Reform Legislation for which the accounting is incomplete but a reasonable estimate can be determined. Provisional amounts or adjustments to provisional amounts identified in the measurement period, as defined, should be included as an adjustment to tax expense or benefit from continuing operations in the period the amounts are determined; and 3) if measurement​ ​of​ ​certain​ ​income​ ​tax​ ​effects​ ​cannot​ ​be​ ​reasonably estimated, registrants are not required to report provisional amounts for any specific income tax effects of the Tax Reform Legislation for which a reasonable estimate cannot be determined, and would continue to apply ASC 740 – Income Taxes based on the provisions of the tax laws that were in effect immediately prior to the enactment of the Tax Reform Legislation. Registrants would report the provisional amounts of the tax effects of the Tax Reform Legislation in the first reporting period in which a reasonable estimate can be determined. The SEC staff believes that in no circumstances should the measurement period extend beyond December 22, 2018, one year from the enactment of the Tax Reform Legislation.

Additional Financial Statemen27

Additional Financial Statement Information (Tables)	12 Months Ended
	Dec. 31, 2017
Additional Financial Statement Information [Abstract]
Statement of Operations Information	Additional statements of operations information is as follows: Year Ended December 31, (millions) 2017 2016 2015 Production Expense Lease Operating Expense $ 571 $ 542 $ 563 Production and Ad Valorem Taxes 138 78 127 Gathering, Transportation and Processing Expense (1) 432 480 306 Total $ 1,141 $ 1,100 $ 996 Exploration Expense Leasehold Impairment and Amortization (2) $ 62 $ 148 $ 113 Dry Hole Cost 9 579 266 Seismic, Geological and Geophysical 27 76 34 Staff Expense 55 77 43 Other 35 45 32 Total $ 188 $ 925 $ 488 Loss on Marcellus Shale Upstream Divestiture Loss on Sale $ 2,270 $ — $ — Firm Transportation Commitment (2) 93 — — Other (3) 16 — — Total $ 2,379 $ — $ — Other Operating (Income) Expense, Net Marketing Expense (4) $ 47 $ 58 $ 33 Clayton Williams Acquisition Expenses (5) 100 — — Corporate Restructuring Expense (6) — 8 51 Pension Plan Expense (7) — — 88 Impact of Rosetta Merger (8) — (25 ) 81 North Sea Remediation Project Revision (9) (42 ) — — Loss on Asset Due to Terminated Contract (10) — 41 — Gain on Divestitures, Net (11) (326 ) (238 ) — Other, Net 33 53 79 Total $ (188 ) $ (103 ) $ 332 (1) Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense.For the years ended December 31, 2016 and 2015, these costs totaled $17 million and $17 million , respectively, and have been reclassified from other operating expense, net to conform to current presentation. (2) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (3) Expense relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 17. Commitments and Contingencies . (4) Amount includes costs for legal and advisory services and employee severance charges. (5) Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (6) See Note 3. Clayton Williams Energy Acquisition . (7) Expenses are associated with corporate organizational activities. (8) Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss). (9) Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 4. Acquisitions, Divestitures and Merger . (10) See Note 9. Asset Retirement Obligations . (11) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. (12) See Note 4. Acquisitions, Divestitures and Merger .
Balance Sheet Information Table	Additional balance sheet information is as follows: December 31, (millions) 2017 2016 Accounts Receivable, Net Commodity Sales $ 455 $ 403 Joint Interest Billings 207 106 Proceeds Receivable (1) — 40 Other 103 86 Allowance for Doubtful Accounts (17 ) (20 ) Total $ 748 $ 615 Other Current Assets Inventories, Materials and Supplies $ 66 $ 71 Inventories, Crude Oil 16 18 Assets Held for Sale (2) 629 18 Restricted Cash (3) 38 30 Prepaid Expenses and Other Assets, Current 31 23 Total $ 780 $ 160 Other Noncurrent Assets Equity Method Investments $ 305 $ 400 Mutual Fund Investments 57 71 Net Deferred Income Tax Asset 25 — Other Assets, Noncurrent 74 37 Total $ 461 $ 508 Other Current Liabilities Production and Ad Valorem Taxes $ 84 $ 115 Commodity Derivative Liabilities, Current 58 102 Income Taxes Payable 18 53 Asset Retirement Obligations, Current 51 160 Interest Payable 67 76 Compensation and Benefits Payable 98 110 Current Portion of Capital Lease and Other Obligations 61 63 Other Liabilities, Current 141 63 Total $ 578 $ 742 Other Noncurrent Liabilities Deferred Compensation Liabilities, Noncurrent $ 197 $ 218 Asset Retirement Obligations, Noncurrent 824 775 Production and Ad Valorem Taxes 69 47 Marcellus Firm Transportation Commitment, Noncurrent (4) 76 — Other Liabilities, Noncurrent 79 63 Total $ 1,245 $ 1,103 (1) Proceeds relate to the farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 4. Acquisitions, Divestitures and Merger . (2) Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar and Dalit fields, offshore Israel, certain non-strategic assets acquired in the Clayton Williams Energy Acquisition and the CONE investments. Assets held for sale at December 31, 2016 include assets in the Greeley Crescent area of the DJ Basin. See Note 4. Acquisitions, Divestitures and Merger . (3) Balance at December 31, 2017 represents amount held in escrow for the purchase of a midstream entity. Balance at December 31, 2016 represents amount held in escrow for the purchase of certain Delaware Basin properties. See Note 4. Acquisitions, Divestitures and Merger . (4) Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 4. Acquisitions, Divestitures and Merger .
Supplemental Cash Flow Disclosure	Supplemental statements of cash flow information is as follows: Year Ended December 31, (millions) 2017 2016 2015 Cash Paid During the Year For Interest, Net of Amount Capitalized $ 346 $ 327 $ 260 Income Taxes Paid, Net 121 236 202 Non-Cash Financing and Investing Activities Increase in Capital Lease and Other Obligations — 5 55

Clayton Williams Energy Acqui28

Clayton Williams Energy Acquisition (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table sets forth our preliminary purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,876 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,513 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 509 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,817 The fair values of Clayton Williams Energy's identifiable assets are as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 70 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Cost 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 63 Other Property Plant and Equipment 12 Implied Goodwill 1,310 Total Asset Value $ 3,817
Business Acquisition, Pro Forma Information	The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. Year Ended December 31, (millions, except per share amounts) 2017 2016 Revenues $ 4,304 $ 3,651 Net Loss and Comprehensive Loss Attributable to Noble Energy (678 ) (1,082 ) Net Loss Attributable to Noble Energy per Common Share Basic and Diluted $ (1.39 ) $ (2.23 )

Asset Impairments (Tables)

Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Impairment Charges [Abstract]
Asset Impairment Charges Pre Tax (non-cash)	Pre-tax (non-cash) asset impairment charges were as follows: Year Ended December 31, (millions) 2017 2016 2015 Gulf of Mexico $ 63 $ — $ 158 Israel — 88 36 Equatorial Guinea — — 339 Other International 7 4 — Total $ 70 $ 92 $ 533

Capitalized Exploratory Well 30

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)	12 Months Ended
	Dec. 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: Year Ended December 31, (millions) 2017 2016 2015 Capitalized Exploratory Well Costs, Beginning of Period $ 768 $ 1,353 $ 1,337 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 20 84 123 Divestitures and Other (1) — (143 ) — Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) (203 ) (1 ) (19 ) Capitalized Exploratory Well Costs Charged to Expense (3) (65 ) (525 ) (88 ) Capitalized Exploratory Well Costs, End of Period $ 520 $ 768 $ 1,353 (1) The 2016 amount relates to the farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel. The 2015 amount relates primarily to US onshore exploration activity. (3) Capitalized exploratory well costs charged to expense are included within exploration or impairment expense in our consolidated statements of operations.
Aging of Capitalized Well Costs	The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: December 31, (millions) 2017 2016 2015 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 10 $ 69 $ 95 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 510 699 1,258 Balance at End of Period $ 520 $ 768 $ 1,353 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 8 10 14
Aging of Exploratory Well Costs	The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2017 : Suspended Since Country/Project (millions) Total 2015 - 2016 2013 - 2014 2012 & Prior Progress Gulf of Mexico Katmai $ 147 $ 56 $ 91 $ — Progressing a development scenario for this 2014 crude oil discovery. We are currently conducting feasibility and front-end engineering and design studies on host platform options. Offshore Equatorial Guinea Felicita (Block O) 47 3 12 32 Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Yolanda (Block I) 23 1 6 16 A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. Offshore Cameroon YoYo (YoYo Block) 55 4 6 45 A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with both governments to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. In June 2017, we converted our mining concession license for the YoYo block into a PSC. Offshore Israel Leviathan-1 Deep 91 8 10 73 The well did not reach the target interval in 2012. We continue to reprocess and review seismic information for this discovery, based on information obtained from other recent discoveries in the region, and develop future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 32 3 5 24 Our future development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. See also Note 4. Acquisitions, Divestitures and Merger. Offshore Cyprus Cyprus 97 15 52 30 In 2016, we farmed-down a 35% interest in Block 12 and submitted an updated development plan. We continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. During 2017, we submitted an updated development plan, progressed capital project cost improvement and continued regional natural gas marketing efforts. Other Projects less than $20 million 18 (9 ) 21 6 Continuing to assess and evaluate wells. Total $ 510 $ 81 $ 203 $ 226

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity method investments	Equity method investments are as follows: December 31, (millions) 2017 2016 Equity Method Investments CONE Investments (1) $ — $ 172 AMPCO 129 120 Alba Plant 80 82 Advantage Pipeline 70 — Other 26 26 Total Equity Method Investments $ 305 $ 400 (1) CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31, 2017. Summarized, 100% combined financial information for equity method investees is as follows: December 31, (millions) 2017 2016 Balance Sheet Information Current Assets $ 390 $ 313 Noncurrent Assets 588 1,390 Current Liabilities 171 149 Noncurrent Liabilities 90 256 Year Ended December 31, (millions) 2017 2016 2015 Statements of Operations Information Operating Revenues $ 790 $ 667 $ 645 Operating Expenses 303 355 393 Operating Income 487 312 252 Other (Income) Net (15 ) (7 ) (9 ) Income Before Income Taxes 502 319 261 Income Tax Provision 136 60 46 Net Income $ 366 $ 259 $ 215

Derivative Instruments and He32

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unsettled Derivative Instruments	As of December 31, 2017 , we had entered into the following crude oil derivative instruments: 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 2018 Three-Way Collars NYMEX WTI 10,000 $ — $ 45.50 $ 52.50 $ 69.09 2018 Swaps NYMEX WTI 24,000 57.09 — — — 2018 Two-Way Collars NYMEX WTI 18,000 — — 50.42 58.82 2018 Three-Way Collars Dated Brent 3,000 — 40.00 50.00 70.41 2018 Swaps ICE Brent 2,000 59.00 — — — 2018 Two-Way Collars ICE Brent 2,000 — — 50.00 55.25 2018 Three-Way Collars ICE Brent 5,000 — 43.00 50.00 59.50 2018 Basis Swaps (1) 12,000 (0.60 ) — — — 2019 Swaps NYMEX WTI 3,000 55.07 — — — 2019 Swaps ICE Brent 5,000 57.00 — — — 2019 Three-Way Collars ICE Brent 3,000 — 43.00 50.00 64.07 2019 Basis Swaps (1) 12,000 (1.01 ) — — — (1) We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts. As of December 31, 2017 , we had entered into the following natural gas derivative instruments: Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2018 Three-Way Collars NYMEX HH 120,000 $ 2.50 $ 2.88 $ 3.65
Fair Value of Derivative Instruments	The fair values of derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments (1) Asset Derivative Instruments Liability Derivative Instruments December 31, December 31, December 31, December 31, Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value (millions) Commodity Derivative Instruments Current Assets $ 2 Current Assets $ — Current Liabilities $ 58 Current Liabilities $ 102 Noncurrent Assets — Noncurrent Assets — Noncurrent Liabilities 15 Noncurrent Liabilities 14 Total $ 2 $ — $ 73 $ 116 (1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities for a discussion of our netting policy.
Effect of derivative instruments on consolidated statement of operations	The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2017 2016 2015 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (14 ) $ (499 ) $ (844 ) Natural Gas 1 (70 ) (147 ) NGLs (1) — — (18 ) Total Cash Received in Settlement of Commodity Derivative Instruments (13 ) (569 ) (1,009 ) Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil 18 582 423 Natural Gas (68 ) 126 65 NGLs (1) — — 20 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (50 ) 708 508 (Gain) Loss on Commodity Derivative Instruments Crude Oil 4 83 (421 ) Natural Gas (67 ) 56 (82 ) NGLs (1) — — 2 Total (Gain) Loss on Commodity Derivative Instruments $ (63 ) $ 139 $ (501 ) (1) Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	Changes in AROs were as follows: Year Ended December 31, (millions) 2017 2016 Asset Retirement Obligations, Beginning Balance $ 935 $ 989 Liabilities Incurred 94 21 Liabilities Settled (82 ) (120 ) Revision of Estimate (65 ) (3 ) Reclassification to Liabilities Associated with Assets Held for Sale (54 ) — Accretion Expense 47 48 Asset Retirement Obligations, Ending Balance $ 875 $ 935

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Our debt consists of the following: December 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ 230 2.27 % $ — — % Noble Midstream Services Revolving Credit Facility, due September 20, 2021 85 2.49 % — — % Term Loan Facility, due January 6, 2019 (1) — — % 550 2.01 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — Senior Notes, due March 1, 2019 (2) — — % 1,000 8.25 % Senior Notes, due May 1, 2021 379 5.63 % 379 5.63 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % Senior Notes, due June 1, 2022 (1) — — % 18 5.88 % Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % Senior Notes, due January 15, 2028 (2) 600 3.85 % — — % Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % Senior Notes, due August 15, 2047 (2) 500 4.95 % — — % Other Senior Notes and Debentures (3) 92 7.13 % 92 7.13 % Capital Lease and Other Obligations (4) 273 — % 375 — % Total $ 6,859 $ 7,114 Unamortized Discount (24 ) (23 ) Unamortized Premium (2) 12 17 Unamortized Debt Issuance Costs (40 ) (34 ) Total Debt, Net of Discount $ 6,807 $ 7,074 Less Amounts Due Within One Year Capital Lease and Other Obligations (61 ) (63 ) Long-Term Debt Due After One Year $ 6,746 $ 7,011 (1) In fourth quarter 2017, we repaid $550 million of borrowings under the Term Loan Facility and $18 million of our outstanding Senior Notes due June 1, 2022. (2) In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047. (3) Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13% . (4) The reduction from 2016 includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $60 million of capital lease principal payments.
Annual maturities of outstanding debt	Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2017 are as follows: (millions) Debt Principal Payments 2018 $ — 2019 — 2020 230 2021 1,464 2022 — Thereafter 4,892 Total $ 6,586

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Components of Income Before Income Taxes Table	Components of income (loss) from operations before income taxes are as follows: Year Ended December 31, (millions) 2017 2016 2015 Domestic $ (2,831 ) $ (1,859 ) $ (2,338 ) Foreign 640 87 119 Total $ (2,191 ) $ (1,772 ) $ (2,219 )
Components of Income Tax Provision Table	The income tax provision (benefit) consists of the following: Year Ended December 31, (millions) 2017 2016 2015 Current Taxes Federal $ (11 ) $ (4 ) $ (1 ) State 1 5 — Foreign 96 196 107 Total Current $ 86 $ 197 $ 106 Deferred Taxes Federal $ (1,258 ) $ (784 ) $ 216 State (8 ) (24 ) (5 ) Foreign 39 (176 ) (95 ) Total Deferred $ (1,227 ) $ (984 ) $ 116 Total Income Tax (Benefit) Provision Attributable to Noble Energy $ (1,141 ) $ (787 ) $ 222 Effective Tax Rate 52.1 % 44.4 % (10.0 )%
Tax Rate Reconciliation Table	A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, (percentages) 2017 2016 2015 Federal Statutory Rate (1) 35.0 % 35.0 % 35.0 % Effect of Earnings of Equity Method Investees 1.9 1.0 0.6 Noncontrolling Interests 1.1 0.4 — US and Foreign Statutory Rate Change (1) 23.5 1.6 — Transition Tax (1) (4.8 ) — — State Taxes, Net of Federal Benefit 0.3 1.3 0.3 Difference Between US and Foreign Rates 1.8 (0.1 ) 2.6 Foreign Exploration Loss — 0.1 2.7 Change in Valuation Allowance (1) (17.4 ) (2.0 ) — Oil Profits Tax - Israel (0.1 ) — 0.1 Tax Contingency 0.1 0.2 0.4 Accumulated Undistributed Foreign Earnings (1) 11.0 7.2 (37.7 ) Goodwill Impairment — — (12.3 ) Other, Net (0.3 ) (0.3 ) (1.7 ) Effective Rate 52.1 % 44.4 % (10.0 )% (1) See Recent Changes in US Tax Law, above. Rate will decrease to 21.0% for fiscal year 2018. In addition, see discussion regarding accumulated undistributed foreign earnings above.
Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2017 2016 Deferred Tax Assets Loss Carryforwards $ 902 $ 474 Employee Compensation and Benefits 97 150 Mark to Market of Commodity Derivative Instruments 7 44 Foreign Tax Credits 366 — Other 104 49 Total Deferred Tax Assets $ 1,476 $ 717 Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits (549 ) (242 ) Net Deferred Tax Assets $ 927 $ 475 Deferred Tax Liabilities Accumulated Undistributed Foreign Earnings (1) — (240 ) Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (2,029 ) (2,054 ) Total Deferred Tax Liability $ (2,029 ) $ (2,294 ) Net Deferred Tax Liability $ (1,102 ) $ (1,819 ) (1) At December 31, 2017, we reversed the deferred tax liability associated with the removal of the assertion of indefinitely reinvested earnings, resulting in recognition of a deferred tax benefit of $240 million .
Deferred Tax Liability Balance Sheet Classifcation	Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2017 2016 Deferred Income Tax Asset - Noncurrent $ 25 $ — Deferred Income Tax Liability - Noncurrent (1,127 ) (1,819 ) Net Deferred Tax Liability $ (1,102 ) $ (1,819 )
Schedule of Unrecognized Tax Benefits	A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows: (millions) Twelve Months Ended December 31, 2017 Unrecognized Tax Benefits, Beginning Balance $ 3 Reductions for Tax Positions of Prior Years (3 ) Unrecognized Tax Benefits, Ending Balance $ —

Stock-Based and Other Compens36

Stock-Based and Other Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation expense	We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2017 2016 2015 Stock-Based Compensation Expense Included in: General and Administrative Expense $ 56 $ 62 $ 50 Exploration Expense and Other 48 15 36 Total Stock-Based Compensation Expense $ 104 $ 77 $ 86 Tax Benefit Recognized $ (36 ) $ (27 ) $ (30 )
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of components for Rabbi Trust	Components of that rabbi trust are as follows: December 31, (millions, except share amounts) 2017 2016 Rabbi Trust Assets Mutual Fund Investments $ 57 $ 62 Noble Energy Common Stock (at Fair Value) 14 26 Total Rabbi Trust Assets $ 71 $ 88 Liability Under Related Deferred Compensation Plan $ 71 $ 88 Number of Shares of Noble Energy Common Stock Held by Rabbi Trust 470,030 671,269
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2017 2016 2015 Expected Term (in Years) 6.4 6.3 6.0 Expected Volatility 33.2 % 32.4 % 32.6 % Risk-Free Rate 2.2 % 1.6 % 1.4 % Expected Dividend Yield 0.9 % 0.7 % 1.2 % Weighted Average Grant-Date Fair Value $ 13.26 $ 10.10 $ 13.93
Share-based Compensation Awards	Stock option activity was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (in years) (in millions) Outstanding at December 31, 2016 15,088,862 $ 43.49 Granted 1,819,819 39.40 Exercised (382,882 ) 37.57 Forfeited (976,577 ) 43.93 Outstanding at December 31, 2017 15,549,222 $ 43.42 5.0 $ 6 Exercisable at December 31, 2017 12,101,890 $ 44.98 4.0 $ 6
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2017 2016 2015 Number of Simulations 500,000 500,000 500,000 Expected Volatility 35 % 38 % 30 % Risk-Free Rate 1.5 % 1.0 % 0.8 %
Share-based Compensation Awards	Restricted stock activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Shares Weighted Average Award Date Fair Value Number of Shares Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2016 1,371,780 $ 36.37 1,502,992 $ 27.43 Awarded (1) 3,201,504 36.26 464,608 24.25 Vested (1) (2,515,383 ) 34.93 (219,883 ) 44.61 Forfeited (218,164 ) 37.66 (535,012 ) 33.12 Outstanding at December 31, 2017 1,839,737 $ 37.21 1,212,705 $ 25.55 (1) During 2017, we awarded approximately 1.9 million shares of restricted stock for the conversion of Clayton Williams Energy shares into Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are included in the above table. See Note 3. Clayton Williams Energy Acquisition .
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Awards	Phantom unit activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Units Weighted Number of Units Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2016 712,089 $ 31.65 209,504 $ 6.82 Vested (13,305 ) 31.65 — — Forfeited (88,625 ) 31.65 (42,021 ) 6.82 Outstanding at December 31, 2017 610,159 $ 31.65 167,483 $ 6.82

Fair Value Measurements and D37

Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Assets and liabilities measured at fair value on a 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 (millions) Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Adjustment (2) Fair Value Measurement December 31, 2017 Financial Assets Mutual Fund Investments $ 57 $ — $ — $ — $ 57 Commodity Derivative Instruments — 7 — (5 ) 2 Financial Liabilities Commodity Derivative Instruments — (78 ) — 5 (73 ) Portion of Deferred Compensation Liability Measured at Fair Value (71 ) — — — (71 ) 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) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents the impact of netting clauses 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 noncurring basis	Information about the impaired assets is as follows: Fair Value Measurements Using Description Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Net Book Value (2) Total Pre-tax (Non-cash) Impairment Loss (millions) Year Ended December 31, 2017 Impaired Oil and Gas Properties $ — $ — $ — $ 70 $ 70 Year Ended December 31, 2016 Impaired Oil and Gas Properties — — — 92 92 Impaired Materials and Supplies Inventory — — 91 105 14 Year Ended December 31, 2015 Impaired Oil and Gas Properties — — 752 1,285 533 Impaired Materials and Supplies Inventory — — 61 81 20 (1) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents net book value at the date of assessment.
Additional fair value disclosures	Fair value information regarding our debt is as follows: December 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,586 $ 7,142 $ 6,739 $ 7,112 (1) Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Prior period amounts are presented on a comparable basis. Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2017 Oil, NGL and Gas Sales from Third Parties (2) $ 4,060 $ 3,156 $ 534 $ 370 $ — $ — $ — $ — Income from Equity Method Investees and Other (3) 196 — — 120 — 76 — — Intersegment Revenues — — — — — 277 (277 ) — Total Revenues 4,256 3,156 534 490 — 353 (277 ) — Lease Operating Expense 571 466 29 90 — — (14 ) — Production and Ad Valorem Taxes 138 135 — — — 3 — — Gathering, Transportation and Processing Expense 432 550 — — — 70 (188 ) — Total Production Expense 1,141 1,151 29 90 — 73 (202 ) — DD&A 2,053 1,739 76 146 4 30 (5 ) 63 Clayton Williams Energy Acquisition Expenses 100 100 — — — — — — Loss on Debt Extinguishment 98 — — — — — — 98 Loss on Marcellus Shale Upstream Divestiture 2,379 2,379 — — — — — — Asset Impairments 70 63 — — 7 — — — Gain on Commodity Derivative Instruments (63 ) (92 ) — 29 — — — — (Loss) Income Before Income Taxes (2,191 ) (2,365 ) 413 203 (54 ) 233 (62 ) (559 ) Equity Method Investments 305 — — 225 — 80 — — Additions to Long Lived Assets 2,851 1,994 411 34 (34 ) 423 (79 ) 102 Goodwill (4) 1,310 1,310 — — — — — — Total Assets at End of Year (5) 21,476 15,767 2,846 1,308 114 1,357 (163 ) 247 Year Ended December 31, 2016 Oil, NGL and Gas Sales from Third Parties (2) $ 3,389 $ 2,416 $ 540 $ 433 $ — $ — $ — $ — Income from Equity Method Investees and Other 102 — — 50 — 52 — — Intersegment Revenues — — — — — 200 (200 ) — Total Revenues 3,491 2,416 540 483 — 252 (200 ) — Lease Operating Expense 542 418 37 105 — — (18 ) — Production and Ad Valorem Taxes 78 76 — — — 2 — — Gathering, Transportation and Processing Expense 480 564 — — — 44 (128 ) — Total Production Expense 1,100 1,058 37 105 — 46 (146 ) — DD&A 2,454 2,103 81 205 6 19 — 40 Asset Impairments 92 — 88 — 4 — — — Loss on Commodity Derivative Instruments 139 126 — 13 — — — (Loss) Income Before Income Taxes (1,772 ) (1,277 ) 543 (338 ) (199 ) 176 (51 ) (626 ) Equity Method Investments 400 — — 217 — 183 — — Additions to Long Lived Assets 1,526 1,353 88 54 (6 ) 58 (53 ) 32 Total Assets at End of Year (5) 21,011 16,153 2,233 1,479 89 851 (98 ) 304 Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2015 Oil, NGL and Gas Sales from Third Parties (2) $ 3,093 $ 2,011 $ 497 $ 580 $ 5 $ — $ — $ — Income from Equity Method Investees and Other 90 — — 39 — 51 — — Intersegment Revenues — — — — — 119 (119 ) — Total Revenues 3,183 2,011 497 619 5 170 (119 ) — Lease Operating Expense 563 398 42 131 4 — (12 ) — Production and Ad Valorem Taxes 127 126 — — — 1 — — Gathering, Transportation and Processing Expense 306 366 — — — 25 (85 ) — Total Production Expense 996 890 42 131 4 26 (97 ) — DD&A 2,131 1,677 70 326 — 14 — 44 Asset Impairments 533 158 36 339 — — — — Gain on Commodity Derivative Instruments (501 ) (347 ) — (154 ) — — — — (Loss) Income Before Income Taxes (2,219 ) (1,693 ) 313 (90 ) (229 ) 123 (21 ) (622 ) Equity Method Investments 453 — — 227 — 226 — — Additions to Long Lived Assets 3,062 2,409 147 124 177 146 (21 ) 80 Total Assets at End of Year (5) 24,196 18,043 2,676 2,299 205 799 (46 ) 220 (1) Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. (2) Revenues from third parties for all foreign countries, in total, were $904 million in 2017, $973 million in 2016, and $1.1 billion in 2015. (3) The midstream segment includes revenues of $19 million from third party customers. (4) Goodwill is associated with the Texas reporting unit. See Note 1. Summary of Significant Accounting Policies . (5) Long-lived assets located in all foreign countries, in total, were $2.8 billion , $3.0 billion , and $3.9 billion at December 31, 2017, 2016, and 2015, respectively.

Concentration of Risk (Tables)

Concentration of Risk (Tables)	12 Months Ended
	Dec. 31, 2017
Concentration of Risk [Abstract]
Schedules of Concentration of Risk, by Risk Factor	The largest single non-affiliated purchasers of our production were as follows: Percentage of Crude Oil Sales Percentage of Total Oil, Gas & NGL Sales Year Ended December 31, 2017 BP (1) 15 % 10 % Shell (2) 22 % 13 % Year Ended December 31, 2016 Glencore Energy UK Ltd 22 % 12 % Shell (2) 24 % 13 % Year Ended December 31, 2015 Glencore Energy UK Ltd 30 % 18 % Shell (2) 18 % 11 % (1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company. (2) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited.

Additional Shareholders' Equi40

Additional Shareholders' Equity Information (Tables)	12 Months Ended
	Dec. 31, 2017
Additional Shareholders' Equity Information [Abstract]
Schedule Of Activity In Shares Of Common And Treasury Stock	Activity in shares of our common stock and treasury stock was as follows: Year Ended December 31, 2017 2016 Common Stock Shares Issued Shares, Beginning of Period 471,360,427 469,718,512 Exercise of Common Stock Options 382,882 954,898 Restricted Stock Awarded, Net of Forfeitures (1) 2,912,936 687,017 Shares Exchanged in Clayton Williams Energy Acquisition 54,087,136 — Shares, End of Period 528,743,381 471,360,427 Treasury Stock Shares, Beginning of Period 37,961,316 37,925,625 Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (2) 1,026,891 236,700 Rabbi Trust Shares Distributed and/or Sold (201,238 ) (201,009 ) Shares, End of Period 38,786,969 37,961,316 Additional Information Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (2) — — Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Loss per Share 15,619,276 14,218,319 (1) The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. See Note 3. Clayton Williams Energy Acquisition . (2) The 2017 amount includes approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale agreement. (3) For the years ended December 31, 2017 and 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive.
Accumulated other comprehensive income (loss) in the shareholders' equity section of the balance sheet	AOCL in the shareholders’ equity section of the balance sheet included: Accumulated Other Comprehensive Loss (millions) Interest Rate Cash Flow Hedges Pension- Related and Other Total December 31, 2014 $ (23 ) $ (67 ) $ (90 ) Realized Amounts Reclassified Into Earnings 1 62 63 Unrealized Change in Fair Value — (6 ) (6 ) December 31, 2015 (22 ) (11 ) (33 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (3 ) (3 ) December 31, 2016 (21 ) (10 ) (31 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (4 ) (4 ) December 31, 2017 $ (20 ) $ (10 ) $ (30 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments	Minimum commitments as of December 31, 2017 consist of the following: (millions) Drilling, Equipment, and Purchase Obligations Transportation and Gathering Obligations Operating Lease Obligations Capital Lease and Other Obligations (1) Total 2018 $ 636 $ 215 $ 44 $ 74 $ 969 2019 167 252 33 45 497 2020 40 247 32 42 361 2021 13 223 32 29 297 2022 8 182 33 21 244 2023 and Thereafter 32 1,355 156 124 1,667 Total $ 896 $ 2,474 $ 330 $ 335 $ 4,035 (1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt .

Summary of Significant Accoun42

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 30, 2015
Property, Plant and Equipment [Line Items]
Total capitalized interest	$ 49,000,000	$ 84,000,000	$ 144,000,000
Goodwill	1,310,000,000	0		$ 779,000,000
Goodwill Impairment	$ 0	$ 0	779,000,000
Goodwill allocation			4,000,000
Goodwill fair value			0
Rosetta Merger
Property, Plant and Equipment [Line Items]
Acquired goodwill			$ 163,000,000
Minimum
Property, Plant and Equipment [Line Items]
Useful lives of gathering facilitates and processing plants (in years)	3 years
Maximum
Property, Plant and Equipment [Line Items]
Useful lives of gathering facilitates and processing plants (in years)	30 years

Additional Financial Statemen43

Additional Financial Statement Information (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Production Expense
Lease Operating Expense			$ 571	$ 542	$ 563
Production and Ad Valorem Taxes			138	78	127
Gathering, Transportation and Processing Expense			432	480	306
Total			1,141	1,100	996
Exploration Expense
Leasehold Impairment and Amortization			62	148	113
Dry Hole Cost			9	579	266
Seismic, Geological and Geophysical			27	76	34
Staff Expense			55	77	43
Other			35	45	32
Exploration Expense			188	925	488
Loss on Marcellus Shale Upstream Divestiture
Loss on Sale			2,270	0	0
Firm Transportation Commitment			93	0	0
Other			16	0	0
Total			2,379	0	0
Other Operating (Income) Expense, Net
Marketing Expense			47	58	33
Clayton Williams Acquisition Expenses			100	0	0
Corporate Restructuring Expense			0	8	51
Pension Plan Expense			0	0	88
Impact of Rosetta Merger			0	(25)	81
North Sea Remediation Project Revision			(42)	0	0
Loss on Asset Due to Terminated Contract			0	41	0
Gain (loss) on disposition of assets			(326)	(238)	0
Other, Net			33	53	79
Total			(188)	(103)	332
Accounts Receivable, Net
Commodity Sales			455	403
Joint Interest Billings			207	106
Proceeds Receivable			0	40
Other			103	86
Allowance for Doubtful Accounts			(17)	(20)
Total			748	615
Other Current Assets
Inventories, Materials and Supplies			66	71
Inventories, Crude Oil			16	18
Assets Held for Sale			629	18
Restricted Cash			38	30
Prepaid Expenses and Other Assets, Current			31	23
Total			780	160
Other Noncurrent Assets
Equity Method Investments			305	400	$ 453
Mutual Fund Investments			57	71
Net Deferred Income Tax Asset			25	0
Other Assets, Noncurrent			74	37
Total			461	508
Other Current Liabilities
Production and Ad Valorem Taxes			84	115
Commodity Derivative Liabilities, Current			58	102
Income Taxes Payable			18	53
Asset Retirement Obligations, Current			51	160
Interest Payable			67	76
Compensation and Benefits Payable			98	110
Current Portion of Capital Lease and Other Obligations			61	63
Other Liabilities, Current			141	63
Total			578	742
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent			197	218
Asset Retirement Obligations, Noncurrent			824	775
Production and Ad Valorem Taxes			69	47
Marcellus Firm Transportation Commitment, Noncurrent			76	0
Other Liabilities, Noncurrent			79	63
Total			$ 1,245	$ 1,103
Ownership interest sold			35.00%	35.00%
Tamar and Dalit Fields
Other Noncurrent Liabilities
Ownership interest			7.50%
Adjustment | Gathering, Transportation and Processing Expense
Other Operating (Income) Expense, Net
Total	$ 17	$ 17

Additional Financial Statemen44

Additional Financial Statement Information (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Paid During the Year For
Interest, Net of Amount Capitalized	$ 346	$ 327	$ 260
Income Taxes Paid, Net	121	236	202
Non-Cash Financing and Investing Activities
Increase in Capital Lease and Other Obligations	$ 0	$ 5	$ 55

Clayton Williams Energy Acqui45

Clayton Williams Energy Acquisition - Narrative (Details) $ / shares in Units, a in Thousands, $ in Millions	Apr. 24, 2017USD ($)a$ / sharesshares	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)ashares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Jun. 30, 2017USD ($)	Dec. 30, 2015USD ($)
Business Acquisition [Line Items]
Stock issued (shares) | shares				54,087,136	0
Cash paid				$ 616	$ 0	$ 0
Clayton Williams Acquisition Expenses				100	0	$ 0
Goodwill			$ 1,310	1,310	0			$ 779
Revenue since acquisition		$ 181			457
Pre-tax loss since acquisition		$ (120)			$ (20)
Clayton Williams Energy
Business Acquisition [Line Items]
Clayton Williams Acquisition Expenses				23
Clayton Williams Energy
Business Acquisition [Line Items]
Stock issued (shares) | shares	56,000,000
Fair value of common stock issued	$ 1,876
Cash paid	637
Consideration transferred	$ 2,513
Share price ($ per share) | $ / shares	$ 34.17
Long-term line of credit							$ 1,300
Clayton Williams Acquisition Expenses				100
Severance, consulting, investment, advisory, legal, and other merger related fees				64
Noncash share-based compensation expense				$ 36
Treasury stock redeemed (in shares) | shares				720,000
Consideration transferred, treasury stock				$ 25
Long-term debt acquired	$ 595
Goodwill	$ 1,310		1,300	$ 1,300
Revenue since acquisition			99
Pre-tax loss since acquisition			$ 19
Clayton Williams Energy | Delaware Basin
Business Acquisition [Line Items]
Gas and oil area acquired | a	71
Additional gas and oil area acquired | a	117
Clayton Williams Energy | Permian
Business Acquisition [Line Items]
Gas and oil area acquired | a	100
Clayton Williams Energy | Texas
Business Acquisition [Line Items]
Gas and oil area acquired | a				64

Clayton Williams Energy Acqui46

Clayton Williams Energy Acquisition - Purchase Price Allocation (Details) - USD ($) $ in Millions	Apr. 24, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders		$ 616	$ 0	$ 0
Clayton Williams Energy
Business Acquisition [Line Items]
Fair value of common stock issued	$ 1,876
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders	637
Total purchase price	2,513
Accounts Payable	99
Other Current Liabilities	38
Long-Term Deferred Tax Liability	509
Long-Term Debt	595
Asset Retirement Obligation	63
Total purchase price plus liabilities assumed	$ 3,817

Clayton Williams Energy Acqui47

Clayton Williams Energy Acquisition - Fair Value of Acquired Assets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Apr. 24, 2017	Dec. 31, 2016	Dec. 30, 2015
Business Acquisition [Line Items]
Goodwill	$ 1,310		$ 0	$ 779
Clayton Williams Energy
Business Acquisition [Line Items]
Cash and Equivalents		$ 21
Other Current Assets		70
Proved Reserves		722
Undeveloped Leasehold Cost		1,571
Gathering and Processing Assets		48
Asset Retirement Costs		63
Other Property Plant and Equipment		12
Goodwill	$ 1,300	1,310
Total Asset Value		$ 3,817

Clayton Williams Energy Acqui48

Clayton Williams Energy Acquisition - Pro Forma Information (Details) - Clayton Williams Energy - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenues	$ 4,304	$ 3,651
Net Loss and Comprehensive Loss Attributable to Noble Energy	$ (678)	$ (1,082)
Net Loss Attributable to Noble Energy per Common Share - Basic and Diluted (in dollars per share)	$ (1.39)	$ (2.23)

Acquisitions, Divestitures an49

Acquisitions, Divestitures and Merger - Narrative (Details)	Jan. 31, 2018USD ($)abbl / dmibbl	Jan. 29, 2018USD ($)shares	Jun. 28, 2017USD ($)payment$ / MMBTU	Jun. 26, 2017USD ($)ashares	Apr. 03, 2017USD ($)bbl / dmibbl	Jul. 20, 2015USD ($)abusinessshares	Jan. 31, 2018USD ($)	Jan. 31, 2017USD ($)well	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)aMMcf / dshares	Dec. 31, 2016USD ($)ashares	Dec. 31, 2015USD ($)	Feb. 15, 2018USD ($)	Jan. 28, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds											$ 2,073,000,000	$ 1,241,000,000	$ 151,000,000
Loss on Marcellus Shale Upstream Divestiture											2,379,000,000	$ 0	0
Exit costs											41,000,000
Commitment to third party for assumption of retained capacity											$ 52,000,000
Ownership interest sold									35.00%		35.00%	35.00%
Asset retirement obligation									$ 935,000,000	$ 989,000,000	$ 875,000,000	$ 935,000,000	989,000,000
Gain (loss) on disposition of assets											326,000,000	238,000,000	0
Cash paid											616,000,000	0	0
Equity Method Investments									400,000,000	453,000,000	$ 305,000,000	$ 400,000,000	453,000,000
Stock issued (shares) | shares											54,087,136	0
Proceeds from issuance of common limited partners units											$ 312,000,000	$ 299,000,000	0
Proceeds from debt											325,000,000	0	0
Gain (loss) on divestitures											326,000,000	238,000,000	0
Severance, consulting, investment, advistory, legal and other related merger-related fees											100,000,000	0	$ 0
Revenue since acquisition										181,000,000		457,000,000
Pre-tax loss since acquisition										120,000,000		20,000,000
Purchase price allocation adjustment										$ 163,000,000		$ 25,000,000
Marcellus Shale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value			$ 1,200,000,000
Sales Proceeds			1,000,000,000
Consideration adjustment			$ 100,000,000
Additional consideration, number of payments, divestiture | payment			3
Additional consideration, Individual payment amounts			$ 33,300,000
Minimum Appalachia Dominion, South Point index price for contingent consideration to be required ($ per MMBtu) | $ / MMBTU			3.30
Loss on Marcellus Shale Upstream Divestiture											2,400,000,000
Loss on sale of property, after tax											$ 1,500,000,000
Asset consideration			$ 3,400,000,000
Natural gas production per day | MMcf / d											204
Southwest Royalties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity method investment, amount sold											$ 102,000,000
Asset retirement obligation											42,000,000
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses											671,000,000
Proceeds expected from divestiture											40,000,000
DJ Basin (Onshore US)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses											568,000,000
Mineral and Royalty Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds											335,000,000
Gain (loss) on disposition of assets											$ 334,000,000
Mineral and royalty assets, area | a											140,000
CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage											50.00%
Equity Method Investments											$ 181,000,000
CONSOL Carried Cost Obligation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash remitted									213,000,000
Wells Ranch Development Area
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Land exchanged (acres) | a												11,700
Bronco Development Area
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Land sold (acres) | a												13,500
Tamar Field, Offshore Israel
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value									$ 431,000,000			$ 431,000,000
Sales Proceeds												$ 316,000,000
Ownership interest sold									3.50%			3.50%
Gain (loss) on divestitures												$ 261,000,000
Ownership percentage required per agreement									25.00%			25.00%
Delaware Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of wells | well								7
Consideration transferred								$ 301,000,000
Proceeds allocated to undeveloped leasehold cost								246,000,000
Cash paid									$ 30,000,000
Rosetta Resources, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock issued (shares) | shares						41,000,000
Number of businesses acquired | business						2
Merger-related costs incurred						$ 81,000,000
Severance, consulting, investment, advistory, legal and other related merger-related fees						66,000,000
Noncash share-based compensation expense						$ 15,000,000
Common Stock | Rosetta Resources, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business combination, stock exchange ratio						0.542
Delaware Basin Area | Rosetta Resources, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gas and oil area acquired | a						45,000
Midland Basin | Rosetta Resources, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gas and oil area acquired | a						9,000
Long-term debt, fair value						$ 2,000,000,000
Eagle Ford Shale | Rosetta Resources, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gas and oil area acquired | a						50,000
Delaware Basin | Rosetta Resources, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gas and oil area acquired | a						54,000
Noble Midstream Partners LP | Blanco River DevCo
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest acquired				15.00%
Ownership interest acquired, step acquisition				40.00%
Noble Midstream Partners LP | Colorado River DevCo
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest acquired				20.00%
Noble Midstream Partners LP | Blanco River and Colorado River DevCos
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred				$ 270,000,000
Noble Midstream Partners LP | Advantage Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred					$ 133,000,000
Ownership percentage					50.00%
Length of pipeline | mi					70
Shipping capacity per day (bbls/day) | bbl / d					150
Storage capacity (bbls) | bbl					490
Noble Midstream Partners LP | Black Diamond Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest											54.40%
Subsequent Event | Southwest Royalties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses							$ 60,000,000
Subsequent Event | CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses							$ 308,000,000
Subsequent Event | Gulf of Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value														$ 480,000,000
Asset consideration														750,000,000
Obligations divested														$ 230,000,000
Subsequent Event | Noble Midstream Partners LP | Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Length of pipeline | mi	160
Shipping capacity per day (bbls/day) | bbl / d	300
Storage capacity (bbls) | bbl	210
Gas and oil area acquired | a	141,000
Subsequent Event | Black Diamond Gathering LLC | Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash paid	$ 638,500,000
Tamar and Dalit Fields | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest in equity method investments		25.00%													32.50%
CNX Midstream Partners
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investment, net book value											$ 70,000,000
Owned (shares) | shares											21,700,000
Ownership											33.50%
Advantage Joint Venture
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to acquire interest in joint venture					$ 67,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Producing and Undeveloped Net Acres in the DJ Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds												$ 486,000,000
Land sold (acres) | a												33,100
Consideration expected									505,000,000			$ 505,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Bowdoin Property
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds												152,000,000
Gain (loss) on divestitures												(23,000,000)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Alon A And Alon C
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value									73,000,000			73,000,000
Consideration adjustment												6,000,000
Asset consideration									$ 67,000,000			$ 67,000,000
Ownership interest sold									47.00%			47.00%
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Cyprus Block 12
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses								$ 40,000,000				$ 131,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Subsequent Event | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest sold		7.50%
Proceeds from sale of ownership interest		$ 560,000,000
Shares received in divestiture of interest in equity method investment (in shares) | shares		38,500,000
Disposal Group, Held-for-sale, Not Discontinued Operations | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investment, net book value											$ 293,000,000
Leaseholds and Leasehold Improvements | Marcellus Shale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset consideration			$ 883,000,000
Subsidiaries | Blanco River and Colorado River DevCos
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred				270,000,000
Cash paid				$ 245,000,000
Developed gas and oil area | a				111,000
Stock issued (shares) | shares				562,430
Proceeds from issuance of common limited partners units				$ 138,000,000
Proceeds from debt				$ 90,000,000

Asset Impairments - Pre-tax (No

Asset Impairments - Pre-tax (Non-Cash) Asset Impairment Charges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments	$ 70	$ 92	$ 533
Gulf of Mexico
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments	63	0	158
Israel
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments	0	88	36
Equatorial Guinea
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments	0	0	339
Other International
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments	$ 7	$ 4	$ 0

Asset Impairments - Narrative (

Asset Impairments - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments		$ 70	$ 92	$ 533
Other (Onshore US)
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments				481
Gulf of Mexico and Eastern Mediterranean
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments				47
Abandonment and Other Costs
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments				$ 5
Leviathan-1 Deep
Impaired Long-Lived Assets Held and Used [Line Items]
Asset Impairments	$ 88

Capitalized Exploratory Well 52

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Exploratory Well Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)project	Dec. 31, 2016USD ($)project	Dec. 31, 2015USD ($)project
Exploratory Wells Drilled [Line Items]
Ownership interest sold				35.00%	35.00%
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized Exploratory Well Costs, Beginning of Period	$ 768	$ 1,353	$ 1,337
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	20	84	123
Divestitures and Other	0	(143)	0
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale	(203)	(1)	(19)
Capitalized Exploratory Well Costs Charged to Expense	(65)	(525)	(88)
Capitalized Exploratory Well Costs, End of Period	520	768	1,353
Exploratory Well Costs Capitalized for a Period of One Year or Less				$ 10	$ 69	$ 95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				510	699	1,258
Capitalized Exploratory Well Costs	$ 768	$ 1,353	$ 1,337	$ 520	$ 768	$ 1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project				8	10	14
Cyprus Block 12
Exploratory Wells Drilled [Line Items]
Ownership interest sold				35.00%

Capitalized Exploratory Well 53

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Exploratory Well Costs (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	$ 510	$ 699	$ 1,258
Ownership interest sold	35.00%	35.00%
Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	$ 81
Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	203
Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	226
Katmai
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	147
Katmai | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	56
Katmai | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	91
Katmai | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	0
Felicita (Block O)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	47
Felicita (Block O) | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	3
Felicita (Block O) | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	12
Felicita (Block O) | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	32
Yolanda (Block I)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	23
Yolanda (Block I) | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	1
Yolanda (Block I) | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	6
Yolanda (Block I) | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	16
YoYo (YoYo Block)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	55
YoYo (YoYo Block) | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	4
YoYo (YoYo Block) | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	6
YoYo (YoYo Block) | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	45
Leviathan-1 Deep
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	91
Leviathan-1 Deep | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	8
Leviathan-1 Deep | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	10
Leviathan-1 Deep | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	73
Dalit
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	32
Dalit | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	3
Dalit | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	5
Dalit | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	24
Cyprus
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	97
Cyprus | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	15
Cyprus | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	52
Cyprus | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	30
Projects less than $20 million
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	18
Projects less than $20 million | Suspended Since 2015 and 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	(9)
Projects less than $20 million | Suspended Since 2013 and 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	21
Projects less than $20 million | Suspended Since 2012 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	$ 6
Cyprus Block 12
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Ownership interest sold	35.00%

Capitalized Exploratory Well 54

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	$ 2,800
Impairment of Leasehold	62	$ 93	$ 21
Gulf of Mexico
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	44
International
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	53
Clayton Williams Energy | Delaware Basin
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	1,600
Rosetta Merger | Delaware Basin
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	1,100
Rosetta Merger | Eagle Ford Shale
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	$ 149

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 400	$ 305	$ 400	$ 453
Equity Method Investment, Financial Statement, Reported Amounts [Abstract]
Retained earnings related to undistributed earnings of equity method investees		90
AMPCO Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
Difference between the carrying value of an equity method investment and the underlying net assets of the investee		12
Balance Sheet Information
Current Assets	313	390	313
Noncurrent Assets	1,390	588	1,390
Current Liabilities	149	171	149
Noncurrent Liabilities	256	90	256
Statements of Operations Information
Operating Revenues		790	667	645
Operating Expenses		303	355	393
Operating Income		487	312	252
Other (Income) Net		(15)	(7)	(9)
Income Before Income Taxes		502	319	261
Income Tax Provision		136	60	46
Net Income		$ 366	259	$ 215
Advantage Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership interest in equity method investments		50.00%
Equity Method Investments	0	$ 70	0
CONE Investments
Schedule of Equity Method Investments [Line Items]
Ownership interest in equity method investments		50.00%
Distributions from equity method investments	70
Equity Method Investments	172	$ 0	172
CONE Midstream
Schedule of Equity Method Investments [Line Items]
Ownership interest in equity method investments		34.00%
Atlantic Methanol Production Company
Schedule of Equity Method Investments [Line Items]
Ownership interest in equity method investments		45.00%
Alba Plant
Schedule of Equity Method Investments [Line Items]
Ownership interest in equity method investments		28.00%
Equity Method Investments	82	$ 80	82
AMPCO
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	120	129	120
Other
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 26	$ 26	$ 26

Derivative Instruments and He56

Derivative Instruments and Hedging Activities - Derivative Instruments Summary (Details)	Dec. 31, 2017bbl / dMMBTU / d$ / MMBTU$ / bbl
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2018
Derivative [Line Items]
Volume 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 | Swaps - NYMEX WTI 2018
Derivative [Line Items]
Volume Per Day | bbl / d	24,000
Weighted Average Fixed Price	57.09
Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2018
Derivative [Line Items]
Volume Per Day | bbl / d	18,000
Weighted Average Floor Price	50.42
Weighted Average Ceiling Price	58.82
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2018
Derivative [Line Items]
Volume Per Day | bbl / d	3,000
Weighted Average Short Put Price	40
Weighted Average Floor Price	50
Weighted Average Ceiling Price	70.41
Crude Oil Commodity Contract | Swaps - ICE Brent 2018
Derivative [Line Items]
Volume Per Day | bbl / d	2,000
Weighted Average Fixed Price	59
Crude Oil Commodity Contract | Two Way Collars - ICE Brent 2018
Derivative [Line Items]
Volume Per Day | bbl / d	2,000
Weighted Average Floor Price	50
Weighted Average Ceiling Price	55.25
Crude Oil Commodity Contract | Three Way Collars - ICE Brent 2018
Derivative [Line Items]
Volume Per Day | bbl / d	5,000
Weighted Average Short Put Price	43
Weighted Average Floor Price	50
Weighted Average Ceiling Price	59.50
Crude Oil Commodity Contract | Basic Swap 2018
Derivative [Line Items]
Volume Per Day | bbl / d	12,000
Weighted Average Fixed Price	(0.60)
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2019
Derivative [Line Items]
Volume Per Day | bbl / d	3,000
Weighted Average Fixed Price	55.07
Crude Oil Commodity Contract | Swaps - ICE Brent 2019
Derivative [Line Items]
Volume Per Day | bbl / d	5,000
Weighted Average Fixed Price	57
Crude Oil Commodity Contract | Three Way Collar - ICE Brent 2019
Derivative [Line Items]
Volume Per Day | bbl / d	3,000
Weighted Average Short Put Price	43
Weighted Average Floor Price	50
Weighted Average Ceiling Price	64.07
Crude Oil Commodity Contract | Basic Swap 2019
Derivative [Line Items]
Volume Per Day | bbl / d	12,000
Weighted Average Fixed Price	(1.01)
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2018
Derivative [Line Items]
Volume Per Day | MMBTU / d	120,000
Weighted Average Short Put Price | $ / MMBTU	2.50
Weighted Average Floor Price | $ / MMBTU	2.88
Weighted Average Ceiling Price | $ / MMBTU	3.65

Derivative Instruments and He57

Derivative Instruments and Hedging Activities - Fair Value and Effect on Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Cash Received (Paid) In Settlement Of Derivative Instruments Not Designated As Hedging Instruments	$ (13)	$ (569)	$ (1,009)
Asset Derivative Instruments	2	0
Liability Derivative Instruments	73	116
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(50)	708	508
Total (Gain) Loss on Commodity Derivative Instruments	(63)	139	(501)
Crude Oil
Derivatives, Fair Value [Line Items]
Cash Received (Paid) In Settlement Of Derivative Instruments Not Designated As Hedging Instruments	(14)	(499)	(844)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	18	582	423
Total (Gain) Loss on Commodity Derivative Instruments	4	83	(421)
Natural Gas
Derivatives, Fair Value [Line Items]
Cash Received (Paid) In Settlement Of Derivative Instruments Not Designated As Hedging Instruments	1	(70)	(147)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(68)	126	65
Total (Gain) Loss on Commodity Derivative Instruments	(67)	56	(82)
Natural Gas Liquids
Derivatives, Fair Value [Line Items]
Cash Received (Paid) In Settlement Of Derivative Instruments Not Designated As Hedging Instruments	0	0	(18)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	0	0	20
Total (Gain) Loss on Commodity Derivative Instruments	0	0	$ 2
Current Assets
Derivatives, Fair Value [Line Items]
Asset Derivative Instruments	2	0
Current Liabilities
Derivatives, Fair Value [Line Items]
Liability Derivative Instruments	58	102
Noncurrent Assets
Derivatives, Fair Value [Line Items]
Asset Derivative Instruments	0	0
Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Liability Derivative Instruments	$ 15	$ 14

Asset Retirement Obligations -

Asset Retirement Obligations - Change in AROs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance	$ 935	$ 989
Liabilities Incurred	94	21
Liabilities Settled	(82)	(120)
Revision of Estimate	(65)	(3)
Reclassification to Liabilities Associated with Assets Held for Sale	(54)	0
Accretion Expense	47	48
Asset Retirement Obligations, Ending Balance	$ 875	$ 935

Asset Retirement Obligations 59

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Incurred	$ 94	$ 21
Liabilities Settled	82	120
Revision of Estimate	(65)	(3)
Reclassification to Liabilities Associated with Assets Held for Sale	54	0
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	43	49
Greeley Crescent DJ Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	19
Marcellus Shale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	12
Other Offshore International and US Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	8
North Sea
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		1
Revision of Estimate	42
US Onshore and Gulf of Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revision of Estimate	(38)
Southwest Royalties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Reclassification to Liabilities Associated with Assets Held for Sale	42
Tamar Field, Offshore Israel
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Reclassification to Liabilities Associated with Assets Held for Sale	12
Gulf of Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		65
Israel
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		$ 5
Clayton Williams Energy
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Incurred	63
West Africa
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revision of Estimate	15
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Incurred	$ 31

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 15, 2017
Debt Instrument [Line Items]
Debt	$ 6,859	$ 6,859	$ 7,114
Unamortized Discount	(24)	(24)	(23)
Unamortized Premium	12	12	17
Unamortized Debt Issuance Costs	(40)	(40)	(34)
Total Debt, Net of Discount	6,807	6,807	7,074
Capital Lease Obligations, Current	(61)	(61)	(63)
Long-Term Debt Due After One Year	6,746	6,746	7,011
Repayments of term loan facility		240	0	$ 0
Repayments of senior debt		1,114	1,383	$ 12
Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Debt	$ 230	$ 230	$ 0
Interest Rate	2.27%	2.27%	0.00%
Noble Midstream Services Revolving Credit Facility, due September 20, 2021
Debt Instrument [Line Items]
Debt	$ 85	$ 85	$ 0
Interest Rate	2.49%	2.49%	0.00%
Term Loan Facility, due January 6, 2019
Debt Instrument [Line Items]
Debt	$ 0	$ 0	$ 550
Interest Rate	0.00%	0.00%	2.01%
Repayments of term loan facility	$ 550
Leviathan Term Loan Facility, due February 23, 2025
Debt Instrument [Line Items]
Debt	$ 0	$ 0	$ 0
Interest Rate	0.00%	0.00%	0.00%
Senior Notes, due March 1, 2019
Debt Instrument [Line Items]
Debt	$ 0	$ 0	$ 1,000
Interest Rate	0.00%	0.00%	8.25%		8.25%
Senior Notes, due May 1, 2021
Debt Instrument [Line Items]
Debt	$ 379	$ 379	$ 379
Interest Rate	5.625%	5.625%	5.625%
Senior Notes, due December 15, 2021
Debt Instrument [Line Items]
Debt	$ 1,000	$ 1,000	$ 1,000
Interest Rate	4.15%	4.15%	4.15%
Senior Notes, due June 1, 2022
Debt Instrument [Line Items]
Debt	$ 0	$ 0	$ 18
Interest Rate	0.00%	0.00%	5.875%
Repayments of senior debt	$ 18
Senior Notes due October 15, 2023
Debt Instrument [Line Items]
Debt	$ 100	$ 100	$ 100
Interest Rate	7.25%	7.25%	7.25%
Senior Notes Due November 15, 2024
Debt Instrument [Line Items]
Debt	$ 650	$ 650	$ 650
Interest Rate	3.90%	3.90%	3.90%
Senior Notes, due April 1, 2027
Debt Instrument [Line Items]
Debt	$ 250	$ 250	$ 250
Interest Rate	8.00%	8.00%	8.00%
Senior Notes, due January 15, 2028
Debt Instrument [Line Items]
Debt	$ 600	$ 600	$ 0
Interest Rate	3.85%	3.85%	0.00%
Senior Notes, due March 1, 2041
Debt Instrument [Line Items]
Debt	$ 850	$ 850	$ 850
Interest Rate	6.00%	6.00%	6.00%
Senior Notes, due November 15, 2043
Debt Instrument [Line Items]
Debt	$ 1,000	$ 1,000	$ 1,000
Interest Rate	5.25%	5.25%	5.25%
Senior Notes, due November 15, 2044
Debt Instrument [Line Items]
Debt	$ 850	$ 850	$ 850
Interest Rate	5.05%	5.05%	5.05%
Senior Notes, due August 15, 2047
Debt Instrument [Line Items]
Debt	$ 500	$ 500	$ 0
Interest Rate	4.95%	4.95%	0.00%		4.95%
Other Senior Notes and Debentures
Debt Instrument [Line Items]
Debt	$ 92	$ 92	$ 92
Interest Rate	7.13043%	7.13043%	7.13043%
Capital Lease and Other Obligations
Debt Instrument [Line Items]
Capital Lease Obligations	$ 273	$ 273	$ 375
Interest Rate	0.00%	0.00%	0.00%
Senior Notes, due June 1, 2024
Debt Instrument [Line Items]
Debt	$ 8	$ 8
Senior Debentures due August 1, 2097
Debt Instrument [Line Items]
Debt	$ 84	$ 84
Senior Notes due June 1, 2022, June 1, 2024 and Senior Debentures due August 1, 2097
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	7.13%	7.13%
Marcellus Shale | Capital Lease and Other Obligations
Debt Instrument [Line Items]
Debt	$ 41	$ 41
Capital lease principal payments		$ 60

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($)	Jan. 31, 2018	Aug. 15, 2017	Jan. 06, 2016	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 24, 2017
Debt Instrument [Line Items]
Proceeds from debt								$ 325,000,000	$ 0	$ 0
Debt				$ 6,859,000,000		$ 7,114,000,000		6,859,000,000	7,114,000,000
Unamortized discount				24,000,000		23,000,000		24,000,000	23,000,000
Proceeds from Issuance of Senior Notes, Net								1,086,000,000	0	0
Unamortized Premium				12,000,000		17,000,000		12,000,000	17,000,000
Gain on extinguishment								(98,000,000)	80,000,000	0
Repayment of facility				550,000,000		850,000,000		1,355,000,000	0	$ 70,000,000
Term Loan Facility, due January 6, 2019
Debt Instrument [Line Items]
Debt				$ 0		$ 550,000,000		$ 0	$ 550,000,000
Interest Rate				0.00%		2.01%		0.00%	2.01%
Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Credit facility fee rate basis points, minimum				0.10%				0.10%
Credit facility fee rate basis points, maximum				0.25%				0.25%
Credit facility aggregate short-term loans and letters of credit, maximum				$ 500,000,000				$ 500,000,000
Credit facility interest rate, Eurodollar rate plus, minimum				0.90%				0.90%
Credit facility interest rate, Eurodollar rate plus, maximum				1.50%				1.50%
Credit facility covenant term debt to capitalization ratio maximum				65.00%				65.00%
Debt				$ 230,000,000		$ 0		$ 230,000,000	$ 0
Interest Rate				2.27%		0.00%		2.27%	0.00%
Noble Midstream Services Revolving Credit Facility, due September 20, 2021
Debt Instrument [Line Items]
Debt				$ 85,000,000		$ 0		$ 85,000,000	$ 0
Interest Rate				2.49%		0.00%		2.49%	0.00%
Senior Notes, due January 15, 2028
Debt Instrument [Line Items]
Debt				$ 600,000,000		$ 0		$ 600,000,000	$ 0
Interest Rate				3.85%		0.00%		3.85%	0.00%
Senior Notes, due August 15, 2047
Debt Instrument [Line Items]
Debt				$ 500,000,000		$ 0		$ 500,000,000	$ 0
Interest Rate		4.95%		4.95%		0.00%		4.95%	0.00%
Senior Notes, due March 1, 2019
Debt Instrument [Line Items]
Debt				$ 0		$ 1,000,000,000		$ 0	$ 1,000,000,000
Interest Rate		8.25%		0.00%		8.25%		0.00%	8.25%
Leviathan Term Loan Facility, due February 23, 2025
Debt Instrument [Line Items]
Debt				$ 0		$ 0		$ 0	$ 0
Interest Rate				0.00%		0.00%		0.00%	0.00%
Term Loan Facility
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 1,400,000,000
Line of Credit | Term Loan Facility, due January 6, 2019
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 | Term Loan Facility, due January 6, 2019 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Credit facility interest rate, Eurodollar rate plus, minimum			1.00%
Credit facility interest rate, Eurodollar rate plus, maximum			1.75%
Line of Credit | Term Loan Facility
Debt Instrument [Line Items]
Proceeds from debt								$ 1,380,000,000
Debt instrument, term			3 years
Line of Credit | Term Loan Facility | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Basis spread			0.50%
Line of Credit | Term Loan Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread			1.00%
Senior Notes
Debt Instrument [Line Items]
Unamortized discount		$ 4,000,000
Debt issuance costs, gross		11,000,000
Proceeds from Issuance of Senior Notes, Net		1,000,000,000
Loss on debt					$ 98,000,000
Senior Notes | Senior Notes, due January 15, 2028
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 600,000,000
Interest Rate		3.85%
Senior Notes | Senior Notes, due August 15, 2047
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 500,000,000
Interest Rate		4.95%
Senior Notes | Senior Notes, due March 1, 2019
Debt Instrument [Line Items]
Debt redemption amount		$ 1,000,000,000
Unamortized Premium		$ 96,000,000
Noble Midstream | Line of Credit | Noble Midstream Services Revolving Credit Facility, due September 20, 2021
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 350,000,000				350,000,000
Additional borrowing capacity available				350,000,000				$ 350,000,000
Noble Midstream | Line of Credit | Noble Midstream Services Revolving Credit Facility, due September 20, 2021 | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Basis spread								0.50%
Noble Midstream | Line of Credit | Noble Midstream Services Revolving Credit Facility, due September 20, 2021 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread								1.00%
Letter of Credit | Noble Midstream
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 100,000,000				$ 100,000,000
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025
Debt Instrument [Line Items]
Maximum borrowing capacity											$ 1,000,000,000
Long-term line of credit											$ 625,000,000
Maximum final balloon payment allowable								35.00%
Commitment fee percentage								1.00%
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | LIBOR Prior to Production Startup
Debt Instrument [Line Items]
Basis spread								3.50%
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | LIBOR After Startup Prior to Two Years Before Maturity
Debt Instrument [Line Items]
Basis spread								3.25%
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | LIBOR Last Two years Until Maturity
Debt Instrument [Line Items]
Basis spread								3.75%
Subsequent Event | Noble Midstream Services Revolving Credit Facility, due September 20, 2021
Debt Instrument [Line Items]
Proceeds from debt	$ 300,000,000
Long-term line of credit	$ 530,000,000
Other Operating Income (Expense) | Line of Credit | Term Loan Facility
Debt Instrument [Line Items]
Gain on extinguishment							$ 80,000,000

Long-Term Debt - Debt Maturitie

Long-Term Debt - Debt Maturities (Details) $ in Millions	Dec. 31, 2017USD ($)
Debt Disclosure [Abstract]
2,018	$ 0
2,019	0
2,020	230
2,021	1,464
2,022	0
Thereafter	4,892
Total	$ 6,586

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Tax Credit Carryforward [Line Items]
Tax Cuts And Jobs Act Of 2017, Deferred tax benefit	$ 500
Tax Cuts And Jobs Act Of 2017, additional taxable income recognized	767
Foreign tax credits	164
AMT credit carryover	3
Operating loss carryforwards	3,200
Foreign loss carryforward	549
Estimated future US taxes on the eventual remittance of accumulated undistributed foreign subsidiary earnings	$ 240	$ 240
Federal Statutory Rate (in hundredths)	35.00%	35.00%	35.00%
Deferred Income Taxes	$ 1,227	$ 984	$ (116)
Clayton Williams Energy
Tax Credit Carryforward [Line Items]
Deferred tax liabilities	307
Deferred tax assets	450
Foreign Loss Carryforward
Tax Credit Carryforward [Line Items]
Foreign loss carryforward	183	$ 242
ISRAEL
Tax Credit Carryforward [Line Items]
Deferred Income Taxes	$ 12
ISRAEL | Tax Year 2016
Tax Credit Carryforward [Line Items]
Federal Statutory Rate (in hundredths)	25.00%
ISRAEL | Tax Year 2017
Tax Credit Carryforward [Line Items]
Federal Statutory Rate (in hundredths)	24.00%
ISRAEL | Tax Year 2018
Tax Credit Carryforward [Line Items]
Federal Statutory Rate (in hundredths)	23.00%

Income Taxes - Income Tax Provi

Income Taxes - Income Tax Provision, Effective Income Tax Reconciliation, and Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of income (loss) before income taxes [Abstract]
Domestic	$ (2,831)	$ (1,859)	$ (2,338)
Foreign	640	87	119
Loss Before Income Taxes	(2,191)	(1,772)	(2,219)
Current Taxes
Federal	(11)	(4)	(1)
State	1	5	0
Foreign	96	196	107
Total Current	86	197	106
Deferred Taxes
Federal	(1,258)	(784)	216
State	(8)	(24)	(5)
Foreign	39	(176)	(95)
Total Deferred	(1,227)	(984)	116
Total Income Tax (Benefit) Provision Attributable to Noble Energy	$ (1,141)	$ (787)	$ 222
Effective Tax Rate (in hundredths)	52.10%	44.40%	(10.00%)
Federal statutory tax rate reconciliation [Abstract]
Federal Statutory Rate (in hundredths)	35.00%	35.00%	35.00%
Effect of
Earnings of Equity Method Investees	1.90%	1.00%	0.60%
Noncontrolling Interests	1.10%	0.40%	(0.00%)
US and Foreign Statutory Rate Change	23.50%	1.60%	0.00%
Transition Tax	(4.80%)	0.00%	0.00%
State Taxes, Net of Federal Benefit	0.30%	1.30%	0.30%
Difference Between US and Foreign Rates	1.80%	(0.10%)	2.60%
Foreign Exploration Loss	0.00%	0.10%	2.70%
Change in Valuation Allowance	(17.40%)	(2.00%)	0.00%
Oil Profits Tax - Israel	(0.10%)	0.00%	0.10%
Tax Contingency	0.10%	0.20%	0.40%
Accumulated Undistributed Foreign Earnings	11.00%	7.20%	(37.70%)
Goodwill Impairment	0.00%	0.00%	(12.30%)
Other, Net	(0.30%)	(0.30%)	(1.70%)
Effective Rate	52.10%	44.40%	(10.00%)
Deferred Tax Assets
Loss Carryforwards	$ 902	$ 474
Employee Compensation and Benefits	97	150
Mark to Market of Commodity Derivative Instruments	7	44
Foreign Tax Credits	366	0
Other	104	49
Total Deferred Tax Assets	1,476	717
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits	(549)
Net Deferred Tax Assets	927	475
Deferred Tax Liabilities
Accumulated Undistributed Foreign Earnings	0	(240)
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments	(2,029)	(2,054)
Total Deferred Tax Liability	(2,029)	(2,294)
Net Deferred Tax Liability	(1,102)	$ (1,819)
Deferred tax benefit, removal of assertion of indefinitely reinvested earnings	$ 240

Income Taxes - Net Deferred Tax

Income Taxes - Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Deferred Income Tax Asset - Noncurrent	$ 25	$ 0
Deferred Income Tax Liability - Noncurrent	(1,127)	(1,819)
Net Deferred Tax Liability	$ (1,102)	$ (1,819)

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	$ 3
Reductions for Tax Positions of Prior Years	(3)
Unrecognized Tax Benefits, Ending Balance	$ 0

Stock-Based and Other Compens67

Stock-Based and Other Compensation Plans - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Total Stock-Based Compensation Expense	$ 104	$ 77	$ 86
Tax Benefit Recognized	(36)	(27)	(30)
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Total Stock-Based Compensation Expense	56	62	50
Exploration Expense and Other
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Total Stock-Based Compensation Expense	$ 48	$ 15	$ 36

Stock-Based and Other Compens68

Stock-Based and Other Compensation Plans - Narrative (Details) $ / shares in Units, $ in Millions	Feb. 01, 2016simulation$ / sharesshares	Dec. 31, 2017USD ($)simulation$ / sharesshares	Dec. 31, 2016USD ($)simulation$ / sharesshares	Dec. 31, 2015USD ($)simulation$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution, percent of employees' gross pay		6.00%
401K Plan Employer Cash Contributions | $		$ 31	$ 32	$ 35
Shares of common stock held by rabbi trust (in dollars per share) | $ / shares		$ 16.72
Deferred compensation arrangement most shares held by individual | shares		400,000
Deferred compensation arrangement, percent of the most shares held by individual		85.00%
Deferred compensation distribution timeline		2 years
Deferred compensation arrangement plan, distribution amount | shares		200,000	200,000	200,000
Deferred compensation arrangement shares sold | shares		1,238	1,009	1,009
Deferred compensation arrangements trust plan, distribution amount | $		$ 21	$ 22	$ 18
Deferred compensation (income) expense | $		9	11	(12)
Deferred compensation liabilities | $		$ 116	121
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum term to maturity on US Treasuries used to determine the risk free rate assumption in valuing stock options		5 years
Maximum term to maturity on US Treasuries used to determine the risk free rate assumption in valuing stock options		7 years
The period ended, prior to the date of grant, over which an average of daily stock prices is computed in determining the dividend yield		3 years
Duration of dividends		1 year
Total intrinsic value of options exercised | $		$ 4	$ 10	$ 7
Unrecognized compensation cost related to nonvested awards | $		$ 21
The weighted-average period over which unrecognized compensation cost is to be recognized (in years)		1 year 3 months 18 days
Expected volatility (in hundredths)		33.20%	32.40%	32.60%
Risk-free rate (in hundredths)		2.20%	1.60%	1.40%
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to nonvested awards | $		$ 41
The weighted-average period over which unrecognized compensation cost is to be recognized (in years)		1 year 4 months 24 days
Total fair value of vested restricted stock | $		$ 34	$ 24	$ 62
Weighted average award date fair value, shares awarded (in dollars per share) | $ / shares		$ 35.45	$ 29.99	$ 35.53
Number of Simulations | simulation		500,000	500,000	500,000
Expected volatility (in hundredths)		35.00%	38.00%	30.00%
Risk-free rate (in hundredths)		1.50%	1.00%	0.80%
Restricted Stock | Subject to Time Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average award date fair value, shares awarded (in dollars per share) | $ / shares		$ 36.26
Weighted average award date fair value (in dollars per share) | $ / shares		$ 37.21	$ 36.37
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to nonvested awards | $		$ 6
The weighted-average period over which unrecognized compensation cost is to be recognized (in years)		1 year 1 month 6 days
Phantom Share Units (PSUs) | Subject to Time Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average award date fair value (in dollars per share) | $ / shares		$ 31.65	$ 31.65
2017 Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock authorized for issuance After April 26, 2011 (in shares) | shares		29,000,000
Number of shares of common stock reserved for issuance (in shares) | shares		28,987,609
Shares of common stock available for future grants and awards (in shares) | shares		28,972,832
Expiration period (in years)		10 years
Stock option vesting period		3 years
2017 Long-Term Incentive Plan | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period		2 years
2017 Long-Term Incentive Plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period		3 years
2015 Stock Plan for Non-Employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock authorized for issuance After April 26, 2011 (in shares) | shares		708,996
Number of shares of common stock reserved for issuance (in shares) | shares		674,025
Shares of common stock available for future grants and awards (in shares) | shares		463,096
Stock Option And Restricted Stock Plan 1992 | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period	3 years
Issued (shares) | shares	1,000,000
Number of Simulations | simulation	500,000
Expected volatility (in hundredths)	3800.00%
Risk-free rate (in hundredths)	90.00%
Maximum number of times fair market value of stock price of award issued	400.00%
Weighted average award date fair value (in dollars per share) | $ / shares	$ 31.65
Officer | Stock Option And Restricted Stock Plan 1992 | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period	2 years
Fair Value, Measurements, Recurring
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation liability | $		$ 10	$ 9

Stock-Based and Other Compens69

Stock-Based and Other Compensation Plans - Assumptions and Award Activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Options
Exercised (in shares)	(382,882)	(954,898)
Stock Option
Assumptions used to value stock option awards [Abstract]
Expected term (in years)	6 years 4 months 24 days	6 years 3 months 18 days	6 years
Expected volatility (in hundredths)	33.20%	32.40%	32.60%
Risk-free rate (in hundredths)	2.20%	1.60%	1.40%
Expected dividend yield (in hundredths)	0.90%	0.70%	1.20%
Weighted-average grant-date fair value of options granted (in dollars per share)	$ 13.26	$ 10.10	$ 13.93
Options
Outstanding, beginning balance (in shares)	15,088,862
Granted (in shares)	1,819,819
Exercised (in shares)	(382,882)
Forfeited (in shares)	(976,577)
Outstanding, ending balance (in shares)	15,549,222	15,088,862
Exercisable (in shares)	12,101,890
Weighted Average Exercise Price
Weighted average exercise price per share outstanding, beginning balance (in dollars per share)	$ 43.49
Weighted average exercise price per share granted (in dollars per share)	39.40
Weighted average exercise price per share exercised (in dollars per share)	37.57
Weighted average exercise price per share forfeited (in dollars per share)	43.93
Weighted average exercise price per share outstanding, ending balance (in dollars per share)	43.42	$ 43.49
Weighted average exercise price per exercisable share (in dollars per share)	$ 44.98
Weighted average remaining contractual term of shares outstanding (in years)	5 years
Weighted average remaining contractual term, exercisable shares (in years)	4 years
Aggregate intrinsic value of shares outstanding	$ 6
Aggregate intrinsic value, exercisable shares	$ 6
Restricted Stock
Assumptions used to value stock option awards [Abstract]
Expected volatility (in hundredths)	35.00%	38.00%	30.00%
Risk-free rate (in hundredths)	1.50%	1.00%	0.80%
Weighted Average Award Date Fair Value
Weighted average award date fair value, shares awarded (in dollars per share)	$ 35.45	$ 29.99	$ 35.53
Subject to Time Vesting | Restricted Stock
Number of Shares
Outstanding, beginning balance (in shares)	1,371,780
Awarded (in shares)	3,201,504
Vested (in shares)	(2,515,383)
Forfeited (in shares)	(218,164)
Outstanding, ending balance (in shares)	1,839,737	1,371,780
Weighted Average Award Date Fair Value
Weighted average award date fair value, beginning of period (in dollars per share)	$ 36.37
Weighted average award date fair value, shares awarded (in dollars per share)	36.26
Weighted average award date fair value, shares vested (in dollars per share)	34.93
Weighted average award date fair value, shares forfeited (in dollars per share)	37.66
Weighted average award date fair value, end of period (in dollars per share)	$ 37.21	$ 36.37
Subject to Time Vesting | Phantom Share Units (PSUs)
Number of Shares
Outstanding, beginning balance (in shares)	712,089
Vested (in shares)	(13,305)
Forfeited (in shares)	(88,625)
Outstanding, ending balance (in shares)	610,159	712,089
Weighted Average Award Date Fair Value
Weighted average award date fair value, beginning of period (in dollars per share)	$ 31.65
Weighted average award date fair value, shares vested (in dollars per share)	31.65
Weighted average award date fair value, shares forfeited (in dollars per share)	31.65
Weighted average award date fair value, end of period (in dollars per share)	$ 31.65	$ 31.65
Subject to Market Conditions | Restricted Stock
Number of Shares
Outstanding, beginning balance (in shares)	1,502,992
Awarded (in shares)	464,608
Vested (in shares)	(219,883)
Forfeited (in shares)	(535,012)
Outstanding, ending balance (in shares)	1,212,705	1,502,992
Weighted Average Award Date Fair Value
Weighted average award date fair value, beginning of period (in dollars per share)	$ 27.43
Weighted average award date fair value, shares awarded (in dollars per share)	24.25
Weighted average award date fair value, shares vested (in dollars per share)	44.61
Weighted average award date fair value, shares forfeited (in dollars per share)	33.12
Weighted average award date fair value, end of period (in dollars per share)	$ 25.55	$ 27.43
Subject to Market Conditions | Phantom Share Units (PSUs)
Number of Shares
Outstanding, beginning balance (in shares)	209,504
Vested (in shares)	0
Forfeited (in shares)	(42,021)
Outstanding, ending balance (in shares)	167,483	209,504
Weighted Average Award Date Fair Value
Weighted average award date fair value, beginning of period (in dollars per share)	$ 6.82
Weighted average award date fair value, shares vested (in dollars per share)	0
Weighted average award date fair value, shares forfeited (in dollars per share)	6.82
Weighted average award date fair value, end of period (in dollars per share)	$ 6.82	$ 6.82
Clayton Williams Energy | Restricted Stock
Number of Shares
Awarded (in shares)	1,900,000

Stock-Based and Other Compens70

Stock-Based and Other Compensation Plans - Assumptions Used For Restricted Stock (Details) - Restricted Stock - simulation	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Simulations	500,000	500,000	500,000
Expected volatility (in hundredths)	35.00%	38.00%	30.00%
Risk-free rate (in hundredths)	1.50%	1.00%	0.80%

Stock-Based and Other Compens71

Stock-Based and Other Compensation Plans - Components of Rabbi Trust (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Mutual Fund Investments	$ 57	$ 62
Noble Energy Common Stock (at Fair Value)	14	26
Total Rabbi Trust Assets	71	88
Liability Under Related Deferred Compensation Plan	$ 71	$ 88
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust	470,030	671,269

Fair Value Measurements and D72

Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Nonrecurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Impaired Oil and Gas Properties	$ 70	$ 92	$ 1,285
Total Pre-tax (Non-cash) Impairment Loss, Impaired oil and gas properties	$ 70	92	533
Impaired Materials and Supplies Inventory		105	81
Total Pre-tax (Non-cash) Impairment Loss, Materials and supplies inventory		14	20
Discount rate for impairment model	10.00%
Quoted Prices in Active Markets (Level 1)
Asset Impairment Charges [Abstract]
Impaired Oil and Gas Properties	$ 0	0	0
Impaired Materials and Supplies Inventory		0	0
Significant Other Observable Inputs (Level 2)
Asset Impairment Charges [Abstract]
Impaired Oil and Gas Properties	0	0	0
Impaired Materials and Supplies Inventory		0	0
Significant Unobservable Inputs (Level 3)
Financial Assets
Commodity Derivative Instruments		0
Asset Impairment Charges [Abstract]
Impaired Oil and Gas Properties	0	0	752
Impaired Materials and Supplies Inventory		91	$ 61
Fair Value, Measurements, Recurring
Financial Assets
Mutual Fund Investments	57	71
Commodity Derivative Instruments	2	0
Financial Liabilities
Commodity Derivative Instruments	(73)	(116)
Portion of Deferred Compensation Liability Measured at Fair Value	(71)	(88)
Stock Based Compensation Liability Measured at Fair Value	(10)	(9)
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets (Level 1)
Financial Assets
Mutual Fund Investments	57	71
Commodity Derivative Instruments	0	0
Financial Liabilities
Commodity Derivative Instruments	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	(71)	(88)
Stock Based Compensation Liability Measured at Fair Value	(10)	(9)
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Financial Assets
Mutual Fund Investments	0	0
Commodity Derivative Instruments	7	5
Financial Liabilities
Commodity Derivative Instruments	(78)	(121)
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Financial Assets
Mutual Fund Investments	0	0
Commodity Derivative Instruments	0
Financial Liabilities
Commodity Derivative Instruments	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	0
Fair Value, Measurements, Recurring | Adjustment
Financial Assets
Mutual Fund Investments	0	0
Commodity Derivative Instruments	(5)	(5)
Financial Liabilities
Commodity Derivative Instruments	5	5
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	$ 0	$ 0

Fair Value Measurements and D73

Fair Value Measurements and Disclosures - Narrative (Details) $ in Millions	Dec. 31, 2017USD ($)
Fair Value Disclosures [Abstract]
Firm transportation liability	$ 90

Fair Value Measurements and D74

Fair Value Measurements and Disclosures - Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Net of Unamortized Discount	$ 6,586	$ 6,739
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Net of Unamortized Discount	$ 7,142	$ 7,112

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 30, 2015
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	$ 4,060	$ 3,389	$ 3,093
Income from Equity Method Investees and Other	196	102	90
Intersegment Revenues	0	0	0
Total Revenues	4,256	3,491	3,183
Lease Operating Expense	571	542	563
Production and Ad Valorem Taxes	138	78	127
Gathering, Transportation and Processing Expense	432	480	306
Total	1,141	1,100	996
DD&A	2,053	2,454	2,131
Clayton Williams Acquisition Expenses	100	0	0
Loss (Gain) on Debt Extinguishment	98	(80)	0
Loss on Marcellus Shale Upstream Divestiture	2,379	0	0
Asset Impairments	70	92	533
(Gain) Loss on Commodity Derivative Instruments	(63)	139	(501)
(Loss) Income Before Income Taxes	(2,191)	(1,772)	(2,219)
Equity Method Investments	305	400	453
Additions to Long-Lived Assets	2,851	1,526	3,062
Goodwill	1,310	0		$ 779
Assets	21,476	21,011	24,196
Noble Midstream
Segment Reporting Information [Line Items]
Revenues from third parties	19
Intersegment Eliminations
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	0	0	0
Income from Equity Method Investees and Other	0	0	0
Intersegment Revenues	(277)	(200)	(119)
Total Revenues	(277)	(200)	(119)
Lease Operating Expense	(14)	(18)	(12)
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	(188)	(128)	(85)
Total	(202)	(146)	(97)
DD&A	(5)	0	0
Clayton Williams Acquisition Expenses	0
Loss (Gain) on Debt Extinguishment	0
Loss on Marcellus Shale Upstream Divestiture	0
Asset Impairments	0	0	0
(Gain) Loss on Commodity Derivative Instruments	0	0	0
(Loss) Income Before Income Taxes	(62)	(51)	(21)
Equity Method Investments	0	0	0
Additions to Long-Lived Assets	(79)	(53)	(21)
Goodwill	0
Assets	(163)	(98)	(46)
Corporate
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	0	0	0
Income from Equity Method Investees and Other	0	0	0
Intersegment Revenues	0	0	0
Total Revenues	0	0	0
Lease Operating Expense	0	0	0
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	0	0	0
Total	0	0	0
DD&A	63	40	44
Clayton Williams Acquisition Expenses	0
Loss (Gain) on Debt Extinguishment	98
Loss on Marcellus Shale Upstream Divestiture	0
Asset Impairments	0	0	0
(Gain) Loss on Commodity Derivative Instruments	0		0
(Loss) Income Before Income Taxes	(559)	(626)	(622)
Equity Method Investments	0	0	0
Additions to Long-Lived Assets	102	32	80
Goodwill	0
Assets	247	304	220
United States | Operating Segments
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	3,156	2,416	2,011
Income from Equity Method Investees and Other	0	0	0
Intersegment Revenues	0	0	0
Total Revenues	3,156	2,416	2,011
Lease Operating Expense	466	418	398
Production and Ad Valorem Taxes	135	76	126
Gathering, Transportation and Processing Expense	550	564	366
Total	1,151	1,058	890
DD&A	1,739	2,103	1,677
Clayton Williams Acquisition Expenses	100
Loss (Gain) on Debt Extinguishment	0
Loss on Marcellus Shale Upstream Divestiture	2,379
Asset Impairments	63	0	158
(Gain) Loss on Commodity Derivative Instruments	(92)	126	(347)
(Loss) Income Before Income Taxes	(2,365)	(1,277)	(1,693)
Equity Method Investments	0	0	0
Additions to Long-Lived Assets	1,994	1,353	2,409
Goodwill	1,310
Assets	15,767	16,153	18,043
United States | Noble Midstream
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	0	0	0
Income from Equity Method Investees and Other	76	52	51
Intersegment Revenues	277	200	119
Total Revenues	353	252	170
Lease Operating Expense	0	0	0
Production and Ad Valorem Taxes	3	2	1
Gathering, Transportation and Processing Expense	70	44	25
Total	73	46	26
DD&A	30	19	14
Clayton Williams Acquisition Expenses	0
Loss (Gain) on Debt Extinguishment	0
Loss on Marcellus Shale Upstream Divestiture	0
Asset Impairments	0	0	0
(Gain) Loss on Commodity Derivative Instruments	0	0	0
(Loss) Income Before Income Taxes	233	176	123
Equity Method Investments	80	183	226
Additions to Long-Lived Assets	423	58	146
Goodwill	0
Assets	1,357	851	799
Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	534	540	497
Income from Equity Method Investees and Other	0	0	0
Intersegment Revenues	0	0	0
Total Revenues	534	540	497
Lease Operating Expense	29	37	42
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	0	0	0
Total	29	37	42
DD&A	76	81	70
Clayton Williams Acquisition Expenses	0
Loss (Gain) on Debt Extinguishment	0
Loss on Marcellus Shale Upstream Divestiture	0
Asset Impairments	0	88	36
(Gain) Loss on Commodity Derivative Instruments	0	0	0
(Loss) Income Before Income Taxes	413	543	313
Equity Method Investments	0	0	0
Additions to Long-Lived Assets	411	88	147
Goodwill	0
Assets	2,846	2,233	2,676
West Africa | Operating Segments
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	370	433	580
Income from Equity Method Investees and Other	120	50	39
Intersegment Revenues	0	0	0
Total Revenues	490	483	619
Lease Operating Expense	90	105	131
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	0	0	0
Total	90	105	131
DD&A	146	205	326
Clayton Williams Acquisition Expenses	0
Loss (Gain) on Debt Extinguishment	0
Loss on Marcellus Shale Upstream Divestiture	0
Asset Impairments	0	0	339
(Gain) Loss on Commodity Derivative Instruments	29	13	(154)
(Loss) Income Before Income Taxes	203	(338)	(90)
Equity Method Investments	225	217	227
Additions to Long-Lived Assets	34	54	124
Goodwill	0
Assets	1,308	1,479	2,299
Other International | Operating Segments
Segment Reporting Information [Line Items]
Oil, NGL and Gas Sales from Third Parties	0	0	5
Income from Equity Method Investees and Other	0	0	0
Intersegment Revenues	0	0	0
Total Revenues	0	0	5
Lease Operating Expense	0	0	4
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	0	0	0
Total	0	0	4
DD&A	4	6	0
Clayton Williams Acquisition Expenses	0
Loss (Gain) on Debt Extinguishment	0
Loss on Marcellus Shale Upstream Divestiture	0
Asset Impairments	7	4	0
(Gain) Loss on Commodity Derivative Instruments	0	0	0
(Loss) Income Before Income Taxes	(54)	(199)	(229)
Equity Method Investments	0	0	0
Additions to Long-Lived Assets	(34)	(6)	177
Goodwill	0
Assets	114	89	205
Foreign Countries
Segment Reporting Information [Line Items]
Revenues from third parties	904	973	1,100
Long-lived assets	$ 2,800	$ 3,000	$ 3,900

Concentration of Risk (Details)

Concentration of Risk (Details)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
BP
Concentration Risk [Line Items]
Percentage of crude oil sales (in hundredths)	15.00%
Percentage of total oil, gas & NGL sales (in hundredths)	10.00%
Shell
Concentration Risk [Line Items]
Percentage of crude oil sales (in hundredths)	22.00%	24.00%	18.00%
Percentage of total oil, gas & NGL sales (in hundredths)	13.00%	13.00%	11.00%
Glencore Energy UK Ltd
Concentration Risk [Line Items]
Percentage of crude oil sales (in hundredths)		22.00%	30.00%
Percentage of total oil, gas & NGL sales (in hundredths)		12.00%	18.00%

Additional Shareholders' Equi77

Additional Shareholders' Equity Information (Details) - USD ($) $ in Millions	Dec. 15, 2017	Jun. 26, 2017	Apr. 24, 2017	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 15, 2018
Common stock shares issued [Rollforward]
Shares, beginning of period (in shares)					471,360,427	469,718,512
Exercise of common stock options (in shares)					382,882	954,898
Restricted stock awards, net of forfeitures (in shares)					2,912,936	687,017
Stock issued (shares)					54,087,136	0
Shares, end of period (in shares)					528,743,381	471,360,427	469,718,512
Treasury stock [Rollforward]
Shares, beginning of period (in shares)					37,961,316	37,925,625
Shares received from employees in payment of withholding taxes due on vesting of shares of restricted stock (in shares)					1,026,891	236,700
Rabbi Trust Shares Distributed and/or Sold (in shares)					(201,238)	(201,009)
Shares, end of period (in shares)					38,786,969	37,961,316	37,925,625
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust					0	0
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Loss per Share					15,619,276	14,218,319
Payment of withholding taxes due by Clayton Williams shareholders (in shares)					720,000
Proceeds from issuance of common limited partners units					$ 312	$ 299	$ 0
Accumulated Other Comprehensive Loss
Shareholders Equity, Beginning Balance					9,600	10,370	10,325
Realized Amounts Reclassified Into Earnings					5	5	63
Unrealized Change in Fair Value					(4)	(3)	(6)
Shareholders Equity, Ending Balance					$ 10,619	$ 9,600	$ 10,370
Effective income tax rate applied to AOCI (in hundredths)					35.00%	35.00%	35.00%
Noble Midstream
Treasury stock [Rollforward]
Shares issued (in shares)	3,680,000	3,525,000		14,375,000
Proceeds from issuance of common limited partners units	$ 174	$ 138		$ 299
Clayton Williams Energy
Common stock shares issued [Rollforward]
Stock issued (shares)			56,000,000
Clayton Williams Energy | Restricted Stock
Treasury stock [Rollforward]
Awarded (in shares)					1,900,000
Non-controlling Interests
Accumulated Other Comprehensive Loss
Shareholders Equity, Beginning Balance					$ 312	$ 0	$ 0
Shareholders Equity, Ending Balance					683	312	0
Interest Rate Cash Flow Hedges
Accumulated Other Comprehensive Loss
Shareholders Equity, Beginning Balance					(21)	(22)	(23)
Realized Amounts Reclassified Into Earnings					1	1	1
Unrealized Change in Fair Value					0	0	0
Shareholders Equity, Ending Balance					(20)	(21)	(22)
Pension- Related and Other
Accumulated Other Comprehensive Loss
Shareholders Equity, Beginning Balance					(10)	(11)	(67)
Realized Amounts Reclassified Into Earnings					4	4	62
Unrealized Change in Fair Value					(4)	(3)	(6)
Shareholders Equity, Ending Balance					(10)	(10)	(11)
AOCI Including Portion Attributable to Noncontrolling Interest
Accumulated Other Comprehensive Loss
Shareholders Equity, Beginning Balance					(31)	(33)	(90)
Shareholders Equity, Ending Balance					(30)	$ (31)	$ (33)
Subsequent Event
Treasury stock [Rollforward]
Share repurchase program authorized amount								$ 750
Interest Rate Contract
Accumulated Other Comprehensive Loss
Loss on derivative					$ 20

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended			36 Months Ended
	May 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Other Commitments [Line Items]
Rental expense for office buildings and oil and gas operations equipment		$ 69,000,000	$ 76,000,000	$ 84,000,000
Consent Decree
Other Commitments [Line Items]
Civil penalty	$ 24,710			4,950,000	$ 72,000,000
Mitigation projects				4,500,000
Supplemental environmental projects	$ 98,840			$ 4,000,000
Marcellus Shale Firm Transportation Agreement
Other Commitments [Line Items]
Long-term purchase commitment, amount		1,400,000,000
United States
Other Commitments [Line Items]
Long-term purchase commitment, amount		$ 781,000,000
Minimum | Marcellus Shale Firm Transportation Agreement
Other Commitments [Line Items]
Commitment obligation, term		2 years
Minimum | United States
Other Commitments [Line Items]
Commitment obligation, term		1 year
Maximum | Marcellus Shale Firm Transportation Agreement
Other Commitments [Line Items]
Commitment obligation, term		16 years
Maximum | United States
Other Commitments [Line Items]
Commitment obligation, term		11 years

Commitments and Contingencies79

Commitments and Contingencies - Minimum Commitments Due (Details) $ in Millions	Dec. 31, 2017USD ($)
Other Commitments [Line Items]
2,018	$ 969
2,019	497
2,020	361
2,021	297
2,022	244
2023 and Thereafter	1,667
Total	4,035
Drilling, Equipment, and Purchase Obligations
Other Commitments [Line Items]
2,018	636
2,019	167
2,020	40
2,021	13
2,022	8
2023 and Thereafter	32
Total	896
Transportation and Gathering Obligations
Other Commitments [Line Items]
2,018	215
2,019	252
2,020	247
2,021	223
2,022	182
2023 and Thereafter	1,355
Total	2,474
Operating Lease Obligations
Other Commitments [Line Items]
2,018	44
2,019	33
2,020	32
2,021	32
2,022	33
2023 and Thereafter	156
Total	330
Capital Lease and Other Obligations
Other Commitments [Line Items]
2,018	74
2,019	45
2,020	42
2,021	29
2,022	21
2023 and Thereafter	124
Total	$ 335