Noble Energy (NBL) 10-K 19 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018
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 Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float		$ 17
Entity Common Stock, Shares Outstanding	477,643,425
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Revenue	$ 4,986	$ 4,256	$ 3,491
Costs and Expenses
Production Expense	1,197	1,141	1,100
Exploration Expense	129	188	925
Depreciation, Depletion and Amortization	1,934	2,053	2,454
Loss on Marcellus Shale Upstream Divestiture and Other	0	2,379	0
Gain on Divestitures, Net	(843)	(326)	(238)
Asset Impairments	206	70	92
Goodwill Impairment	1,281	0	0
General and Administrative	385	415	399
Other Operating Expense, Net	346	138	135
Total	4,635	6,058	4,867
Operating Income (Loss)	351	(1,802)	(1,376)
Other Expense
(Gain) Loss on Commodity Derivative Instruments	(63)	(63)	139
Loss (Gain) on Extinguishment of Facility or Debt	8	98	(80)
Interest, Net of Amount Capitalized	282	354	328
Other Non-Operating (Income) Expense, Net	(16)	0	9
Total	211	389	396
Income (Loss) Before Income Taxes	140	(2,191)	(1,772)
Income Tax Expense (Benefit)	126	(1,141)	(787)
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests	14	(1,050)	(985)
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	80	68	13
Net Loss and Comprehensive Loss Attributable to Noble Energy	$ (66)	$ (1,118)	$ (998)
Loss Attributable to Noble Energy per Common Share
Basic and Diluted (in usd per share)	$ (0.14)	$ (2.38)	$ (2.32)
Weighted Average Number of Shares Outstanding
Weighted Average Number of Shares Outstanding, Basic and Diluted (in shares)	483	469	430
Oil, NGL and Gas Sales
Revenues
Revenue	$ 4,461	$ 4,060	$ 3,389
Sales of Purchased Oil and Gas and Other
Revenues
Revenue	$ 525	$ 196	$ 102

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 716	$ 675
Accounts Receivable, Net	616	748
Other Current Assets	418	780
Total Current Assets	1,750	2,203
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	29,002	29,678
Property, Plant and Equipment, Other	891	879
Total Property, Plant and Equipment, Gross	29,893	30,557
Accumulated Depreciation, Depletion and Amortization	(11,474)	(13,055)
Total Property, Plant and Equipment, Net	18,419	17,502
Other Noncurrent Assets	731	461
Goodwill	110	1,310
Total Assets	21,010	21,476
Current Liabilities
Accounts Payable - Trade	1,207	1,161
Other Current Liabilities	519	578
Total Current Liabilities	1,726	1,739
Long-Term Debt	6,574	6,746
Deferred Income Taxes	1,061	1,127
Other Noncurrent Liabilities	1,165	1,245
Total Liabilities	10,526	10,857
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued	0	0
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 520 Million and 529 Million Shares Issued, respectively	5	5
Additional Paid in Capital	8,203	8,438
Accumulated Other Comprehensive Loss	(32)	(30)
Treasury Stock, at Cost; 39 Million Shares	(730)	(725)
Retained Earnings	1,980	2,248
Noble Energy Share of Equity	9,426	9,936
Noncontrolling Interests	1,058	683
Total Equity	10,484	10,619
Total Liabilities and Equity	$ 21,010	$ 21,476

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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)	520,000,000	528,892,390
Treasury Stock (in shares)	38,943,630	38,943,630

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows From Operating Activities
Net Income (Loss) Including Noncontrolling Interests	$ 14	$ (1,050)	$ (985)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,934	2,053	2,454
Loss on Marcellus Shale Upstream Divestiture and Other	0	2,379	0
Gain on Divestitures, Net	(843)	(326)	(238)
Asset Impairments	206	70	92
Goodwill Impairment	1,281	0	0
Deferred Income Tax Benefit	(70)	(1,227)	(984)
Loss (Gain) on Extinguishment of Facility or Debt, Net	4	98	(80)
(Gain) Loss on Commodity Derivative Instruments	(63)	(63)	139
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments	(161)	13	569
Stock Based Compensation	62	104	77
Undeveloped Leasehold Impairment	1	62	93
Dry Hole Cost	1	9	579
Other Adjustments for Noncash Items Included in Net Income (Loss)	17	(21)	95
Changes in Operating Assets and Liabilities
Decrease (Increase) in Accounts Receivable	156	(171)	(151)
(Decrease) Increase in Accounts Payable	(63)	248	(111)
Increase (Decrease) in Current Income Taxes Payable	22	(36)	(32)
Other Current Assets and Liabilities, Net	(36)	(71)	(76)
Other Operating Assets and Liabilities, Net	(126)	(120)	(90)
Net Cash Provided by Operating Activities	2,336	1,951	1,351
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(3,279)	(2,649)	(1,541)
Acquisitions, Net of Cash Received	(653)	(954)	30
Proceeds from Divestitures	1,999	2,073	1,241
Marcellus Shale Acreage Exchange Consideration	0	0	(213)
Other	2	(87)	82
Net Cash Used in Investing Activities	(1,931)	(1,617)	(401)
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facility	1,580	1,585	0
Repayment of Revolving Credit Facility	(1,810)	(1,355)	0
Proceeds from Term Loan Facility	0	0	1,400
Repayment of Term Loan Facility	0	(550)	(850)
Repayment of Senior Notes	(384)	(1,114)	(1,383)
Repayment of Clayton Williams Energy Long-term Debt	0	(595)	0
Proceeds from Issuance of Senior Notes	0	1,086	0
Dividends Paid, Common Stock	(208)	(190)	(172)
Purchase and Retirement of Common Stock	(295)	0	0
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs	0	312	299
Contributions from Noncontrolling Interest Owners	353	19	0
Other	(110)	(114)	(62)
Net Cash Used in Financing Activities	(399)	(831)	(768)
Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	6	(497)	182
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	713	1,210	1,028
Cash, Cash Equivalents, and Restricted Cash at End of Period	719	713	1,210
Revolving Credit Facility
Cash Flows From Financing Activities
Proceeds from Credit Facility	777	325	0
Repayment of Noble Midstream Services Revolving Credit Facility	(802)	(240)	0
Term Loan Facility
Cash Flows From Financing Activities
Proceeds from Credit Facility	$ 500	$ 0	$ 0

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
Beginning 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 Noble Midstream Partners Common Units, Net of Offering Costs	299		0				299
Other	(4)		(2)	2	(4)
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
Clayton Williams Energy Acquisition	1,851		1,876		(25)
Stock-based Compensation	100		100
Exercise of Stock Options	10		10
Dividends	(190)					(190)
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs	312						312
Distributions to Noncontrolling Interest Owners	(28)						(28)
Other	14		2	1	(8)		19
Ending Balance at Dec. 31, 2017	10,619	5	8,438	(30)	(725)	2,248	683
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	14					(66)	80
Stock-based Compensation	78		78
Dividends	(208)					(208)
Purchase and Retirement of Common Stock	(295)		(295)
Clayton Williams Energy Acquisition	(25)		(25)
Contributions from Noncontrolling Interest Owners	353						353
Distributions to Noncontrolling Interest Owners	(51)						(51)
Other	(1)		7	(2)	(5)	6	(7)
Ending Balance at Dec. 31, 2018	$ 10,484	$ 5	$ 8,203	$ (32)	$ (730)	$ 1,980	$ 1,058

Consolidated Statements of Sh_2

Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.43	$ 0.40	$ 0.40

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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 (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins. Basis of Presentation and Consolidation We use accounting policies that 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. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. We do not consider interest income or expense and income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 3. Segment Information . Consolidated Variable Interest Entity (VIE) Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners. Noncontrolling Interests In third quarter 2016, 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. We also present third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries as noncontrolling interests. See Note 5. Acquisitions and Divestitures . 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 on our consolidated balance sheets. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows 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 15. Equity Method Investments . 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. 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, NGL and natural gas reserves are the most significant of our estimates. All of 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, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas 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, NGLs and natural gas 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 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. Reclassifications The revenues and expenses associated with mitigating Marcellus Shale retained firm transportation contracts, including costs associated with exiting certain of those contracts, were reclassified from our oil and gas exploration and production segment to Corporate as these items are not representative of retained upstream operations. See Note 3. Segment Information . 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 14. 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. Accounts Receivable and Allowance for Doubtful Accounts 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. The majority of these receivables have payment terms of 30 days or less . Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and we have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. We routinely assess the recoverability of all material 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. See Note 2. Additional Financial Statement Information . 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 assets will be reduced to their fair value if the carrying amount exceeds net realizable value. The cost of crude oil inventory includes production costs and depreciation, depletion and amortization (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: Oil and Gas Properties (Successful Efforts Method of Accounting) 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, NGL and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. 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. Proved 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. Under such test, 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. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property. 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. We recorded impairment charges in 2018 , 2017 and 2016 and it is possible that other assets could become impaired in the future. See Note 14. Fair Value Measurements and Disclosures . 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, NGL and natural gas 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. 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 7. 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 oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL and natural gas 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. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values. 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 on 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. 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 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, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Property, Plant and Equipment, Other Other property includes automobiles, trucks, airplanes, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging 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 interest rate we pay on long-term debt, including our unsecured revolving credit facilities and bonds. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis. Capitalized interest totaled $73 million in 2018 , $49 million in 2017 , and $84 million in 2016 . Asset Retirement Obligations 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 we have an existing legal obligation associated with the retirement that can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying value of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by the expected future cash outflows required to satisfy the 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 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 8. Asset Retirement Obligations . Goodwill Goodwill is not amortized to earnings but is assessed for impairment at the reporting unit level on an annual basis, or more frequently as circumstances require. We use qualitative and quantitative assessments to determine whether goodwill is impaired. If we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, an impairment charge is recognized for the amount by which the carrying amount exceeds the fair value. We conducted our annual goodwill impairment assessment as of September 30, 2018. As of that date, our consolidated balance sheet included goodwill of $1.4 billion , of which $ 1.3 billion was allocated to our Texas reporting unit, included within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. At that time, we concluded that goodwill was not impaired. During fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that the goodwill allocated to the Texas reporting unit was fully impaired and recorded a charge of $1.3 billion . See Note 6. Goodwill Impairment . Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners through Black Diamond in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2018 , the net book value of our intangible assets was $ 310 million. Amortization expense, which is equivalent to accumulated amortization for 2018 , of $30 million is included in DD&A expense in our consolidated statements of operations and statements of cash flows. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See Note 5. Acquisitions and Divestitures . Exit Costs In accordance with Accounting Standards Codification (ASC) 420 – Exit or Disposal Cost Obligations , we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions including: 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 exit cost liabilities at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will be recognized as an adjustment to the liability in the period of the change. Exit cost liabilities are included in other current and other noncurrent liabilities on our consolidated balance sheets. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations. Accrued exit costs at December 31, 2018 and 2017 relate primarily to estimated costs associated with Marcellus Shale contracts. See Note 10. Marcellus Shale Firm Transportation Commitments . Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on our consolidated balance sheets as either an asset or liability and are 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 against 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. See Note 13. Derivative Instruments and Hedging Activities . Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded on grant-date at 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 ASC 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 17. Stock-Based and Other Compensation Plans . 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, 2018 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. 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 11. 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. Income Taxes and Impact of Tax Reform Legislation We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. We account for income taxes using 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 12. 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 We recognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers . See Note 4. Revenue from Contracts with Customers . 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. In the event of a net loss, we exclude the effect of outstanding common stock equivalents from the calculation of diluted EPS as the inclusion would be anti-dilutive. Recently Issued Accounting Standards Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize a right of use asset (ROU asset) and lease liability on the balance sheet for the rights and obligations created by leases. 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. In July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements , which provides for an alternative transition method by allowing entities to initially apply the new leases standard at the adoption date (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard is 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, field services and well equipment, office space and other assets. We adopted the new standard on the effective date of January 1, 2019, using a modified retrospective approach as permitted under ASU 2018-11. The new standard provides a number of optional practical expedients in transition. We expect to: • elect the package of 'practical expedients', which permits us not to reassess under the new s

Additional Financial Statement

Additional Financial Statement Information	12 Months Ended
	Dec. 31, 2018
Additional Financial Statement Information [Abstract]
Additional Financial Statement Information	Note 2. Additional Financial Statement Information Statements of Operations Information Other statements of operations information is as follows: Year Ended December 31, (millions) 2018 2017 2016 Sales of Purchased Oil and Gas and Other Sales of Purchased Oil and Gas (1) $ 275 $ — $ — Income from Equity Method Investees 172 177 102 Midstream Services Revenues - Third Party 78 19 — Total $ 525 $ 196 $ 102 Production Expense Lease Operating Expense $ 576 $ 571 $ 542 Production and Ad Valorem Taxes 190 118 57 Gathering, Transportation and Processing Expense 393 432 480 Other Royalty Expense 38 20 21 Total $ 1,197 $ 1,141 $ 1,100 Exploration Expense Leasehold Impairment and Amortization $ 1 $ 62 $ 148 Dry Hole Cost 1 9 579 Seismic, Geological and Geophysical 22 27 76 Staff Expense 54 55 77 Other 51 35 45 Total $ 129 $ 188 $ 925 Loss on Marcellus Shale Upstream Divestiture and Other Loss on Sale $ — $ 2,270 $ — Exit Cost — 93 — Other — 16 — Total $ — $ 2,379 $ — Other Operating Expense, Net Marketing Expense (2) $ 40 $ 47 $ 58 Cost of Purchased Oil and Gas (1) 296 — — Clayton Williams Energy Acquisition Expenses — 100 — Gain on Asset Retirement Obligation Revisions (3) (25 ) (42 ) — Other, Net 35 33 77 Total $ 346 $ 138 $ 135 (1) As part of the Saddle Butte Acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we entered into certain transactions beginning in first quarter 2018 for the purchase of third-party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. See Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments . (2) Amounts relate to shortfalls in transporting or processing minimum volumes under certain financial commitments primarily in the DJ Basin for 2018 and in the DJ Basin and Marcellus Shale for 2017 (prior to the Marcellus Shale upstream divestiture) and 2016. (3) Gains due to downward ARO revisions in locations where we have no remaining assets. See Note 8. Asset Retirement Obligations . Balance Sheet Information Other balance sheet information is as follows: December 31, (millions) 2018 2017 Accounts Receivable, Net Commodity Sales $ 383 $ 455 Joint Interest Billings (1) 137 207 Other 111 103 Allowance for Doubtful Accounts (15 ) (17 ) Total $ 616 $ 748 Other Current Assets Commodity Derivative Assets $ 180 $ — Inventories, Materials and Supplies 55 66 Inventories, Crude Oil 12 16 Assets Held for Sale (2) 133 629 Restricted Cash (3) 3 38 Prepaid Expenses and Other Assets, Current 35 31 Total $ 418 $ 780 Other Noncurrent Assets Equity Method Investments $ 286 $ 305 Customer-Related Intangible Assets, Net (4) 310 — Mutual Fund Investments 38 57 Net Deferred Income Tax Asset 21 25 Other Assets, Noncurrent 76 74 Total $ 731 $ 461 Other Current Liabilities Production and Ad Valorem Taxes $ 103 $ 84 Commodity Derivative Liabilities 1 58 Income Taxes Payable 22 18 Asset Retirement Obligations 118 51 Interest Payable 66 67 Current Portion of Capital Lease Obligations 41 61 Liabilities Associated with Assets Held for Sale (2) 1 55 Compensation and Benefits Payable 83 98 Other Liabilities, Current 84 86 Total $ 519 $ 578 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 147 $ 197 Asset Retirement Obligations 762 824 Marcellus Shale Exit Cost Accrual 67 76 Production and Ad Valorem Taxes 83 69 Commodity Derivative Liabilities 26 15 Other Liabilities, Noncurrent 80 64 Total $ 1,165 $ 1,245 (1) We bill partners for their share of expenses of joint venture projects for which we are the operator. These projects, especially those in deepwater or remote international locations, can be very capital cost intensive. Our receivables from joint interest billings decreased significantly in 2018 due to the second quarter 2018 sale of our Gulf of Mexico offshore assets. (2) Assets held for sale at December 31, 2018 include certain proved and unproved non-core acreage in Reeves County, Texas. 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 field, our investment in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments, including CONE Midstream and CONE Gathering. Liabilities associated with assets held for sale primarily represent ARO and other liabilities to be assumed by the purchaser. See Note 5. Acquisitions and Divestitures . (3) Balance at December 31, 2018 represents amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures . (4) Amount relates to intangible assets acquired in the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures . Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: December 31, (millions) 2018 2017 Cash and Cash Equivalents at Beginning of Period $ 675 $ 1,180 Restricted Cash at Beginning of Period 38 30 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 713 $ 1,210 Cash and Cash Equivalents at End of Period $ 716 $ 675 Restricted Cash at End of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 719 $ 713 A significant portion of our cash is located in 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. Supplemental statements of cash flow information are as follows: Year Ended December 31, (millions) 2018 2017 2016 Cash Paid During the Year For Interest, Net of Amount Capitalized $ 270 $ 346 $ 327 Income Taxes Paid, Net 172 121 236 Non-Cash Financing and Investing Activities Increase in Capital Lease Obligations 14 — 5

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	Note 3. Segment Information We have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname, Falkland Islands, Canada, and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets. The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. To assess the performance of Noble Energy's operating segments, the chief operating decision maker analyzes income (loss) before income taxes. Management believes income (loss) before income taxes provides information useful in assessing the Company's operating and financial performance across periods. Expenses related to debt, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, are recorded at the corporate level. Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2018 Crude Oil Sales $ 2,945 $ 2,548 $ 7 $ 390 $ — $ — $ — $ — NGL Sales 587 587 — — — — — — Natural Gas Sales 929 435 473 21 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,461 3,570 480 411 — — — — Sales of Purchased Oil and Gas 275 20 — — — 142 — 113 Income from Equity Method Investees 172 — — 132 — 40 — — Midstream Services Revenues - Third Party 78 — — — — 78 — — Intersegment Revenues — 351 (351 ) Total Revenues 4,986 3,590 480 543 — 611 (351 ) 113 Lease Operating Expense 576 480 26 97 — — (27 ) — Production and Ad Valorem Taxes 190 184 — — — 6 — — Gathering, Transportation and Processing Expense 393 533 — — — 95 (235 ) — Other Royalty Expense 38 38 — — — — — — Total Production Expense 1,197 1,235 26 97 — 101 (262 ) — Exploration Expense 129 48 7 6 68 — — — DD&A 1,934 1,642 60 115 2 87 (20 ) 48 (Gain) Loss on Divestitures, Net (843 ) 36 (376 ) — — (503 ) — — Asset Impairments 206 169 — — — 37 — — Goodwill Impairment 1,281 1,281 — — — — — — Cost of Purchased Oil and Gas 296 20 — — — 136 — 140 Gain on Asset Retirement Obligation Revisions (25 ) — (8 ) — (17 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (70 ) — 7 — — — — Income (Loss) Before Income Taxes 140 (875 ) 742 305 (53 ) 726 (60 ) (645 ) Additions to Long Lived Assets 3,253 2,115 671 12 — 521 (91 ) 25 Property, Plant and Equipment, Net 18,419 13,044 2,630 805 37 1,742 (145 ) 306 Year Ended December 31, 2017 Crude Oil Sales $ 2,346 $ 1,993 $ 6 $ 347 $ — $ — $ — $ — NGL Sales 493 493 — — — — — — Natural Gas Sales 1,221 670 528 23 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,060 3,156 534 370 — — — — Income from Equity Method Investees 177 — — 120 — 57 — — Midstream Services Revenues - Third Party 19 — — — — 19 — — Intersegment Revenues — — — — — 277 (277 ) — Total Revenues 4,256 3,156 534 490 — 353 (277 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Lease Operating Expense 571 466 29 90 — — (14 ) — Production and Ad Valorem Taxes 118 115 — — — 3 — — Gathering, Transportation and Processing Expense 432 550 — — — 70 (188 ) — Other Royalty Expense 20 20 — — — — — — Total Production Expense 1,141 1,151 29 90 — 73 (202 ) — Exploration Expense 188 102 2 5 79 — — — DD&A 2,053 1,739 76 146 4 30 (5 ) 63 Loss on Marcellus Shale Upstream Divestiture and Other 2,379 2,286 — — — — — 93 Gain on Divestitures, Net (326 ) (325 ) (1 ) — — — — — Asset Impairments 70 63 — — 7 — — — Clayton Williams Energy Acquisition Expenses 100 100 — — — — — — Gain on Asset Retirement Obligation Revision (42 ) — — — (42 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (92 ) — 29 — — — — Loss on Debt Extinguishment 98 — — — — — — 98 (Loss) Income Before Income Taxes (2,191 ) (2,365 ) 413 203 (54 ) 233 (62 ) (559 ) Additions to Long Lived Assets 2,851 1,994 411 34 (34 ) 423 (79 ) 102 Property, Plant and Equipment, Net 17,502 13,348 2,005 863 25 1,027 (74 ) 308 Year Ended December 31, 2016 Crude Oil Sales $ 1,854 $ 1,439 $ 5 $ 410 $ — $ — $ — $ — NGL Sales 296 296 — — — — — — Natural Gas Sales 1,239 681 535 23 — — — — Total Crude Oil, NGL and Natural Gas Sales 3,389 2,416 540 433 — — — — Income from Equity Method Investees 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 57 55 — — — 2 — — Gathering, Transportation and Processing Expense 480 564 — — — 44 (128 ) — Other Royalty Expense 21 21 — — — — — — Total Production Expense 1,100 1,058 37 105 — 46 (146 ) — Exploration Expense 925 245 34 483 163 — — — DD&A 2,454 2,103 81 205 6 19 — 40 (Gain) Loss on Divestitures, Net (238 ) 23 (261 ) — — — — — Asset Impairments 92 — 88 — 4 — — — Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Loss on Commodity Derivative Instruments 139 126 — 13 — — — — (Loss) Income Before Income Taxes (1,772 ) (1,277 ) 543 (338 ) (199 ) 176 (51 ) (626 ) Additions to Long Lived Assets 1,526 1,353 88 54 (6 ) 58 (53 ) 32 Property, Plant and Equipment, Net 18,548 14,755 1,872 980 15 594 — 332 (1) Intersegment eliminations related to income (loss) 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. The largest single non-affiliated purchasers of our production were as follows: Percentage of Crude Oil Sales Percentage of Total Oil, NGL & Gas Sales Year Ended December 31, 2018 BP (1) 31 % 17 % Shell (2) 22 % 14 % 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 % (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. Both BP and Shell purchased crude oil and condensate domestically from our US onshore operations and from our Gulf of Mexico operations prior to selling the Gulf of Mexico assets in second quarter 2018. No other single purchaser accounted for 10% or more of crude oil, NGL and natural gas sales in 2018. We maintain credit insurance associated with specific purchasers and believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations as there are numerous potential purchasers of our production.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Note. 4. Revenue from Contracts with Customers Our revenue is derived from the sale of crude oil, NGL and natural gas production, primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers (ASC 606), which we adopted on January 1, 2018 using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered. ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on a gross basis if we control a promised good or service before transferring it to a customer (acting as principal). For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services (acting as agent). For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue. Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging , and will account for such contracts in accordance with ASC 606. In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis. ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption impact on revenues and expenses for 2018 was less than $1 million and did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward. See Note 3. Segment Information for disaggregation of revenue by commodity and geographic location. Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition , where we previously determined that we retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements. Following the control model in ASC 606, we determined that we remain the principal in arrangements with end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production to downstream customers. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis. Our commodity sales contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period. The following is a summary of our types of revenue arrangements by commodity and geographic location. Exploration and Production Revenue Arrangements Crude Oil Sale Arrangements – US We sell the majority of our US crude oil production under short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale. We sell our crude oil production either at the lease location or to downstream customers. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product. When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil to downstream customers is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer. In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing. Crude Oil Buy/Sell Transactions – US We enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions . We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations. Crude Oil Sale Arrangements – West Africa Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd. (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees. Natural Gas and NGLs Sale Arrangements – US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we treat the processor as a customer and record revenue when the processor takes physical possession of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor. In other natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, where we have determined that the processor is a service provider, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer. Natural Gas Purchase and Sale Arrangements – US We enter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation contracts. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production from the Alba field under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors. Natural Gas Sale Arrangements – Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant to ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no material impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations. Transaction Price Allocated to Remaining Performance Obligations – Israel Remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts and long-term dedicated production agreements are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However, certain of our Tamar natural gas sales contracts in Israel have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments. (millions) 2019 2020 Total Natural Gas Revenues (1) $ 137 $ 169 $ 306 (1) The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes. Midstream Revenue Arrangements Service Arrangements Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses. Crude Oil Purchase and Sale Arrangements In first quarter 2018, Noble Midstream Partners acquired an interest in Black Diamond which completed the Saddle Butte Acquisition of a large-scale integrated gathering system and associated third-party

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 5. Acquisitions and Divestitures We maintain an ongoing portfolio management program and have engaged in various transactions over recent years. Year Ended December 31, 2018 Divestiture of Gulf of Mexico Assets On February 15, 2018, we announced that we had signed a definitive agreement to sell our Gulf of Mexico assets, including all of our interests in producing properties and undeveloped acreage, for cash consideration of $480 million , along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, we recorded impairment expense of $168 million during first quarter 2018. In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, to date we have received net proceeds of $384 million and recorded a loss of $24 million . In addition, a cumulative contingent payment of up to $100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of December 31, 2018 , $3 million has been accrued related to the contingent payment. Divestiture of 7.5% Interest in Tamar Field On March 14, 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million . The transaction had an effective date of January 1, 2018 and, after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash. Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $ 376 million . We incurred tax expense of $86 million in connection with the transaction. The Tamar Petroleum shares were subject to certain temporary lock-up provisions and had no voting rights. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lower than the publicly traded value on the TASE. These shares were accounted for at fair value and we recorded decreases in fair value of $27 million and dividend income of $31 million during 2018. These amounts are included in other non-operating (income) expense, net, in our consolidated statements of operations. In fourth quarter 2018, we sold 38.5 million shares of Tamar Petroleum in over the counter transactions for pre-tax proceeds of $163 million , net of transaction expenses. Upon sale, voting rights were restored and granted to the third parties. The sales of the 7.5% working interest in the Tamar field and of the Tamar Petroleum shares are in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021. Divestiture of Southwest Royalties In January 2018, we closed the sale of our investment in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million , resulting in no gain or loss recognition on the sale of these assets. Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $309 million in cash and recognized a pre-tax gain of $ 196 million . After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During 2018, we sold our 21.7 million common units, receiving net proceeds of approximately $387 million , and recognized a gain of $307 million . The investment was previously accounted for under the equity method of accounting. Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in the Greeley Crescent area of the DJ Basin and received proceeds of $68 million , resulting in no gain or loss recognition on the sale of these assets. Divestiture of Non-Core Delaware Basin Acreage In December 2018, we closed the sale of certain non-core acreage in the Delaware Basin, receiving proceeds of $63 million , resulting in a pre-tax loss of $16 million . DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 12,900 net undeveloped acres within core areas of our Mustang and Wells Ranch positions in exchange for approximately 12,300 net undeveloped acres in non-core areas of Mustang and Wells Ranch. No gain or loss was recognized. Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Noble Midstream Partners acquired a 54.4% in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte from Saddle Butte Pipeline II, LLC (Saddle Butte Acquisition). Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million , which included $663 million of cash and assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond as a VIE and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity. This transaction was accounted for as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on the fair value at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair value included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill. Noble Midstream Partners has completed the purchase price allocation related to this acquisition. Other Acquisitions and Divestitures During 2018, we closed on the acquisition of other smaller US onshore properties for total cash consideration of $3 million . We also closed the sale of certain other smaller US onshore proved and unproved properties and received total cash consideration of $81 million, recording a gain of $4 million . Subsequent Events In first quarter 2019, we closed the sale of certain proved and unproved non-core acreage totaling approximately 13,000 net acres in Reeves County, Texas. We received cash consideration of $132 million , recognizing no gain or loss on the sale. As of December 31, 2018, the assets and related liabilities associated with this acreage were considered held for sale and were recorded within other current assets and other current liabilities on our consolidated balance sheets. In first quarter 2019, Noble Midstream Partners exercised and closed an option with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in the EPIC Y-Grade Pipeline. It also exercised an option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline, for which closing is anticipated to occur later in first quarter 2019, subject to certain conditions precedent. Year Ended December 31, 2017 Clayton Williams Energy Acquisition On April 24, 2017 , we completed the Clayton Williams Energy Acquisition. Clayton Williams Energy's results of operations since the acquisition date are included in our consolidated statement of operations. 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 9. Long-Term Debt . The acquired assets included 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 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. In connection with the acquisition, we incurred acquisition-related costs of $100 million , 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 was accounted for as a business combination using the acquisition method. The following table represents the 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. The following table sets forth our purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,851 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,488 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 515 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,798 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) 1,291 Total Asset Value $ 3,798 (1) The goodwill, which was associated with the Texas reporting unit included within our oil and gas exploration and production segment, was fully impaired as of December 31, 2018. See Note 6. Goodwill Impairment . 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 AROs 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 AROs 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. 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) 2018 (1) 2017 2016 Revenues $ 4,986 $ 4,304 $ 3,651 Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy (66 ) (678 ) (1,082 ) Net Income (Loss) Attributable to Noble Energy per Common Share Basic $ (0.14 ) $ (1.39 ) $ (2.23 ) Diluted $ (0.14 ) $ (1.39 ) $ (2.23 ) (1) No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results. 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 closing adjustments. 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. 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 9. Long-Term Debt . For the year ended December 31, 2017, we recognized a loss on divestiture of $2.3 billion , or $1.5 billion after-tax. The aggregate net book value of the properties sold was approximately $3.4 billion , which included approximately $883 million of undeveloped leasehold cost. 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) . After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 10. Marcellus Shale Firm Transportation Commitments . Other US Onshore Transactions We conducted the following additional transactions in 2017: • 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. • 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. • completed the acquisition of Delaware Basin properties, including seven producing wells, 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. 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 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 15. 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. Other Acquisitions and Divestitures During 2017, we closed on the acquisition of other smaller US onshore properties for total cash consideration of $26 million . We also closed the sale of certain other smaller US onshore and international properties and received total cash consideration of $ 39 million, recording a loss of $6 million . 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. Other Divestitures During 2016, we also closed the sale of certain smaller US onshore properties and received total cash consideration of $83 million, with no recognition of gain or loss. See Supplemental Oil and Gas Information (Unaudited)

Goodwill Impairment

Goodwill Impairment	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill Impairment	Note 6. Goodwill Impairment As of December 31, 2017 and through September 30, 2018, our consolidated balance sheet included goodwill of $1.4 billion , of which $ 1.3 billion, resulting from the Clayton Williams Energy Acquisition, was allocated to our Texas reporting unit, included within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. We conducted our annual goodwill impairment assessment as of September 30, 2018. At that time, we concluded that goodwill was not impaired. In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. For purposes of determining the 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 indicated that the implied fair value of our Texas reporting unit goodwill was zero and we recognized a loss of $ 1.3

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	12 Months Ended
	Dec. 31, 2018
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost. Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows: Year Ended December 31, (millions) 2018 2017 2016 Capitalized Exploratory Well Costs, Beginning of Period $ 520 $ 768 $ 1,353 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 7 20 84 Divestitures and Other (1) (168 ) — (143 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) (1 ) (203 ) (1 ) Capitalized Exploratory Well Costs Charged to Expense (3) (4 ) (65 ) (525 ) Capitalized Exploratory Well Costs, End of Period $ 354 $ 520 $ 768 (1) The 2018 amount represents costs primarily related to Gulf of Mexico assets sold during second quarter and 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. (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. 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, Gulf of Mexico, which did not encounter commercial hydrocarbons and was subsequently plugged and abandoned. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: December 31, (millions) 2018 2017 2016 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 6 $ 10 $ 69 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 348 510 699 Balance at End of Period $ 354 $ 520 $ 768 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 8 10 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, 2018 : Suspended Since Country/Project (millions) Total 2016 - 2017 2014 - 2015 2013 & Prior Progress Offshore Equatorial Guinea Felicita (Block O) $ 48 $ 3 $ 7 $ 38 We are in process of evaluating regional development scenarios for this 2008 natural gas discovery. In early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. In 2018, we progressed definitive agreements to sell natural gas through the Punta Europa plants, which will expand the options for additional natural gas sales. Yolanda (Block I) 24 2 3 19 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 development team is working with both governments to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales. Offshore Cameroon YoYo (YoYo Block) 52 (1 ) 6 47 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 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. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales. Offshore Israel Leviathan-1 Deep 94 6 8 80 The well did not reach the target interval in 2012. In 2018, we continued to reprocess and review seismic information for this prospect, incorporating information obtained from other recent discoveries in the region and developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 24 2 3 19 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. Currently, we are analyzing 3D seismic data to evaluate additional potential of the area. Offshore Cyprus Cyprus 100 11 12 77 We continue to work with the Government of Cyprus to obtain approval of our development plan and the issuance of an Exploitation License. During 2017, we submitted an updated development plan. During 2018, we continued to progress capital project cost improvement and regional natural gas marketing efforts. Other Projects less than $20 million 6 (7 ) 10 3 Continuing to assess and evaluate wells. Total $ 348 $ 16 $ 49 $ 283 Undeveloped Leasehold Costs Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. 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. Changes in undeveloped leasehold costs were as follows: December 31, (millions) 2018 2017 Undeveloped Leasehold Costs, Beginning of Period $ 2,922 $ 2,197 Additions to Undeveloped Leasehold Costs (1) 47 1,859 Transfers to Proved Properties (2) (453 ) (174 ) Assets Sold (3) (142 ) (884 ) Impairment (4) (1 ) (62 ) Other — (14 ) Undeveloped Leasehold Costs, Net of Impairment, End of Period $ 2,373 $ 2,922 (1) 2017 additions relate to the Clayton Williams Energy Acquisition and Delaware Basin asset acquisition. (2) 2018 transfers relate primarily to Delaware Basin assets. (3) 2017 sales relate primarily to the Marcellus Shale upstream divestiture. (4) 2017 impairment expense was primarily attributable to Gulf of Mexico leases. As of December 31, 2018 , remaining undeveloped leasehold costs, to which proved reserves had not been attributed, totaled $ 2.4 billion, including $2.2 billion and $100 million attributable to Delaware Basin and Eagle Ford Shale, respectively. The remaining balance of undeveloped leasehold costs as of December 31, 2018 included $53 million and $31 million

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 8. Asset Retirement Obligations ARO consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Year Ended December 31, (millions) 2018 2017 Asset Retirement Obligations, Beginning Balance $ 875 $ 935 Liabilities Incurred 25 94 Liabilities Settled (345 ) (82 ) Revisions of Estimates 293 (65 ) Reclassification to Liabilities Associated with Assets Held for Sale (1 ) (54 ) Accretion Expense 33 47 Asset Retirement Obligations, Ending Balance $ 880 $ 875 Year Ended December 31, 2018 Liabilities settled primarily included $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $104 million related to abandonment of US onshore properties, primarily in the DJ Basin, where we have engaged in a program to plug and abandon older vertical wells. Costs associated with the DJ Basin abandonment activities will be incurred over several years. Revisions of estimates were primarily related to increases in cost estimates and changes in timing estimates of $287 million for US onshore, primarily in the DJ Basin related to the abandonment activities noted above, $ 10 million for wells offshore Israel and $ 9 million for wells offshore Equatorial Guinea, partially offset by decreases in cost and timing estimates of $17 million associated with the North Sea abandonment project. 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 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, respectively, to liabilities associated with assets held for sale. See Note 5. Acquisitions and Divestitures

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-term Debt	Note 9. Long-Term Debt Our debt consists of the following: December 31, 2018 December 31, 2017 (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due March 9, 2023 $ — — % $ 230 2.27 % Noble Midstream Services Revolving Credit Facility, due March 9, 2023 60 3.67 % 85 2.75 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 3.42 % — — % Senior Notes, due May 1, 2021 (1) — — % 379 5.63 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % 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 600 3.85 % 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 500 4.95 % 500 4.95 % Other Senior Notes and Debentures (2) 92 7.13 % 92 7.13 % Capital Lease Obligations 223 — % 273 — % Total $ 6,675 $ 6,859 Unamortized Discount (22 ) (24 ) Unamortized Premium (1) — 12 Unamortized Debt Issuance Costs (38 ) (40 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs $ 6,615 $ 6,807 Less Amounts Due Within One Year: Capital Lease Obligations (41 ) (61 ) Long-Term Debt Due After One Year $ 6,574 $ 6,746 (1) In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, and expensed the associated premium. See Redemption of Notes , below. (2) Includes $8 million of 5.875% Senior Notes due June 1, 2024 and $84 million of 7.25% Senior Debentures due August 1, 2097. 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 Credit Agreement, as amended, provides for a $ 4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating, and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $ 500 million under each sub-facility. 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. We were in compliance with our debt covenants as of December 31, 2018 . 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. In the first quarter 2018, we extended the maturity date of the Revolving Credit Facility from August 2020 to March 2023. As of December 31, 2018 , no borrowings were outstanding under the Revolving Credit Facility. Noble Midstream Services Revolving Credit Facility Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, maintains a revolving credit facility (Noble Midstream Services Revolving Credit Facility), which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners. Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00% ; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. 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. In first quarter 2018, the capacity was increased from $350 million to $800 million and the maturity date was extended from September 2021 to March 2023. In third quarter 2018, we used $480 million proceeds from the issuance of a new term loan credit facility to repay a portion of the balance outstanding under the Noble Midstream Services Revolving Credit Facility. See Noble Midstream Services Term Loan Credit Facility, below. As of December 31, 2018 , $ 60 million was outstanding under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services Term Loan Credit Facility In third quarter 2018, Noble Midstream Services entered into a Term Credit Agreement (Noble Midstream Services Term Credit Agreement), which provides for a three year senior unsecured term loan credit facility (Noble Midstream Services Term Loan Credit Facility) and permits aggregate borrowings of up to $ 500 million . Proceeds from the Noble Midstream Services Term Loan Credit Facility were used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility and to pay fees and expenses in connection with the Noble Midstream Services Term Loan Credit Facility. Borrowings under the Noble Midstream Services Term Loan Credit Facility bear interest at a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum. As of December 31, 2018 , $ 500 million was outstanding under the Noble Midstream Services Term Loan Credit Facility. The Noble Midstream Services Term Loan Credit Facility contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream Services Term Loan Credit Facility, the lenders may declare all amounts outstanding under the Noble Midstream Services Term Loan Credit Facility to be immediately due and payable and exercise other remedies as provided by applicable law. Redemption of Senior Notes In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021 that we assumed in the merger with Rosetta Resources, Inc. in 2015 for $395 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 $1.1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1.1 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 provided for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion , of which $625 million was initially committed. Any amounts borrowed under the Leviathan Term Loan Facility would have been available to fund a portion of our share of costs for the initial phase of development of the Leviathan field. No amounts were ever drawn on the facility, which was terminated in December 2018. Fair Value of Debt See Note 14. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt. Capital Lease 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 11. Commitments and Contingencies for future capital lease payments. Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2018 are as follows: (millions) Debt Principal Payments 2019 $ — 2020 — 2021 1,500 2022 — 2023 160 Thereafter 4,792 Total $ 6,452

Marcellus Shale Firm Transporta

Marcellus Shale Firm Transportation Commitments	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Marcellus Shale Firm Transportation Commitments	Note 10. Marcellus Shale Firm Transportation Commitments On June 28, 2017, we closed the sale of our Marcellus Shale upstream assets, which were primarily natural gas properties. In connection with the divestiture, we retained certain financial commitments on pipelines flowing natural gas production inside and outside of the Marcellus Basin. These financial commitments represent commitments to pay transportation fees; thus, we have no commitment to physically transport minimum volumes of natural gas. Since closing, we have continued efforts to commercialize these firm transportation commitments including the permanent assignment of capacity, negotiation of capacity releases, utilization of capacity through purchase and transport of third-party natural gas, and other potential arrangements. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross contractual commitment is reduced. In the event we execute a capacity release or utilize the capacity through the purchase and transport of third-party natural gas, we remain the primary obligor to the pipeline company. While our gross contractual commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties. As of December 31, 2018 , our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately four to fifteen years, is approximately $1.5 billion , undiscounted. See Note 11. Commitments and Contingencies . One of the retained contracts relates to the Texas Eastern Pipeline. This contract is being fully utilized through a capacity release agreement with the acquirer of the Marcellus Shale upstream assets. The financial commitment on this contract is being fully mitigated by a netback agreement with the purchaser. One of the retained contracts relates to the Appalachian Gateway Project. In 2017, we recorded an exit cost of $41 million , discounted, related to this contract, as we no longer have production to satisfy the commitment and do not plan to utilize this capacity in the future. Additional retained contracts relate to the Leach Xpress and Rayne Xpress (Leach/Rayne Xpress) pipelines. In 2017, we permanently assigned a portion of the capacity, recording an exit cost of $52 million , discounted, related to future commitments to the third-party. Throughout 2018, we mitigated the impact of the remaining capacity through purchasing third-party natural gas and selling the natural gas to other third parties at prevailing market prices. Revenues and expenses associated with these activities are recorded on a gross basis, as we act as a principal in these arrangements by assuming control of the purchased commodity before it is transferred to the customer. In addition to the retained firm transportation commitments, we also have the following accrued discounted liabilities associated with the exit cost activities described above: December 31, (millions) 2018 2017 Balance at Beginning of Period $ 90 $ — Marcellus Exit Cost Accrual — 93 Payments, Net of Accretion (10 ) (3 ) Balance at End of Period $ 80 $ 90 Less Current Portion Included in Other Current Liabilities 13 14 Long-term Portion Included in Other Noncurrent Liabilities $ 67 $ 76 Two additional retained contracts relate to the WB Xpress and NEXUS pipelines. In fourth quarter 2018, we entered into capacity release agreements with third parties extending through March and October 2020, respectively. Revenues and expenses associated with these agreements, as well as those associated with purchasing and selling third-party natural gas to mitigate Leach/Rayne Xpress capacity, are as follows: Year Ended December 31, (millions) Statements of Operations Location 2018 2017 2016 Sales of Purchased Gas Sales of Purchased Oil and Gas and Other $ 113 $ — $ — Cost of Purchased of Gas Other Operating Expense, Net 108 — — Utilized Firm Transportation Expense (1) Other Operating Expense, Net 29 — — Unutilized Firm Transportation Expense Other Operating Expense, Net 3 — — Cost of Purchased Gas, Total Other Operating Expense, Net $ 140 $ — $ — (1) Includes the net impact of the difference in the firm transportation contract rates and the rates agreed to in the capacity releases. Additionally, amount includes transportation expense associated with our transport of purchased natural gas on Leach/Rayne Xpress. We expect to continue our commercialization actions, including utilizing pipeline capacity through purchases of third-party natural gas and sales to other third parties, to mitigate these firm transportation commitments. Some of our commercialization efforts may require pipeline and/or FERC approval to ultimately reduce the financial commitment associated with these contracts. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment. We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities. See Note 5. Acquisitions and Divestitures . Subsequent Event In January 2019, we executed agreements on Leach/Rayne Xpress to permanently assign the remaining capacity to a third-party effective January 1, 2021 extending through the remainder of the contract term. The permanent assignment reduces our total undiscounted financial commitment under the Marcellus Shale firm transportation contracts by approximately $350 million . In January 2019, we recorded exit costs of $92 million

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 11. 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 (EPA), 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 corrective actions, to complete mitigation projects, to complete supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 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. Since 2015, we have incurred approximately $84 million , of which $77 million was incurred to undertake corrective actions 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, plugging and abandonment activities, and mitigation expenditures that result from this settlement, based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. See Note 8. Asset Retirement Obligations . 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. In October 2018, we met with enforcement staff at the Colorado Department of Public Health and Environment (CDPHE) to discuss a potential settlement of the alleged violations. Given the ongoing status of such settlement discussions, 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 and Gas Conservation Commission Administrative Order on Consent In July 2018, we resolved by Administrative Order on Consent (AOC) with the Colorado Oil and Gas Conservation Commission (COGCC) allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC required us to pay an administrative penalty of $135 thousand ( $41 thousand of which is deferred subject to a nine-month compliance schedule) and to complete certain corrective actions at five oil and gas locations in Weld County, Colorado. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Mechanical Integrity Testing Matter In September 2018, we resolved by AOC with the COGCC administrative claims for allegations of noncompliance of State mechanical integrity testing rules at eight shut-in wells in Weld County, Colorado. The AOC includes an administrative penalty of $1.6 million , of which $1.4 million of the total penalty is to be offset by our commensurate contribution to two public projects and our requirement to repair or plug and abandon each of the eight wells and to submit to COGCC certain environmental data. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. The letter requests an opportunity to discuss settlement of the alleged violations. Given the uncertainty associated with enforcement 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. Marcellus Shale Firm Transportation 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. See Note 10. Marcellus Shale Firm Transportation Commitments . Other Transportation and Gathering Obligations We have transportation and gathering obligations to flow US onshore production, primarily in the DJ Basin, to various markets. Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. These amounts are recorded as marketing expense in our consolidated statements of operations. Our total financial commitment for these agreements, which have remaining terms of two to ten years, is approximately $ 612 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 $90 million in 2018 , $69 million in 2017 , and $76 million in 2016 . Minimum commitments as of December 31, 2018 consist of the following: (millions) Purchase and Service Obligations Marcellus Shale Firm Transportation and Other Obligations (1) Gathering, Transportation & Processing Obligations Operating Lease Obligations (2) Capital Lease Obligations (2) Total 2019 $ 197 $ 123 $ 151 $ 91 $ 52 $ 614 2020 29 122 129 74 46 400 2021 13 121 103 59 31 327 2022 6 118 67 62 22 275 2023 21 113 66 50 20 270 2024 and Thereafter 5 934 285 176 104 1,504 Total $ 271 $ 1,531 $ 801 $ 512 $ 275 $ 3,390 (1) Amount includes exit cost obligations resulting from a permanent capacity assignment. See Note 10. Marcellus Shale Firm Transportation Commitments . (2) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. Long-Term Debt

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 12. Income Taxes Components of income (loss) from operations before income taxes are as follows: Year Ended December 31, (millions) 2018 2017 2016 Domestic $ (953 ) $ (2,831 ) $ (1,859 ) Foreign 1,093 640 87 Total $ 140 $ (2,191 ) $ (1,772 ) The income tax provision (benefit) consists of the following: Year Ended December 31, (millions, except percentages) 2018 2017 2016 Current Taxes Federal $ 22 $ (11 ) $ (4 ) State 2 1 5 Foreign 172 96 196 Total Current $ 196 $ 86 $ 197 Deferred Taxes Federal $ (123 ) $ (1,258 ) $ (784 ) State (7 ) (8 ) (24 ) Foreign 60 39 (176 ) Total Deferred $ (70 ) $ (1,227 ) $ (984 ) Total Income Tax Provision (Benefit) Attributable to Noble Energy $ 126 $ (1,141 ) $ (787 ) Effective Tax Rate 90.0 % 52.1 % 44.4 % A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, (percentages) 2018 2017 2016 Federal Statutory Rate (1) 21.0 % 35.0 % 35.0 % Effect of Goodwill Impairment 192.5 — — Change in Valuation Allowance (1) (170.2 ) (17.4 ) (2.0 ) US and Foreign Statutory Rate Change (1) 80.7 23.5 1.6 Accumulated Undistributed Foreign Earnings (1) — 11.0 7.2 Transition Tax (1) — (4.8 ) — Difference Between US and Foreign Rates 17.9 1.8 (0.1 ) Earnings of Equity Method Investees (20.1 ) 1.9 1.0 Noncontrolling Interests (12.1 ) 1.1 0.4 State Taxes, Net of Federal Benefit 0.9 0.3 1.3 Foreign Exploration Loss (35.6 ) — — Global Intangible Low-Taxed Income (GILTI) (1) 24.2 — — Return to Provision (17.1 ) (0.1 ) (0.2 ) Audit Settlement 5.1 0.1 (0.2 ) Oil Profits Tax - Israel 3.3 (0.1 ) — Other, Net (0.5 ) (0.2 ) 0.4 Effective Rate 90.0 % 52.1 % 44.4 % (1) See Tax Reform Legislation and Accumulated Undistributed Earnings of Foreign Subsidiaries , below. Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2018 2017 Deferred Tax Assets Loss Carryforwards $ 589 $ 902 Employee Compensation and Benefits 92 97 Mark to Market of Commodity Derivative Instruments (27 ) 7 Foreign Tax Credits 138 366 Other 157 104 Total Deferred Tax Assets $ 949 $ 1,476 Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits (320 ) (549 ) Net Deferred Tax Assets $ 629 $ 927 Deferred Tax Liabilities Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (1,669 ) (2,029 ) Total Deferred Tax Liability $ (1,669 ) $ (2,029 ) Net Deferred Tax Liability $ (1,040 ) $ (1,102 ) Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2018 2017 Deferred Income Tax Asset - Noncurrent $ 21 $ 25 Deferred Income Tax Liability - Noncurrent (1,061 ) (1,127 ) Net Deferred Tax Liability $ (1,040 ) $ (1,102 ) Tax Reform Legislation On December 22, 2017, the US Congress enacted 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. The SEC staff issued SAB 118 which allowed registrants to report provisional amounts for the income tax effects specific to Tax Reform Legislation for which accounting was incomplete but a reasonable estimate could be determined. We reported certain provisional amounts in fourth quarter 2017, some of which were adjusted in 2018 based on changes in estimates, including changes based on further guidance provided by the Internal Revenue Service (IRS). Provisional amounts recorded in 2017 and changes in estimates reported in 2018 are as follows: Remeasurement of Deferred Taxes In accordance with US GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities in the period in which the tax rate change was enacted, resulting in the recognition of a provisional deferred tax benefit of $500 million at December 31, 2017. Further remeasurements of these deferred taxes in 2018 were associated with the return to provision resulted in a $10 million deferred tax benefit. Transition Tax (Toll Tax) Tax Reform Legislation provided for a toll tax on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Based on early interpretations of the law, we recognized additional taxable income in 2017 of $767 million associated with the toll tax, which was fully offset by net operating losses (NOLs), and recorded corresponding deemed foreign tax credits of $164 million , against which we recorded a full valuation allowance. On April 2, 2018, the US Department of the Treasury and the IRS released Notice 2018-26, signaling intent to issue regulations related to the toll tax for the year ended December 31, 2017. Notice 2018-26 clarified that an Internal Revenue Code Section 965(n) election is available with respect to both current and prior year NOLs. As a result, we released $252 million of the valuation allowance recorded against foreign tax credits to be utilized against the estimated $268 million toll tax liability recorded as of December 31, 2017. This resulted in a $252 million tax benefit and a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized NOL's. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit. During fourth quarter 2018, the toll tax calculations were finalized in conjunction with filing of the US tax return, resulting in a $261 million toll tax against which $240 million of foreign tax credits were utilized. This resulted in a $21 million liability payable in installments over eight years beginning in 2018. The additional impact recorded during fourth quarter 2018 was a net $5 million tax expense. Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation also introduced a new tax on global intangible low-taxed income (GILTI). Further analysis and legal interpretation has resulted in identifying certain foreign oil related income (FORI) activity as GILTI income which will be offset by NOL carryforwards rather than the 50% deduction and related foreign tax credits. As a result of utilizing our NOL to offset the GILTI inclusion, we recognized tax expense of $34 million for 2018 GILTI associated with FORI from investments in operating assets in Equatorial Guinea and operations in Israel. We are making an accounting policy election to not record deferred taxes related to GILTI. Other Provisions Tax Reform Legislation is a comprehensive bill containing other provisions that do not materially affect us. The ultimate impact may differ from our estimates if additional regulatory guidance is issued. We are closely monitoring the provision which revised and broadened the former Section 163(j) interest expense limitation rules. In tax years subsequent to 2021 the basis of the limitation calculation will change to be roughly equivalent to EBIT at which time we expect to be subject to an interest expense limitation. The interest expense not deducted due to limitation has an indefinite carryover period. Deferred Tax Assets Our estimated pre-tax NOL carryforwards totaled approximately $2.4 billion at December 31, 2018 , of which US federal income tax NOL carryforwards totaled approximately $1.7 billion and foreign NOL carryforwards were $670 million . 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 $ 187 million and $ 183 million in 2018 and 2017 , respectively. The valuation allowance on foreign tax credits totaled $132 million and $366 million in 2018 and 2017 , respectively. As noted above, in first quarter 2018 we released $252 million of the valuation allowance recorded against the foreign tax credits and in fourth quarter 2018, we made further return to provision adjustments based on the tax return filing. 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. Our purchase price allocation is finalized and we recorded a deferred tax liability of $307 million , adjusted for the new US statutory rate, which includes a deferred tax asset for federal pre-tax NOLs 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. Effective Tax Rate Our effective tax rate increased in 2018 as compared with 2017 , primarily due to the fourth quarter 2018 goodwill impairment for which there is no tax benefit and the deferred tax expense of $34 million for GILTI. This increase was reduced by a deferred tax benefit of $145 million recorded discretely in the current year, as discussed above, and a deferred tax benefit of $ 50 million associated with a write-off of foreign exploration losses. The increase in current income tax expense during 2018 as compared with 2017 is primarily due to foreign taxes on the gain recognized with the first quarter 2018 divestiture of a 7.5% working interest in the Tamar field. The decrease in deferred income tax benefit during 2018 as compared to 2017 is due to the significant deferred tax benefit recorded in 2017 associated with the revaluation of the US deferred tax liability at the reduced future tax rate. Accumulated Undistributed Earnings of Foreign Subsidiaries During 2016, we reduced the deferred tax liability associated with unremitted foreign earnings, net of foreign tax credits, to $240 million . In 2017, as a result of Tax Reform Legislation, which established a new territorial tax regime, we reversed the deferred tax liability recorded in 2016, resulting in a deferred tax benefit of $240 million . As of December 31, 2018, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any tax associated with unremitted earnings. Israeli Tax Law Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and from 24% to 23% effective January 2018. The full impact of the rate reduction was recognized in 2017, decreasing deferred tax expense 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 (Oil Profits Tax). The Oil 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 Oil Profits Tax increases progressively up to a maximum rate of 50%. The Oil 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 Oil Profits Tax rate is calculated. At the current corporate tax rate, the Oil Profits Tax rate is 46.8% . The Oil Profits Tax is deductible for Israeli corporate tax purposes. Our Tamar and Leviathan projects are both subject to the Oil 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 - 2015 , Israel - 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea - 2013 . Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2018 and 2017

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 13. 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, collars and three-way collars, basis swaps, swaptions and/or put options. The fixed price swap and 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 collar contract combined with a put option contract sold by us with a strike price below the floor price of the collar. We receive price protection at the purchased put option floor price of the 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. A swaption gives counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. 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 14. 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, especially during periods of falling prices. Our commodity derivative instruments are currently with a diversified group of major banks or market participants. We monitor the creditworthiness of these counterparties and our internal hedge policies provide for exposure limits. 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. 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, 2018 , we had entered into the following crude oil derivative instruments: Swaps Collars Settlement Period Type of Contract Index Bbls per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2019 Swaps NYMEX WTI 22,000 $ — $ 56.96 $ — $ — $ — 2019 Three-Way Collars NYMEX WTI 33,000 — — 49.35 59.35 72.25 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) 27,000 (3.23 ) — — — — 2020 Swaption NYMEX WTI 5,000 — 61.79 — — — 2020 Basis Swap (1) 15,000 (5.01 ) — — — — (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, 2018 , we had entered into the following natural gas derivative instruments: Swaps Collars Settlement Period Type of Contract Index MMBtu per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 1Q19 (1) Swaps NYMEX HH 86,500 $ — $ 4.36 $ — $ — $ — 1Q19 (1) Three-Way Collars NYMEX HH 21,500 — — 3.00 3.25 4.08 2019 Three-Way Collars NYMEX HH 104,000 — — 2.25 2.65 2.95 2019 Basis Swaps (2) 52,000 (0.74 ) — — — — (1) We have entered into contracts for portions of 2019 resulting in the difference in hedged volumes for the full year. (2) We have entered into natural gas basis swap contracts in order to establish a fixed amount for the differential between index pricing for Colorado Interstate Gas and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts. Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments on our consolidated balance sheets were as follows (1) : Asset Derivative Instruments Liability Derivative Instruments December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 180 Current Assets $ 2 Current Liabilities $ 1 Current Liabilities $ 58 Noncurrent Assets — Noncurrent Assets — Noncurrent Liabilities 26 Noncurrent Liabilities 15 Total $ 180 $ 2 $ 27 $ 73 (1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities . The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2018 2017 2016 Cash Paid (Received) in Settlement of Commodity Derivative Instruments Crude Oil $ 162 $ (14 ) $ (499 ) Natural Gas (1 ) 1 (70 ) Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments 161 (13 ) (569 ) Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (225 ) 18 582 Natural Gas 1 (68 ) 126 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (224 ) (50 ) 708 (Gain) Loss on Commodity Derivative Instruments Crude Oil (63 ) 4 83 Natural Gas — (67 ) 56 Total (Gain) Loss on Commodity Derivative Instruments $ (63 ) $ (63 ) $ 139

Fair Value Measurements and Dis

Fair Value Measurements and Disclosures	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements and Disclosures	Note 14. 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 on 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 considers market volatility, market prices and contract terms. See Note 13. 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 17. 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, 2018 Financial Assets Mutual Fund Investments $ 38 $ — $ — $ — $ 38 Commodity Derivative Instruments — 187 — (7 ) 180 Financial Liabilities Commodity Derivative Instruments — (34 ) — 7 (27 ) Portion of Deferred Compensation Liability Measured at Fair Value (43 ) — — — (43 ) Stock Based Compensation Liability Measured at Fair Value (8 ) — — — (8 ) 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 ) (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 on our consolidated balance sheets. See Note 1. Summary of Significant Accounting Policies for the methods and assumptions used to estimate the fair values: Asset Impairments Impairments are recorded when we determine that the carrying amounts of certain oil and gas properties or midstream facilities are not recoverable from future cash flows, and are calculated using significant unobservable (Level 3) inputs. In 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized impairment expense of $168 million . Additionally, in fourth quarter 2018, we recorded impairment expense of $38 million , $37 million of which related to changes in construction plans for certain midstream assets. The 2017 impairment of $70 million primarily related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico. The 2016 impairment of $92 million primarily related to a decision to write off certain development concepts associated with the Leviathan natural gas project that were not selected. The assets were reduced to their estimated fair values. Inventory Impairment In 2016, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value, which was calculated using significant unobservable (Level 3) inputs. We recognized a $14 million impairment related to these assets. Goodwill Impairment In fourth quarter 2018, we determined that the carrying amount of goodwill allocated to our Texas reporting unit was less than its estimated fair value, which was calculated using significant unobservable (Level 3) inputs. As a result, we recognized a goodwill impairment of $ 1.3 billion. See Note 6. Goodwill Impairment . Marcellus Shale Firm Transportation Liability In 2017, we recorded liabilities totaling $93 million representing the discounted present value of our remaining obligation under certain firm transportation contracts. See Note 10. Marcellus Shale Firm Transportation Commitments . 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, 2018 , our variable-rate, non-public debt included the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and the Noble Midstream Services Term Loan 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 9. Long-Term Debt . Fair value information regarding our debt is as follows: December 31, 2018 December 31, 2017 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,452 $ 6,121 $ 6,586 $ 7,142 (1)

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Note 15. 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 5. Acquisitions and Divestitures ); • 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 , which owns and operates a LPG processing plant in Equatorial Guinea. We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing operations in our Midstream and West Africa segments. For the Advantage Pipeline system, Noble Midstream Partners serves as operator and exerts significant influence over the day-to-day operations. The operating agreements for Advantage Pipeline empower the board to direct activities that most significantly affect long-term economic performance. With regard to AMPCO, we hold a voting position on AMPCO's leadership team through AMPCO's management committee, and our asset teams influence decisions regarding capital investments, budgets, turnarounds, maintenance and other project matters. For the Alba Plant, our Alba asset teams are fully engaged in operational and financial decisions and exert significant influence in the monetization of the Alba field and Alba Plant. Equity method investments are as follows: December 31, (millions) 2018 2017 Advantage Pipeline $ 73 $ 70 AMPCO 131 129 Alba Plant 58 80 Other 24 26 Total Equity Method Investments $ 286 $ 305 Additional Information At December 31, 2018 , consolidated retained earnings included $68 million related to the undistributed earnings of equity method investees. The carrying value of our AMPCO investment was $13 million higher than the underlying net assets of the investee at December 31, 2018 . 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) 2018 2017 Balance Sheet Information Current Assets $ 387 $ 390 Noncurrent Assets 575 588 Current Liabilities 198 171 Noncurrent Liabilities 81 90 Year Ended December 31, (millions) 2018 2017 2016 Statements of Operations Information Operating Revenues $ 855 $ 790 $ 667 Operating Expenses 284 303 355 Operating Income 571 487 312 Other Income, net 3 15 7 Income Before Income Taxes 574 502 319 Income Tax Provision 152 136 60 Net Income $ 422 $ 366 $ 259

Additional Shareholders' Equity

Additional Shareholders' Equity Information	12 Months Ended
	Dec. 31, 2018
Equity [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, 2018 2017 Shares of Common Stock Issued Shares, Beginning of Period 528,743,381 471,360,427 Exercise of Common Stock Options 576,617 382,882 Restricted Stock Awarded, Net of Forfeitures (1) 2,488,363 2,912,936 Purchase and Retirement of Common Stock (2) (10,008,128 ) — Shares Exchanged in Clayton Williams Energy Acquisition (745,232 ) 54,087,136 Shares, End of Period 521,055,001 528,743,381 Treasury Stock Shares, Beginning of Period 38,786,969 37,961,316 Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (3) 267,258 1,026,891 Rabbi Trust Shares Distributed and/or Sold (202,239 ) (201,238 ) Shares, End of Period 38,851,988 38,786,969 Additional Information Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust — — Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (4) 15,004,591 15,619,276 (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. (2) On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. These shares were repurchased and retired at an average price of $ 29.49 per share. (3) The 2017 amount includes approximately 720,000 shares of common stock received 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. (4) For the years ended December 31, 2018 and 2017, 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 Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included: (millions) Interest Rate Cash Flow Hedge Other Postretirement Benefit Plans Total 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 ) Realized Amounts Reclassified Into Earnings (3 ) 1 (2 ) Unrealized Change in Fair Value — — — December 31, 2018 $ (23 ) $ (9 ) $ (32 ) Items in AOCL were initially recorded net of tax, using an effective income tax rate of 35% . In fourth quarter 2018, we reclassified to retained earnings approximately $6 million representing the effect of the decrease in the income tax rate to 21% . AOCL at December 31, 2018 included deferred losses of $24 million

Stock-Based and Other Compensat

Stock-Based and Other Compensation Plans	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based and Other Compensation Plans	Note 17. Stock-Based and Other Compensation Plans We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2018 2017 2016 Stock-Based Compensation Expense Included in: General and Administrative Expense $ 54 $ 56 $ 62 Exploration Expense and Other 8 48 15 Total Stock-Based Compensation Expense $ 62 $ 104 $ 77 Tax Benefit Recognized $ (13 ) $ (36 ) $ (27 ) 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 shareholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon shareholder approval, the 2017 Plan superseded 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, 2018 , 26,621,632 shares of our common stock were reserved for issuance, including 21,084,928 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 shareholder 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, 2018 , 576,798 shares of our common stock were reserved for issuance, including 397,979 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) 2018 2017 2016 Expected Term (in Years) 6.7 6.4 6.3 Expected Volatility 33.4 % 33.2 % 32.4 % Risk-Free Rate 2.6 % 2.2 % 1.6 % Expected Dividend Yield 1.2 % 0.9 % 0.7 % Weighted Average Grant-Date Fair Value $ 10.47 $ 13.26 $ 10.10 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, 2017 15,549,222 $ 43.42 Granted 551,888 30.20 Exercised (576,617 ) 34.55 Forfeited (1,672,473 ) 40.04 Outstanding at December 31, 2018 13,852,020 $ 44.04 5.0 $ — Exercisable at December 31, 2018 11,866,188 $ 45.58 4.0 $ — The total intrinsic value of options exercised was $5 million in 2018 , $4 million in 2017 and $10 million in 2016 . As of December 31, 2018 , $11 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 1.2 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, 2018 2017 2016 Number of Simulations 10,000,000 500,000 500,000 Expected Volatility 35 % 35 % 38 % Risk-Free Rate 2.3 % 1.5 % 1.0 % 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, 2017 1,839,737 $ 37.21 1,212,705 $ 25.55 Awarded 2,702,426 30.68 874,960 19.56 Vested (982,280 ) 35.28 — — Forfeited (386,992 ) 32.65 (702,031 ) 25.52 Outstanding at December 31, 2018 3,172,891 $ 32.72 1,385,634 $ 21.74 The total fair value of restricted stock that vested was $29 million in 2018 , $34 million in 2017 , and $24 million in 2016 . The weighted average award-date fair value of restricted stock awarded was $27.96 per share in 2018 , $35.45 per share in 2017 , and $29.99 per share in 2016 . As of December 31, 2018 , $74 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 1.5 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 ( two -year cliff vesting for officers and three -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. We accrued a liability of $ 8 million in 2018 related to the phantom units. No phantom units were awarded in 2018 or 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, 2017 610,159 $ 31.65 167,483 $ 6.82 Vested (83,276 ) 31.65 — — Forfeited (59,518 ) 31.65 (17,187 ) 6.82 Outstanding at December 31, 2018 467,365 $ 31.65 150,296 $ 6.82 As of December 31, 2018 , compensation cost related to phantom units remained to be recognized was de minimis. The remaining cost is expected to be recognized in first quarter 2019. The total fair value of phantom units that vested in 2018 was de minimis. Common stock dividends accrue on phantom units and are 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 2018 , $31 million in 2017 , and $32 million in 2016 . 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) 2018 2017 Mutual Fund Investments $ 38 $ 57 Noble Energy Common Stock (at Fair Value) 5 14 Total Rabbi Trust Assets $ 43 $ 71 Liability Under Related Deferred Compensation Plan $ 43 $ 71 Number of Shares of Noble Energy Common Stock Held by Rabbi Trust 267,792 470,030 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 14. 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 200,000 shares, or 75% , of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2018 were attributable to a member of our Board of Directors. The remaining shares will be distributed in 2019. Distributions of 200,000 shares were made in each of 2018 , 2017 and 2016 . In addition, plan participants sold 2,239 shares of our common stock in 2018 , 1,238 shares in 2017 , and 1,009 shares in 2016 . Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $18 million in 2018 , $21 million in 2017 and $22 million in 2016 . 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 of $2 million in 2018 , $9 million in 2017 and $11 million in 2016 . We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities of $104 million and $116 million were outstanding at December 31, 2018 and 2017

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation and Consolidation	Basis of Presentation and Consolidation We use accounting policies that 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. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. We do not consider interest income or expense and income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 3. Segment Information . Consolidated Variable Interest Entity (VIE) Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners. Noncontrolling Interests
Equity Method of Accounting	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.
Foreign Currency	Foreign Currency
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, NGL and natural gas reserves are the most significant of our estimates. All of 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, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas 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, NGLs and natural gas 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) .
Reclassification	Reclassifications The revenues and expenses associated with mitigating Marcellus Shale retained firm transportation contracts, including costs associated with exiting certain of those contracts, were reclassified from our oil and gas exploration and production segment to Corporate as these items are not representative of retained upstream operations. See Note 3. Segment Information .
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.
Cash and Cash Equivalents	Cash and Cash Equivalents
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts 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. The majority of these receivables have payment terms of 30 days or less . Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and we have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit.
Inventories	Inventories
Property, Plant and Equipment	Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Oil and Gas Properties (Successful Efforts Method of Accounting) 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, NGL and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. 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. Proved 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. Under such test, 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. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property. 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. We recorded impairment charges in 2018 , 2017 and 2016 and it is possible that other assets could become impaired in the future. See Note 14. Fair Value Measurements and Disclosures . 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, NGL and natural gas 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. 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 7. 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 oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL and natural gas 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. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values. 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 on 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. 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 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, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Property, Plant and Equipment, Other Other property includes automobiles, trucks, airplanes, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging 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 interest rate we pay on long-term debt, including our unsecured revolving credit facilities and bonds. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis. Capitalized interest totaled $73 million in 2018 , $49 million in 2017 , and $84 million in 2016 . Asset Retirement Obligations
Goodwill	Goodwill Goodwill is not amortized to earnings but is assessed for impairment at the reporting unit level on an annual basis, or more frequently as circumstances require. We use qualitative and quantitative assessments to determine whether goodwill is impaired. If we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, an impairment charge is recognized for the amount by which the carrying amount exceeds the fair value. We conducted our annual goodwill impairment assessment as of September 30, 2018. As of that date, our consolidated balance sheet included goodwill of $1.4 billion , of which $ 1.3 billion was allocated to our Texas reporting unit, included within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. At that time, we concluded that goodwill was not impaired. During fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that the goodwill allocated to the Texas reporting unit was fully impaired and recorded a charge of $1.3 billion . See Note 6. Goodwill Impairment .
Intangible Assets	Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners through Black Diamond in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2018 , the net book value of our intangible assets was $ 310 million. Amortization expense, which is equivalent to accumulated amortization for 2018 , of $30 million
Exit Costs	Exit Costs In accordance with Accounting Standards Codification (ASC) 420 – Exit or Disposal Cost Obligations , we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions including: 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 exit cost liabilities at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will be recognized as an adjustment to the liability in the period of the change. Exit cost liabilities are included in other current and other noncurrent liabilities on our consolidated balance sheets. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations. Accrued exit costs at December 31, 2018 and 2017
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on our consolidated balance sheets as either an asset or liability and are 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.
Stock-Based Compensation	Stock-Based Compensation
Pension and Other Postretirement Benefit Plans	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, 2018
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 11. Commitments and Contingencies .
Income Taxes and Impact of Tax Reform Legislation	Income Taxes and Impact of Tax Reform Legislation We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. We account for income taxes using 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.
Treasury Stock	Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs.
Basic and Diluted Earnings (Loss) Per Share	Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy
Recently Issued and Adopted Accounting Standards	Recently Issued Accounting Standards Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize a right of use asset (ROU asset) and lease liability on the balance sheet for the rights and obligations created by leases. 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. In July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements , which provides for an alternative transition method by allowing entities to initially apply the new leases standard at the adoption date (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard is 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, field services and well equipment, office space and other assets. We adopted the new standard on the effective date of January 1, 2019, using a modified retrospective approach as permitted under ASU 2018-11. The new standard provides a number of optional practical expedients in transition. We expect to: • elect the package of 'practical expedients', which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs; • elect the practical expedient pertaining to land easements and plan to account for existing land easements under our current accounting policy; • elect the short-term lease recognition exemption for all leases that qualify and, as such, no ROU asset or lease liability will be recorded on the balance sheet and no transition adjustment will be required for short-term leases; and • elect the practical expedient to not separate lease and non-lease components for all of our leases. We do not expect to elect the hindsight practical expedient in determining the lease term and assessing impairment of ROU assets when transitioning to ASC 842. We continue to execute a project plan, which includes contract review and assessment, data collection, and evaluation of our systems, processes and internal controls. In addition, we have implemented a new lease accounting software which will facilitate the adoption of this standard. While we are finalizing our assessment of the effect of adoption, we do not expect the adoption and implementation of this standard will have a material effect on our financial statements. We estimate the most significant impact will relate to the recognition of new ROU assets and lease liabilities on our balance sheet for operating leases, as well as additional disclosures. Consequently, with adoption, we expect to recognize additional operating liabilities ranging between $200 million to $350 million with corresponding ROU assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. 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 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 standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements. Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. The amended standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-12. Intangibles – Goodwill and Other – Internal-Use Software In August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles – Goodwill and Other – Internal-Use Software to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2018-15. Recently Adopted Accounting Standards Topic 606, Revenue from Contracts with Customers In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers (ASC 606). We adopted ASC 606 on January 1, 2018, using the modified retrospective method. See Note 4. Revenue from Contracts with Customers . 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 . We adopted ASU 2016-18 in the first quarter of 2018, using the retrospective method. ASU 2016-18 requires that restricted cash and 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. There are no other impacts on our results of operations, financial condition or cash flows. 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 standard, we will perform our 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 early adopted this ASU in fourth quarter 2018. This adoption did not have a material impact on our financial statements. Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement – Reporting Comprehensive Income to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. ASU 2018-02 is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We early adopted this ASU in fourth quarter 2018, reclassifying the tax effect of approximately $6 million

Additional Financial Statemen_2

Additional Financial Statement Information (Tables)	12 Months Ended
	Dec. 31, 2018
Additional Financial Statement Information [Abstract]
Statement of Operations Information	Other statements of operations information is as follows: Year Ended December 31, (millions) 2018 2017 2016 Sales of Purchased Oil and Gas and Other Sales of Purchased Oil and Gas (1) $ 275 $ — $ — Income from Equity Method Investees 172 177 102 Midstream Services Revenues - Third Party 78 19 — Total $ 525 $ 196 $ 102 Production Expense Lease Operating Expense $ 576 $ 571 $ 542 Production and Ad Valorem Taxes 190 118 57 Gathering, Transportation and Processing Expense 393 432 480 Other Royalty Expense 38 20 21 Total $ 1,197 $ 1,141 $ 1,100 Exploration Expense Leasehold Impairment and Amortization $ 1 $ 62 $ 148 Dry Hole Cost 1 9 579 Seismic, Geological and Geophysical 22 27 76 Staff Expense 54 55 77 Other 51 35 45 Total $ 129 $ 188 $ 925 Loss on Marcellus Shale Upstream Divestiture and Other Loss on Sale $ — $ 2,270 $ — Exit Cost — 93 — Other — 16 — Total $ — $ 2,379 $ — Other Operating Expense, Net Marketing Expense (2) $ 40 $ 47 $ 58 Cost of Purchased Oil and Gas (1) 296 — — Clayton Williams Energy Acquisition Expenses — 100 — Gain on Asset Retirement Obligation Revisions (3) (25 ) (42 ) — Other, Net 35 33 77 Total $ 346 $ 138 $ 135 (1) As part of the Saddle Butte Acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we entered into certain transactions beginning in first quarter 2018 for the purchase of third-party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. See Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments . (2) Amounts relate to shortfalls in transporting or processing minimum volumes under certain financial commitments primarily in the DJ Basin for 2018 and in the DJ Basin and Marcellus Shale for 2017 (prior to the Marcellus Shale upstream divestiture) and 2016. (3) Gains due to downward ARO revisions in locations where we have no remaining assets. See Note 8. Asset Retirement Obligations .
Balance Sheet Information Table	Other balance sheet information is as follows: December 31, (millions) 2018 2017 Accounts Receivable, Net Commodity Sales $ 383 $ 455 Joint Interest Billings (1) 137 207 Other 111 103 Allowance for Doubtful Accounts (15 ) (17 ) Total $ 616 $ 748 Other Current Assets Commodity Derivative Assets $ 180 $ — Inventories, Materials and Supplies 55 66 Inventories, Crude Oil 12 16 Assets Held for Sale (2) 133 629 Restricted Cash (3) 3 38 Prepaid Expenses and Other Assets, Current 35 31 Total $ 418 $ 780 Other Noncurrent Assets Equity Method Investments $ 286 $ 305 Customer-Related Intangible Assets, Net (4) 310 — Mutual Fund Investments 38 57 Net Deferred Income Tax Asset 21 25 Other Assets, Noncurrent 76 74 Total $ 731 $ 461 Other Current Liabilities Production and Ad Valorem Taxes $ 103 $ 84 Commodity Derivative Liabilities 1 58 Income Taxes Payable 22 18 Asset Retirement Obligations 118 51 Interest Payable 66 67 Current Portion of Capital Lease Obligations 41 61 Liabilities Associated with Assets Held for Sale (2) 1 55 Compensation and Benefits Payable 83 98 Other Liabilities, Current 84 86 Total $ 519 $ 578 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 147 $ 197 Asset Retirement Obligations 762 824 Marcellus Shale Exit Cost Accrual 67 76 Production and Ad Valorem Taxes 83 69 Commodity Derivative Liabilities 26 15 Other Liabilities, Noncurrent 80 64 Total $ 1,165 $ 1,245 (1) We bill partners for their share of expenses of joint venture projects for which we are the operator. These projects, especially those in deepwater or remote international locations, can be very capital cost intensive. Our receivables from joint interest billings decreased significantly in 2018 due to the second quarter 2018 sale of our Gulf of Mexico offshore assets. (2) Assets held for sale at December 31, 2018 include certain proved and unproved non-core acreage in Reeves County, Texas. 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 field, our investment in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments, including CONE Midstream and CONE Gathering. Liabilities associated with assets held for sale primarily represent ARO and other liabilities to be assumed by the purchaser. See Note 5. Acquisitions and Divestitures . (3) Balance at December 31, 2018 represents amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures . (4) Amount relates to intangible assets acquired in the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures
Schedule of Cash, Cash Equivalents and Restricted Cash	We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: December 31, (millions) 2018 2017 Cash and Cash Equivalents at Beginning of Period $ 675 $ 1,180 Restricted Cash at Beginning of Period 38 30 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 713 $ 1,210 Cash and Cash Equivalents at End of Period $ 716 $ 675 Restricted Cash at End of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 719 $ 713
Supplemental Cash Flow Disclosure	Supplemental statements of cash flow information are as follows: Year Ended December 31, (millions) 2018 2017 2016 Cash Paid During the Year For Interest, Net of Amount Capitalized $ 270 $ 346 $ 327 Income Taxes Paid, Net 172 121 236 Non-Cash Financing and Investing Activities Increase in Capital Lease Obligations 14 — 5

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2018 Crude Oil Sales $ 2,945 $ 2,548 $ 7 $ 390 $ — $ — $ — $ — NGL Sales 587 587 — — — — — — Natural Gas Sales 929 435 473 21 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,461 3,570 480 411 — — — — Sales of Purchased Oil and Gas 275 20 — — — 142 — 113 Income from Equity Method Investees 172 — — 132 — 40 — — Midstream Services Revenues - Third Party 78 — — — — 78 — — Intersegment Revenues — 351 (351 ) Total Revenues 4,986 3,590 480 543 — 611 (351 ) 113 Lease Operating Expense 576 480 26 97 — — (27 ) — Production and Ad Valorem Taxes 190 184 — — — 6 — — Gathering, Transportation and Processing Expense 393 533 — — — 95 (235 ) — Other Royalty Expense 38 38 — — — — — — Total Production Expense 1,197 1,235 26 97 — 101 (262 ) — Exploration Expense 129 48 7 6 68 — — — DD&A 1,934 1,642 60 115 2 87 (20 ) 48 (Gain) Loss on Divestitures, Net (843 ) 36 (376 ) — — (503 ) — — Asset Impairments 206 169 — — — 37 — — Goodwill Impairment 1,281 1,281 — — — — — — Cost of Purchased Oil and Gas 296 20 — — — 136 — 140 Gain on Asset Retirement Obligation Revisions (25 ) — (8 ) — (17 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (70 ) — 7 — — — — Income (Loss) Before Income Taxes 140 (875 ) 742 305 (53 ) 726 (60 ) (645 ) Additions to Long Lived Assets 3,253 2,115 671 12 — 521 (91 ) 25 Property, Plant and Equipment, Net 18,419 13,044 2,630 805 37 1,742 (145 ) 306 Year Ended December 31, 2017 Crude Oil Sales $ 2,346 $ 1,993 $ 6 $ 347 $ — $ — $ — $ — NGL Sales 493 493 — — — — — — Natural Gas Sales 1,221 670 528 23 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,060 3,156 534 370 — — — — Income from Equity Method Investees 177 — — 120 — 57 — — Midstream Services Revenues - Third Party 19 — — — — 19 — — Intersegment Revenues — — — — — 277 (277 ) — Total Revenues 4,256 3,156 534 490 — 353 (277 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Lease Operating Expense 571 466 29 90 — — (14 ) — Production and Ad Valorem Taxes 118 115 — — — 3 — — Gathering, Transportation and Processing Expense 432 550 — — — 70 (188 ) — Other Royalty Expense 20 20 — — — — — — Total Production Expense 1,141 1,151 29 90 — 73 (202 ) — Exploration Expense 188 102 2 5 79 — — — DD&A 2,053 1,739 76 146 4 30 (5 ) 63 Loss on Marcellus Shale Upstream Divestiture and Other 2,379 2,286 — — — — — 93 Gain on Divestitures, Net (326 ) (325 ) (1 ) — — — — — Asset Impairments 70 63 — — 7 — — — Clayton Williams Energy Acquisition Expenses 100 100 — — — — — — Gain on Asset Retirement Obligation Revision (42 ) — — — (42 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (92 ) — 29 — — — — Loss on Debt Extinguishment 98 — — — — — — 98 (Loss) Income Before Income Taxes (2,191 ) (2,365 ) 413 203 (54 ) 233 (62 ) (559 ) Additions to Long Lived Assets 2,851 1,994 411 34 (34 ) 423 (79 ) 102 Property, Plant and Equipment, Net 17,502 13,348 2,005 863 25 1,027 (74 ) 308 Year Ended December 31, 2016 Crude Oil Sales $ 1,854 $ 1,439 $ 5 $ 410 $ — $ — $ — $ — NGL Sales 296 296 — — — — — — Natural Gas Sales 1,239 681 535 23 — — — — Total Crude Oil, NGL and Natural Gas Sales 3,389 2,416 540 433 — — — — Income from Equity Method Investees 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 57 55 — — — 2 — — Gathering, Transportation and Processing Expense 480 564 — — — 44 (128 ) — Other Royalty Expense 21 21 — — — — — — Total Production Expense 1,100 1,058 37 105 — 46 (146 ) — Exploration Expense 925 245 34 483 163 — — — DD&A 2,454 2,103 81 205 6 19 — 40 (Gain) Loss on Divestitures, Net (238 ) 23 (261 ) — — — — — Asset Impairments 92 — 88 — 4 — — — Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Loss on Commodity Derivative Instruments 139 126 — 13 — — — — (Loss) Income Before Income Taxes (1,772 ) (1,277 ) 543 (338 ) (199 ) 176 (51 ) (626 ) Additions to Long Lived Assets 1,526 1,353 88 54 (6 ) 58 (53 ) 32 Property, Plant and Equipment, Net 18,548 14,755 1,872 980 15 594 — 332 (1)
Concentrations of Revenue by Customer and Production	The largest single non-affiliated purchasers of our production were as follows: Percentage of Crude Oil Sales Percentage of Total Oil, NGL & Gas Sales Year Ended December 31, 2018 BP (1) 31 % 17 % Shell (2) 22 % 14 % 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 % (1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company. (2)

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments. (millions) 2019 2020 Total Natural Gas Revenues (1) $ 137 $ 169 $ 306 (1)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table sets forth our purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,851 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,488 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 515 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,798 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) 1,291 Total Asset Value $ 3,798 (1) The goodwill, which was associated with the Texas reporting unit included within our oil and gas exploration and production segment, was fully impaired as of December 31, 2018. See Note 6. Goodwill Impairment
Pro Forma Information	Year Ended December 31, (millions, except per share amounts) 2018 (1) 2017 2016 Revenues $ 4,986 $ 4,304 $ 3,651 Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy (66 ) (678 ) (1,082 ) Net Income (Loss) Attributable to Noble Energy per Common Share Basic $ (0.14 ) $ (1.39 ) $ (2.23 ) Diluted $ (0.14 ) $ (1.39 ) $ (2.23 )

Capitalized Exploratory Well _2

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)	12 Months Ended
	Dec. 31, 2018
Capitalized Exploratory Well Costs [Abstract]
Changes in Capitalized Exploratory Well Costs	Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows: Year Ended December 31, (millions) 2018 2017 2016 Capitalized Exploratory Well Costs, Beginning of Period $ 520 $ 768 $ 1,353 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 7 20 84 Divestitures and Other (1) (168 ) — (143 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) (1 ) (203 ) (1 ) Capitalized Exploratory Well Costs Charged to Expense (3) (4 ) (65 ) (525 ) Capitalized Exploratory Well Costs, End of Period $ 354 $ 520 $ 768 (1) The 2018 amount represents costs primarily related to Gulf of Mexico assets sold during second quarter and 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. (3)
Aging of Capitalized Well Costs	The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: December 31, (millions) 2018 2017 2016 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 6 $ 10 $ 69 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 348 510 699 Balance at End of Period $ 354 $ 520 $ 768 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 8 10
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, 2018 : Suspended Since Country/Project (millions) Total 2016 - 2017 2014 - 2015 2013 & Prior Progress Offshore Equatorial Guinea Felicita (Block O) $ 48 $ 3 $ 7 $ 38 We are in process of evaluating regional development scenarios for this 2008 natural gas discovery. In early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. In 2018, we progressed definitive agreements to sell natural gas through the Punta Europa plants, which will expand the options for additional natural gas sales. Yolanda (Block I) 24 2 3 19 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 development team is working with both governments to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales. Offshore Cameroon YoYo (YoYo Block) 52 (1 ) 6 47 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 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. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales. Offshore Israel Leviathan-1 Deep 94 6 8 80 The well did not reach the target interval in 2012. In 2018, we continued to reprocess and review seismic information for this prospect, incorporating information obtained from other recent discoveries in the region and developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 24 2 3 19 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. Currently, we are analyzing 3D seismic data to evaluate additional potential of the area. Offshore Cyprus Cyprus 100 11 12 77 We continue to work with the Government of Cyprus to obtain approval of our development plan and the issuance of an Exploitation License. During 2017, we submitted an updated development plan. During 2018, we continued to progress capital project cost improvement and regional natural gas marketing efforts. Other Projects less than $20 million 6 (7 ) 10 3 Continuing to assess and evaluate wells. Total $ 348 $ 16 $ 49 $ 283
Rollforward Of Undeveloped Lease Costs	Changes in undeveloped leasehold costs were as follows: December 31, (millions) 2018 2017 Undeveloped Leasehold Costs, Beginning of Period $ 2,922 $ 2,197 Additions to Undeveloped Leasehold Costs (1) 47 1,859 Transfers to Proved Properties (2) (453 ) (174 ) Assets Sold (3) (142 ) (884 ) Impairment (4) (1 ) (62 ) Other — (14 ) Undeveloped Leasehold Costs, Net of Impairment, End of Period $ 2,373 $ 2,922 (1) 2017 additions relate to the Clayton Williams Energy Acquisition and Delaware Basin asset acquisition. (2) 2018 transfers relate primarily to Delaware Basin assets. (3) 2017 sales relate primarily to the Marcellus Shale upstream divestiture. (4)

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	ARO consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Year Ended December 31, (millions) 2018 2017 Asset Retirement Obligations, Beginning Balance $ 875 $ 935 Liabilities Incurred 25 94 Liabilities Settled (345 ) (82 ) Revisions of Estimates 293 (65 ) Reclassification to Liabilities Associated with Assets Held for Sale (1 ) (54 ) Accretion Expense 33 47 Asset Retirement Obligations, Ending Balance $ 880 $ 875

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Our debt consists of the following: December 31, 2018 December 31, 2017 (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due March 9, 2023 $ — — % $ 230 2.27 % Noble Midstream Services Revolving Credit Facility, due March 9, 2023 60 3.67 % 85 2.75 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 3.42 % — — % Senior Notes, due May 1, 2021 (1) — — % 379 5.63 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % 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 600 3.85 % 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 500 4.95 % 500 4.95 % Other Senior Notes and Debentures (2) 92 7.13 % 92 7.13 % Capital Lease Obligations 223 — % 273 — % Total $ 6,675 $ 6,859 Unamortized Discount (22 ) (24 ) Unamortized Premium (1) — 12 Unamortized Debt Issuance Costs (38 ) (40 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs $ 6,615 $ 6,807 Less Amounts Due Within One Year: Capital Lease Obligations (41 ) (61 ) Long-Term Debt Due After One Year $ 6,574 $ 6,746 (1) In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, and expensed the associated premium. See Redemption of Notes , below. (2) Includes $8 million of 5.875% Senior Notes due June 1, 2024 and $84 million of 7.25% Senior Debentures due August 1, 2097.
Annual maturities of outstanding debt	Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2018 are as follows: (millions) Debt Principal Payments 2019 $ — 2020 — 2021 1,500 2022 — 2023 160 Thereafter 4,792 Total $ 6,452

Marcellus Shale Firm Transpor_2

Marcellus Shale Firm Transportation Commitments (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Summary of Financial Commitments	Revenues and expenses associated with these agreements, as well as those associated with purchasing and selling third-party natural gas to mitigate Leach/Rayne Xpress capacity, are as follows: Year Ended December 31, (millions) Statements of Operations Location 2018 2017 2016 Sales of Purchased Gas Sales of Purchased Oil and Gas and Other $ 113 $ — $ — Cost of Purchased of Gas Other Operating Expense, Net 108 — — Utilized Firm Transportation Expense (1) Other Operating Expense, Net 29 — — Unutilized Firm Transportation Expense Other Operating Expense, Net 3 — — Cost of Purchased Gas, Total Other Operating Expense, Net $ 140 $ — $ — (1) Includes the net impact of the difference in the firm transportation contract rates and the rates agreed to in the capacity releases. Additionally, amount includes transportation expense associated with our transport of purchased natural gas on Leach/Rayne Xpress. December 31, (millions) 2018 2017 Balance at Beginning of Period $ 90 $ — Marcellus Exit Cost Accrual — 93 Payments, Net of Accretion (10 ) (3 ) Balance at End of Period $ 80 $ 90 Less Current Portion Included in Other Current Liabilities 13 14 Long-term Portion Included in Other Noncurrent Liabilities $ 67 $ 76

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments	Minimum commitments as of December 31, 2018 consist of the following: (millions) Purchase and Service Obligations Marcellus Shale Firm Transportation and Other Obligations (1) Gathering, Transportation & Processing Obligations Operating Lease Obligations (2) Capital Lease Obligations (2) Total 2019 $ 197 $ 123 $ 151 $ 91 $ 52 $ 614 2020 29 122 129 74 46 400 2021 13 121 103 59 31 327 2022 6 118 67 62 22 275 2023 21 113 66 50 20 270 2024 and Thereafter 5 934 285 176 104 1,504 Total $ 271 $ 1,531 $ 801 $ 512 $ 275 $ 3,390 (1) Amount includes exit cost obligations resulting from a permanent capacity assignment. See Note 10. Marcellus Shale Firm Transportation Commitments . (2) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. Long-Term Debt .

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 2016 Domestic $ (953 ) $ (2,831 ) $ (1,859 ) Foreign 1,093 640 87 Total $ 140 $ (2,191 ) $ (1,772 )
Components of Income Tax Provision Table	The income tax provision (benefit) consists of the following: Year Ended December 31, (millions, except percentages) 2018 2017 2016 Current Taxes Federal $ 22 $ (11 ) $ (4 ) State 2 1 5 Foreign 172 96 196 Total Current $ 196 $ 86 $ 197 Deferred Taxes Federal $ (123 ) $ (1,258 ) $ (784 ) State (7 ) (8 ) (24 ) Foreign 60 39 (176 ) Total Deferred $ (70 ) $ (1,227 ) $ (984 ) Total Income Tax Provision (Benefit) Attributable to Noble Energy $ 126 $ (1,141 ) $ (787 ) Effective Tax Rate 90.0 % 52.1 % 44.4 %
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) 2018 2017 2016 Federal Statutory Rate (1) 21.0 % 35.0 % 35.0 % Effect of Goodwill Impairment 192.5 — — Change in Valuation Allowance (1) (170.2 ) (17.4 ) (2.0 ) US and Foreign Statutory Rate Change (1) 80.7 23.5 1.6 Accumulated Undistributed Foreign Earnings (1) — 11.0 7.2 Transition Tax (1) — (4.8 ) — Difference Between US and Foreign Rates 17.9 1.8 (0.1 ) Earnings of Equity Method Investees (20.1 ) 1.9 1.0 Noncontrolling Interests (12.1 ) 1.1 0.4 State Taxes, Net of Federal Benefit 0.9 0.3 1.3 Foreign Exploration Loss (35.6 ) — — Global Intangible Low-Taxed Income (GILTI) (1) 24.2 — — Return to Provision (17.1 ) (0.1 ) (0.2 ) Audit Settlement 5.1 0.1 (0.2 ) Oil Profits Tax - Israel 3.3 (0.1 ) — Other, Net (0.5 ) (0.2 ) 0.4 Effective Rate 90.0 % 52.1 % 44.4 % (1) See Tax Reform Legislation and Accumulated Undistributed Earnings of Foreign Subsidiaries
Deferred Tax Assets and Liabilities	eferred tax assets and liabilities resulted from the following: December 31, (millions) 2018 2017 Deferred Tax Assets Loss Carryforwards $ 589 $ 902 Employee Compensation and Benefits 92 97 Mark to Market of Commodity Derivative Instruments (27 ) 7 Foreign Tax Credits 138 366 Other 157 104 Total Deferred Tax Assets $ 949 $ 1,476 Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits (320 ) (549 ) Net Deferred Tax Assets $ 629 $ 927 Deferred Tax Liabilities Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (1,669 ) (2,029 ) Total Deferred Tax Liability $ (1,669 ) $ (2,029 ) Net Deferred Tax Liability $ (1,040 ) $ (1,102 )
Deferred Tax Liability Balance Sheet Classification	Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2018 2017 Deferred Income Tax Asset - Noncurrent $ 21 $ 25 Deferred Income Tax Liability - Noncurrent (1,061 ) (1,127 ) Net Deferred Tax Liability $ (1,040 ) $ (1,102 )

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unsettled Derivative Instruments	As of December 31, 2018 , we had entered into the following crude oil derivative instruments: Swaps Collars Settlement Period Type of Contract Index Bbls per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2019 Swaps NYMEX WTI 22,000 $ — $ 56.96 $ — $ — $ — 2019 Three-Way Collars NYMEX WTI 33,000 — — 49.35 59.35 72.25 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) 27,000 (3.23 ) — — — — 2020 Swaption NYMEX WTI 5,000 — 61.79 — — — 2020 Basis Swap (1) 15,000 (5.01 ) — — — — (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, 2018 , we had entered into the following natural gas derivative instruments: Swaps Collars Settlement Period Type of Contract Index MMBtu per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 1Q19 (1) Swaps NYMEX HH 86,500 $ — $ 4.36 $ — $ — $ — 1Q19 (1) Three-Way Collars NYMEX HH 21,500 — — 3.00 3.25 4.08 2019 Three-Way Collars NYMEX HH 104,000 — — 2.25 2.65 2.95 2019 Basis Swaps (2) 52,000 (0.74 ) — — — — (1) We have entered into contracts for portions of 2019 resulting in the difference in hedged volumes for the full year. (2)
Fair Value of Derivative Instruments	The fair values of derivative instruments on our consolidated balance sheets were as follows (1) : Asset Derivative Instruments Liability Derivative Instruments December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 180 Current Assets $ 2 Current Liabilities $ 1 Current Liabilities $ 58 Noncurrent Assets — Noncurrent Assets — Noncurrent Liabilities 26 Noncurrent Liabilities 15 Total $ 180 $ 2 $ 27 $ 73 (1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities .
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) 2018 2017 2016 Cash Paid (Received) in Settlement of Commodity Derivative Instruments Crude Oil $ 162 $ (14 ) $ (499 ) Natural Gas (1 ) 1 (70 ) Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments 161 (13 ) (569 ) Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (225 ) 18 582 Natural Gas 1 (68 ) 126 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (224 ) (50 ) 708 (Gain) Loss on Commodity Derivative Instruments Crude Oil (63 ) 4 83 Natural Gas — (67 ) 56 Total (Gain) Loss on Commodity Derivative Instruments $ (63 ) $ (63 ) $ 139

Fair Value Measurements and D_2

Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 Financial Assets Mutual Fund Investments $ 38 $ — $ — $ — $ 38 Commodity Derivative Instruments — 187 — (7 ) 180 Financial Liabilities Commodity Derivative Instruments — (34 ) — 7 (27 ) Portion of Deferred Compensation Liability Measured at Fair Value (43 ) — — — (43 ) Stock Based Compensation Liability Measured at Fair Value (8 ) — — — (8 ) 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 ) (1) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy. (2)
Additional fair value disclosures	Fair value information regarding our debt is as follows: December 31, 2018 December 31, 2017 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,452 $ 6,121 $ 6,586 $ 7,142 (1)

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity method investments	Equity method investments are as follows: December 31, (millions) 2018 2017 Advantage Pipeline $ 73 $ 70 AMPCO 131 129 Alba Plant 58 80 Other 24 26 Total Equity Method Investments $ 286 $ 305 December 31, (millions) 2018 2017 Balance Sheet Information Current Assets $ 387 $ 390 Noncurrent Assets 575 588 Current Liabilities 198 171 Noncurrent Liabilities 81 90 Year Ended December 31, (millions) 2018 2017 2016 Statements of Operations Information Operating Revenues $ 855 $ 790 $ 667 Operating Expenses 284 303 355 Operating Income 571 487 312 Other Income, net 3 15 7 Income Before Income Taxes 574 502 319 Income Tax Provision 152 136 60 Net Income $ 422 $ 366 $ 259

Additional Shareholders' Equi_2

Additional Shareholders' Equity Information (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [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, 2018 2017 Shares of Common Stock Issued Shares, Beginning of Period 528,743,381 471,360,427 Exercise of Common Stock Options 576,617 382,882 Restricted Stock Awarded, Net of Forfeitures (1) 2,488,363 2,912,936 Purchase and Retirement of Common Stock (2) (10,008,128 ) — Shares Exchanged in Clayton Williams Energy Acquisition (745,232 ) 54,087,136 Shares, End of Period 521,055,001 528,743,381 Treasury Stock Shares, Beginning of Period 38,786,969 37,961,316 Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (3) 267,258 1,026,891 Rabbi Trust Shares Distributed and/or Sold (202,239 ) (201,238 ) Shares, End of Period 38,851,988 38,786,969 Additional Information Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust — — Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (4) 15,004,591 15,619,276 (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. (2) On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. These shares were repurchased and retired at an average price of $ 29.49 per share. (3) The 2017 amount includes approximately 720,000 shares of common stock received 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. (4)
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: (millions) Interest Rate Cash Flow Hedge Other Postretirement Benefit Plans Total 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 ) Realized Amounts Reclassified Into Earnings (3 ) 1 (2 ) Unrealized Change in Fair Value — — — December 31, 2018 $ (23 ) $ (9 ) $ (32 )

Stock-Based and Other Compens_2

Stock-Based and Other Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 2016 Stock-Based Compensation Expense Included in: General and Administrative Expense $ 54 $ 56 $ 62 Exploration Expense and Other 8 48 15 Total Stock-Based Compensation Expense $ 62 $ 104 $ 77 Tax Benefit Recognized $ (13 ) $ (36 ) $ (27 )
Valuation Assumptions, Options	The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2018 2017 2016 Expected Term (in Years) 6.7 6.4 6.3 Expected Volatility 33.4 % 33.2 % 32.4 % Risk-Free Rate 2.6 % 2.2 % 1.6 % Expected Dividend Yield 1.2 % 0.9 % 0.7 % Weighted Average Grant-Date Fair Value $ 10.47 $ 13.26 $ 10.10
Award Activity, Options	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, 2017 15,549,222 $ 43.42 Granted 551,888 30.20 Exercised (576,617 ) 34.55 Forfeited (1,672,473 ) 40.04 Outstanding at December 31, 2018 13,852,020 $ 44.04 5.0 $ — Exercisable at December 31, 2018 11,866,188 $ 45.58 4.0 $ —
Valuation Assumptions, Restricted Stock	The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2018 2017 2016 Number of Simulations 10,000,000 500,000 500,000 Expected Volatility 35 % 35 % 38 % Risk-Free Rate 2.3 % 1.5 % 1.0 %
Award Activity, Restricted Stock	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, 2017 1,839,737 $ 37.21 1,212,705 $ 25.55 Awarded 2,702,426 30.68 874,960 19.56 Vested (982,280 ) 35.28 — — Forfeited (386,992 ) 32.65 (702,031 ) 25.52 Outstanding at December 31, 2018 3,172,891 $ 32.72 1,385,634 $ 21.74
Award Activity, Phantom Units	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, 2017 610,159 $ 31.65 167,483 $ 6.82 Vested (83,276 ) 31.65 — — Forfeited (59,518 ) 31.65 (17,187 ) 6.82 Outstanding at December 31, 2018 467,365 $ 31.65 150,296 $ 6.82
Schedule of components for Rabbi Trust	Components of that rabbi trust are as follows: December 31, (millions, except share amounts) 2018 2017 Mutual Fund Investments $ 38 $ 57 Noble Energy Common Stock (at Fair Value) 5 14 Total Rabbi Trust Assets $ 43 $ 71 Liability Under Related Deferred Compensation Plan $ 43 $ 71 Number of Shares of Noble Energy Common Stock Held by Rabbi Trust 267,792 470,030

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018
Property, Plant and Equipment [Line Items]
Total capitalized interest	$ (73)	$ (49)	$ (84)
Goodwill	110	1,310		$ 1,400
Goodwill Impairment	1,281	0	$ 0
Intangible assets, net	310	$ 0
Amortization expense	30
Stranded tax assets	$ 6
Minimum
Property, Plant and Equipment [Line Items]
Useful lives of gathering facilitates and processing plants (in years)	3 years
Intangible asset, useful life	7 years
Maximum
Property, Plant and Equipment [Line Items]
Useful lives of gathering facilitates and processing plants (in years)	30 years
Intangible asset, useful life	13 years
Pro Forma | ASU 2016-02 | Minimum
Property, Plant and Equipment [Line Items]
Operating lease liability	$ 200
Operating lease, right of use asset	200
Pro Forma | ASU 2016-02 | Maximum
Property, Plant and Equipment [Line Items]
Operating lease liability	350
Operating lease, right of use asset	350
Texas
Property, Plant and Equipment [Line Items]
Goodwill				$ 1,300
Midstream
Property, Plant and Equipment [Line Items]
Goodwill	$ 110

Additional Financial Statemen_3

Additional Financial Statement Information - Additional Income Statement Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Sales of Purchased Oil and Gas and Other
Revenue from Sales	$ 4,986	$ 4,256	$ 3,491
Sales of Purchased Oil and Gas and Other
Lease Operating Expense	576	571	542
Production and Ad Valorem Taxes	190	118	57
Gathering, Transportation and Processing Expense	393	432	480
Total	1,197	1,141	1,100
Exploration Expense
Leasehold Impairment and Amortization	1	62	148
Dry Hole Cost	1	9	579
Seismic, Geological and Geophysical	22	27	76
Staff Expense	54	55	77
Other	51	35	45
Total	129	188	925
Loss on Marcellus Shale Upstream Divestiture and Other
Loss on Sale	0	2,270	0
Exit Cost	0	93	0
Other	0	16	0
Total	0	2,379	0
Other Operating Expense, Net
Marketing Expense	40	47	58
Cost of Purchased Oil and Gas	296	0	0
Gain on Divestitures, Net	0	100	0
Gain on Asset Retirement Obligation Revisions	(25)	(42)	0
Other, Net	35	33	77
Total	346	138	135
Purchased Oil and Gas
Sales of Purchased Oil and Gas and Other
Revenue from Sales	275	0	0
Sales of Purchased Oil and Gas and Other
Cost of Goods and Services Sold	296
Income from Equity Method Investees
Sales of Purchased Oil and Gas and Other
Revenue from Sales	172	177	102
Midstream Services Revenues - Third Party
Sales of Purchased Oil and Gas and Other
Revenue from Sales	78	19	0
Sales of Purchased Oil and Gas and Other
Sales of Purchased Oil and Gas and Other
Revenue from Sales	525	196	102
Other Royalty Expense
Sales of Purchased Oil and Gas and Other
Cost of Goods and Services Sold	$ 38	$ 20	$ 21

Additional Financial Statemen_4

Additional Financial Statement Information - Additional Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable, Net
Commodity Sales	$ 383	$ 455
Joint Interest Billings	137	207
Other	111	103
Allowance for Doubtful Accounts	(15)	(17)
Total	616	748
Other Current Assets
Commodity Derivative Assets	180	0
Inventories, Materials and Supplies	55	66
Inventories, Crude Oil	12	16
Assets Held for Sale	133	629
Restricted Cash	3	38	$ 30
Prepaid Expenses and Other Assets, Current	35	31
Total	418	780
Other Noncurrent Assets
Equity Method Investments	286	305
Customer-Related Intangible Assets, Net	310	0
Mutual Fund Investments	38	57
Net Deferred Income Tax Asset	21	25
Other Assets, Noncurrent	76	74
Total	731	461
Other Current Liabilities
Production and Ad Valorem Taxes	103	84
Commodity Derivative Liabilities	1	58
Income Taxes Payable	22	18
Asset Retirement Obligations	118	51
Interest Payable	66	67
Current Portion of Capital Lease Obligations	41	61
Liabilities Associated with Assets Held for Sale	1	55
Compensation and Benefits Payable	83	98
Other Liabilities, Current	84	86
Total	519	578
Other Noncurrent Liabilities
Deferred Compensation Liabilities	147	197
Asset Retirement Obligations	762	824
Marcellus Shale Exit Cost Accrual	67	76
Production and Ad Valorem Taxes	83	69
Commodity Derivative Liabilities	26	15
Other Liabilities, Noncurrent	80	64
Total	$ 1,165	$ 1,245
Tamar and Dalit Fields
Other Noncurrent Liabilities
Ownership interest	7.50%

Additional Financial Statemen_5

Additional Financial Statement Information - Reconciliation of Total Cash (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Additional Financial Statement Information [Abstract]
Cash and Cash Equivalents	$ 716	$ 675	$ 1,180
Restricted Cash	3	38	30
Cash, Cash Equivalents, and Restricted Cash	$ 719	$ 713	$ 1,210	$ 1,028

Additional Financial Statemen_6

Additional Financial Statement Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Paid During the Year For
Interest, Net of Amount Capitalized	$ 270	$ 346	$ 327
Income Taxes Paid, Net	172	121	236
Non-Cash Financing and Investing Activities
Increase in Capital Lease Obligations	$ 14	$ 0	$ 5

Segment Information - Operating

Segment Information - Operating Results by Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenue from Sales	$ 4,986	$ 4,256	$ 3,491
Lease Operating Expense	576	571	542
Production and Ad Valorem Taxes	190	118	57
Gathering, Transportation and Processing Expense	393	432	480
Total	1,197	1,141	1,100
Exploration Expense	129	188	925
DD&A	1,934	2,053	2,454
(Gain) Loss on Divestitures, Net	206
Goodwill Impairment	1,281	0	0
Asset Impairments	(843)	(326)	(238)
Gain on Asset Retirement Obligation Revisions	(25)	(42)
Gain on Divestitures, Net	0	100	0
Asset Impairments	8	98	(80)
Loss on Marcellus Shale Upstream Divestiture and Other	0	2,379	0
Asset Impairments	206	70	92
(Gain) Loss on Commodity Derivative Instruments	(63)	(63)	139
Income (Loss) Before Income Taxes	140	(2,191)	(1,772)
Additions to Long-Lived Assets	3,253	2,851	1,526
Property, Plant and Equipment, Net	18,419	17,502	18,548
Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	(351)	(277)	(200)
Lease Operating Expense	(27)	(14)	(18)
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	(235)	(188)	(128)
Total	(262)	(202)	(146)
Exploration Expense	0	0	0
DD&A	(20)	(5)	0
(Gain) Loss on Divestitures, Net	0
Goodwill Impairment	0
Asset Impairments	0	0	0
Gain on Asset Retirement Obligation Revisions	0	0
Gain on Divestitures, Net		0
Asset Impairments		0
Loss on Marcellus Shale Upstream Divestiture and Other		0
Asset Impairments		0	0
(Gain) Loss on Commodity Derivative Instruments	0	0	0
Income (Loss) Before Income Taxes	(60)	(62)	(51)
Additions to Long-Lived Assets	(91)	(79)	(53)
Property, Plant and Equipment, Net	(145)	(74)	0
Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	113	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
Exploration Expense	0	0	0
DD&A	48	63	40
(Gain) Loss on Divestitures, Net	0
Goodwill Impairment	0
Asset Impairments	0	0	0
Gain on Asset Retirement Obligation Revisions	0	0
Gain on Divestitures, Net		0
Asset Impairments		98
Loss on Marcellus Shale Upstream Divestiture and Other		93
Asset Impairments		0	0
(Gain) Loss on Commodity Derivative Instruments	0	0	0
Income (Loss) Before Income Taxes	(645)	(559)	(626)
Additions to Long-Lived Assets	25	102	32
Property, Plant and Equipment, Net	306	308	332
United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	3,590	3,156	2,416
Lease Operating Expense	480	466	418
Production and Ad Valorem Taxes	184	115	55
Gathering, Transportation and Processing Expense	533	550	564
Total	1,235	1,151	1,058
Exploration Expense	48	102	245
DD&A	1,642	1,739	2,103
(Gain) Loss on Divestitures, Net	169
Goodwill Impairment	1,281
Asset Impairments	36	(325)	23
Gain on Asset Retirement Obligation Revisions	0	0
Gain on Divestitures, Net		100
Asset Impairments		0
Loss on Marcellus Shale Upstream Divestiture and Other		2,286
Asset Impairments		63	0
(Gain) Loss on Commodity Derivative Instruments	(70)	(92)	126
Income (Loss) Before Income Taxes	(875)	(2,365)	(1,277)
Additions to Long-Lived Assets	2,115	1,994	1,353
Property, Plant and Equipment, Net	13,044	13,348	14,755
United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	611	353	252
Lease Operating Expense	0	0	0
Production and Ad Valorem Taxes	6	3	2
Gathering, Transportation and Processing Expense	95	70	44
Total	101	73	46
Exploration Expense	0	0	0
DD&A	87	30	19
(Gain) Loss on Divestitures, Net	37
Goodwill Impairment	0
Asset Impairments	(503)	0	0
Gain on Asset Retirement Obligation Revisions	0	0
Gain on Divestitures, Net		0
Asset Impairments		0
Loss on Marcellus Shale Upstream Divestiture and Other		0
Asset Impairments		0	0
(Gain) Loss on Commodity Derivative Instruments	0	0	0
Income (Loss) Before Income Taxes	726	233	176
Additions to Long-Lived Assets	521	423	58
Property, Plant and Equipment, Net	1,742	1,027	594
United States | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	351	277	200
Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	480	534	540
Lease Operating Expense	26	29	37
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	0	0	0
Total	26	29	37
Exploration Expense	7	2	34
DD&A	60	76	81
(Gain) Loss on Divestitures, Net	0
Goodwill Impairment	0
Asset Impairments	(376)	(1)	(261)
Gain on Asset Retirement Obligation Revisions	(8)	0
Gain on Divestitures, Net		0
Asset Impairments		0
Loss on Marcellus Shale Upstream Divestiture and Other		0
Asset Impairments		0	88
(Gain) Loss on Commodity Derivative Instruments	0	0	0
Income (Loss) Before Income Taxes	742	413	543
Additions to Long-Lived Assets	671	411	88
Property, Plant and Equipment, Net	2,630	2,005	1,872
West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	543	490	483
Lease Operating Expense	97	90	105
Production and Ad Valorem Taxes	0	0	0
Gathering, Transportation and Processing Expense	0	0	0
Total	97	90	105
Exploration Expense	6	5	483
DD&A	115	146	205
(Gain) Loss on Divestitures, Net	0
Goodwill Impairment	0
Asset Impairments	0	0	0
Gain on Asset Retirement Obligation Revisions	0	0
Gain on Divestitures, Net		0
Asset Impairments		0
Loss on Marcellus Shale Upstream Divestiture and Other		0
Asset Impairments		0	0
(Gain) Loss on Commodity Derivative Instruments	7	29	13
Income (Loss) Before Income Taxes	305	203	(338)
Additions to Long-Lived Assets	12	34	54
Property, Plant and Equipment, Net	805	863	980
Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	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
Exploration Expense	68	79	163
DD&A	2	4	6
(Gain) Loss on Divestitures, Net	0
Goodwill Impairment	0
Asset Impairments	0	0	0
Gain on Asset Retirement Obligation Revisions	(17)	(42)
Gain on Divestitures, Net		0
Asset Impairments		0
Loss on Marcellus Shale Upstream Divestiture and Other		0
Asset Impairments		7	4
(Gain) Loss on Commodity Derivative Instruments	0	0	0
Income (Loss) Before Income Taxes	(53)	(54)	(199)
Additions to Long-Lived Assets	0	(34)	(6)
Property, Plant and Equipment, Net	37	25	15
Oil, NGL and Gas Sales
Segment Reporting Information [Line Items]
Revenue from Sales	4,461	4,060	3,389
Oil, NGL and Gas Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Oil, NGL and Gas Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Oil, NGL and Gas Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	3,570	3,156	2,416
Oil, NGL and Gas Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Oil, NGL and Gas Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	480	534	540
Oil, NGL and Gas Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	411	370	433
Oil, NGL and Gas Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Crude Oil Sales
Segment Reporting Information [Line Items]
Revenue from Sales	2,945	2,346	1,854
Crude Oil Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Crude Oil Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Crude Oil Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	2,548	1,993	1,439
Crude Oil Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Crude Oil Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	7	6	5
Crude Oil Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	390	347	410
Crude Oil Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
NGL Sales
Segment Reporting Information [Line Items]
Revenue from Sales	587	493	296
NGL Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
NGL Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
NGL Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	587	493	296
NGL Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
NGL Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
NGL Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
NGL Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Natural Gas Sales
Segment Reporting Information [Line Items]
Revenue from Sales	929	1,221	1,239
Natural Gas Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Natural Gas Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Natural Gas Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	435	670	681
Natural Gas Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Natural Gas Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	473	528	535
Natural Gas Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	21	23	23
Natural Gas Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Purchased Oil and Gas
Segment Reporting Information [Line Items]
Revenue from Sales	275	0	0
Cost of Goods and Services Sold	296
Purchased Oil and Gas | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0
Cost of Goods and Services Sold	0
Purchased Oil and Gas | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	113
Cost of Goods and Services Sold	140
Purchased Oil and Gas | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	20
Cost of Goods and Services Sold	20
Purchased Oil and Gas | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	142
Cost of Goods and Services Sold	136
Purchased Oil and Gas | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0
Cost of Goods and Services Sold	0
Purchased Oil and Gas | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0
Cost of Goods and Services Sold	0
Purchased Oil and Gas | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0
Cost of Goods and Services Sold	0
Income from Equity Method Investees
Segment Reporting Information [Line Items]
Revenue from Sales	172	177	102
Income from Equity Method Investees | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Income from Equity Method Investees | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Income from Equity Method Investees | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Income from Equity Method Investees | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	40	57	52
Income from Equity Method Investees | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Income from Equity Method Investees | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	132	120	50
Income from Equity Method Investees | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0
Midstream Services Revenues - Third Party
Segment Reporting Information [Line Items]
Revenue from Sales	78	19	0
Midstream Services Revenues - Third Party | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0
Midstream Services Revenues - Third Party | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0
Midstream Services Revenues - Third Party | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0
Midstream Services Revenues - Third Party | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	78	19
Midstream Services Revenues - Third Party | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0
Midstream Services Revenues - Third Party | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0
Midstream Services Revenues - Third Party | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0
Other Royalty Expense
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	38	20	21
Other Royalty Expense | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	0	0	0
Other Royalty Expense | Corporate
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	0	0	0
Other Royalty Expense | United States | Operating Segments
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	38	20	21
Other Royalty Expense | United States | Noble Midstream
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	0	0	0
Other Royalty Expense | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	0	0	0
Other Royalty Expense | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	0	0	0
Other Royalty Expense | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Cost of Goods and Services Sold	$ 0	$ 0	$ 0

Segment Information - Concentra

Segment Information - Concentrations of Revenue (Details) - Product Concentration Risk - Sales Revenue	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Percentage of Crude Oil Sales | BP
Concentration Risk [Line Items]
Concentration risk, percentage	31.00%	15.00%
Percentage of Crude Oil Sales | Shell
Concentration Risk [Line Items]
Concentration risk, percentage	22.00%	22.00%	24.00%
Percentage of Crude Oil Sales | Glencore Energy UK Ltd
Concentration Risk [Line Items]
Concentration risk, percentage			22.00%
Percentage of Total Oil, NGL & Gas Sales | BP
Concentration Risk [Line Items]
Concentration risk, percentage	17.00%	10.00%
Percentage of Total Oil, NGL & Gas Sales | Shell
Concentration Risk [Line Items]
Concentration risk, percentage	14.00%	13.00%	13.00%
Percentage of Total Oil, NGL & Gas Sales | Glencore Energy UK Ltd
Concentration Risk [Line Items]
Concentration risk, percentage			12.00%

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)$ / MMBTU	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Disaggregation of Revenue [Line Items]
Revenue (less than $1 million)	$ 4,986	$ 4,256	$ 3,491
Operating expenses (less than $1 million)	$ 4,635	$ 6,058	$ 4,867
West Africa
Disaggregation of Revenue [Line Items]
Contractual sales price (in usd per MMBtu) | $ / MMBTU	0.25
ASU 2014-09
Disaggregation of Revenue [Line Items]
Revenue (less than $1 million)	$ 1
Operating expenses (less than $1 million)	$ 1

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Transaction Price Allocated to Remaining Performance Obligations (Details) - Natural Gas Sales $ in Millions	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation amount	$ 137
Remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation amount	$ 306
Remaining performance obligation, expected timing of satisfaction	2 years

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details)	Mar. 14, 2018USD ($)shares	Feb. 15, 2018USD ($)$ / bbl	Jan. 31, 2018USD ($)	Jun. 28, 2017USD ($)payment$ / MMBTU	Jun. 26, 2017USD ($)ashares	Apr. 24, 2017USD ($)a$ / sharesshares	Apr. 03, 2017USD ($)bbl / dmibbl	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jan. 31, 2018USD ($)	Jan. 31, 2017USD ($)	Dec. 31, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)well	Dec. 31, 2018USD ($)aMMcf / d	Dec. 31, 2017USD ($)well	Dec. 31, 2016USD ($)a	Mar. 31, 2019	Jan. 31, 2019USD ($)a	Feb. 01, 2018shares	Jan. 29, 2018	Jan. 28, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment charge																	$ 206,000,000
Proceeds from Divestitures																	1,999,000,000	$ 2,073,000,000	$ 1,241,000,000
Gain (loss) on sale																	843,000,000	326,000,000	$ 238,000,000
Ownership interest sold															35.00%				35.00%
Payments for (proceeds from) businesses and interest in affiliates																	(484,000,000)
Gain (loss) on divestiture																	0	(2,379,000,000)	$ 0
Goodwill								$ 110,000,000	$ 1,400,000,000			$ 110,000,000				$ 1,310,000,000	110,000,000	1,310,000,000
Severance, consulting, investment, advisory, legal and other related merger-related fees																	0	100,000,000	0
Sales Proceeds																			83,000,000
Proceeds from issuance of common limited partners units																	0	312,000,000	299,000,000
Gain (loss) on divestitures																	843,000,000	$ 326,000,000	$ 238,000,000
Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred			$ 681,000,000
Cash paid			663,000,000
Total Purchase Price Plus Liabilities Assumed			$ 18,000,000							$ 18,000,000
Property, plant and equipment assumed								206,000,000				206,000,000					206,000,000
Finite-lived intangible assets assumed								340,000,000				340,000,000					340,000,000
Immaterial acquisitions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of productive wells | well																7		7
Payments to acquire oil and gas properties																	$ 3,000,000	$ 26,000,000
Clayton Williams Energy
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred						$ 2,488,000,000
Cash paid						637,000,000
Total Purchase Price Plus Liabilities Assumed						3,798,000,000
Goodwill						$ 1,291,000,000
Stock issued (shares) | shares						56,000,000
Fair Value of Common Stock Issued						$ 1,851,000,000
Share price ($ per share) | $ / shares						$ 34.17
Long-term line of credit						$ 1,300,000,000
Severance, consulting, investment, advisory, legal and other related merger-related fees						100,000,000												23,000,000
Severance, consulting, investment, advisory, legal, and other merger related fees						64,000,000												100,000,000
Noncash share-based compensation expense						$ 36,000,000
Treasury stock redeemed (in shares) | shares						720,000
Consideration transferred, treasury stock						$ 25,000,000
Long-Term Debt						$ 595,000,000
Revenue since acquisition																$ 99,000,000
Pre-tax loss since acquisition																19,000,000
Delaware Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred											$ 301,000,000
Proceeds allocated to undeveloped leasehold cost											246,000,000
Blanco River DevCo | Noble Midstream Partners LP
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%
Colorado River DevCo | Noble Midstream Partners LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest acquired					20.00%
Blanco River and Colorado River DevCos | Subsidiaries
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
Stock issued (shares) | shares					562,430
Developed gas and oil area | a					111,000
Proceeds from issuance of common limited partners units					$ 138,000,000
Proceeds from debt					90,000,000
Blanco River and Colorado River DevCos | Noble Midstream Partners LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred					$ 270,000,000
Advantage Pipeline | Noble Midstream Partners LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred							$ 133,000,000
Length of pipeline | mi							70
Shipping capacity per day (bbls/day) | bbl / d							150
Storage capacity (bbls) | bbl							490
DJ Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acreage exchange | a																	12,900
Mustang and Wells Ranch
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acreage exchange | a																	12,300
Delaware Basin | Clayton Williams Energy
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gas and oil area acquired | a						71,000
Additional gas and oil area acquired | a						64,000
Long-Term Debt						$ 595,000,000
Permian | Clayton Williams Energy
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gas and oil area acquired | a						100,000
CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage			50.00%							50.00%												34.10%
Greendfield Midstream | Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash paid			$ 343,000,000
Noble Midstream Partners LP | Advantage Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage							50.00%
EPIC NGL Pipeline | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest in equity method investments																				15.00%
EPIC Crude Oil Pipeline | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest in equity method investments																				30.00%
Tamar and Dalit Fields
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]
Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units																	$ 387,000,000
Owned (shares) | shares																						21,700,000
Realized gain (loss) on sale																	307,000,000
Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest in equity method investments			54.40%							54.40%
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
CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestitures										$ 309,000,000
Gain (loss) on sale										196,000,000
Greeley Crescent Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestitures									$ 68,000,000
Ward County
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestitures								63,000,000
Gain (loss) on divestiture								16,000,000
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 sale, before tax																	2,300,000,000
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
Marcellus Shale | Leaseholds and Leasehold Improvements
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset consideration				$ 883,000,000
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestitures																	$ 671,000,000
DJ Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestitures																	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
CONSOL Carried Cost Obligation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash remitted															$ 213,000,000
Mustang and Wells Ranch
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
Ownership interest sold															3.50%				3.50%
Sales Proceeds																			$ 316,000,000
Gain (loss) on divestitures																			$ 261,000,000
Ownership percentage required per agreement															25.00%				25.00%
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Gulf of Mexico assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value		$ 480,000,000
Impairment charge														$ 168,000,000
Proceeds from Divestitures													$ 384,000,000
Gain (loss) on sale													$ (24,000,000)
Contingent consideration, asset		$ 100,000,000
Asset basis, price per barrel (in usd per bbl) | $ / bbl		2
Asset basis, price per barrel benchmark (in usd per bbl) | $ / bbl		63
Contingent consideration, liability								3,000,000				3,000,000					$ 3,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale																	376,000,000
Ownership interest sold	7.50%
Shares received in divestiture of interest in equity method investment (in shares) | shares	38,500,000
Consideration, shares issued, value	$ 224,000,000
Tax effect of gain (loss)																	86,000,000
Gain (loss) on divestiture of equity method investments, change in fair value	$ 190,000,000
Discount rate for impairment model	15.00%
Gross unrealized loss																	27,000,000
Dividend income																	31,000,000
Payments for (proceeds from) investments												(163,000,000)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Southwest Royalties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units										$ 60,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Other Divestitures
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value								81,000,000				81,000,000				$ 39,000,000	81,000,000	39,000,000
Gain (loss) on sale																	4,000,000	$ (6,000,000)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Reeves County Assets | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration value																					$ 132,000,000
Proved and unproved non-core acreage | a																					13,000
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
Ownership interest sold															47.00%				47.00%
Consideration adjustment																			$ 6,000,000
Asset consideration															$ 67,000,000				67,000,000
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 Divestitures											$ 40,000,000								$ 131,000,000
Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill								$ 110,000,000				$ 110,000,000					$ 110,000,000

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Purchase Price Allocation (Details) - Clayton Williams Energy $ in Millions	Apr. 24, 2017USD ($)
Business Acquisition [Line Items]
Fair Value of Common Stock Issued	$ 1,851
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders	637
Total Purchase Price	2,488
Plus Liabilities Assumed by Noble Energy:
Accounts Payable	99
Other Current Liabilities	38
Long-Term Deferred Tax Liability	515
Long-Term Debt	595
Asset Retirement Obligations	63
Total Purchase Price Plus Liabilities Assumed	$ 3,798

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Fair Value of Acquired Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017	Apr. 24, 2017
Business Acquisition [Line Items]
Goodwill	$ 110	$ 1,400	$ 1,310
Clayton Williams Energy
Business Acquisition [Line Items]
Cash and Cash 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				1,291
Total Asset Value				$ 3,798

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Pro Forma Information (Details) - Clayton Williams Energy - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenues	$ 4,986	$ 4,304	$ 3,651
Net Loss Attributable to Noble Energy	$ (66)	$ (678)	$ (1,082)
Net Income (Loss) Attributable to Noble Energy per Common Share
Basic (in usd per share)	$ (0.14)	$ (1.39)	$ (2.23)
Diluted (in usd per share)	$ (0.14)	$ (1.39)	$ (2.23)

Goodwill Impairment - Narrative

Goodwill Impairment - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 110	$ 1,400	$ 1,310
Texas
Goodwill [Line Items]
Goodwill		$ 1,300
Midstream
Goodwill [Line Items]
Goodwill	$ 110

Capitalized Exploratory Well _3

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Exploratory Well Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2018USD ($)project	Dec. 31, 2017USD ($)project	Dec. 31, 2016USD ($)project
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized Exploratory Well Costs, Beginning of Period	$ 520	$ 768	$ 1,353
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	7	20	84
Divestitures and Other	(168)	0	(143)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale	(1)	(203)	(1)
Capitalized Exploratory Well Costs Charged to Expense	(4)	(65)	(525)
Capitalized Exploratory Well Costs, End of Period	354	520	768
Exploratory Wells Drilled [Line Items]
Ownership interest sold						35.00%
Exploratory Well Costs Capitalized for a Period of One Year or Less				$ 6	$ 10	$ 69
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling				348	510	699
Balance at End of Period	$ 520	$ 520	$ 768	$ 354	$ 520	$ 768
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project				7	8	10
Cyprus Block 12
Exploratory Wells Drilled [Line Items]
Ownership interest sold				35.00%

Capitalized Exploratory Well _4

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Exploratory Well Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 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	$ 348	$ 510	$ 699
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	48
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	24
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	52
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	94
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	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	100
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	6
Suspended Since 2016 and 2017
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
Suspended Since 2016 and 2017 | 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	3
Suspended Since 2016 and 2017 | 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	2
Suspended Since 2016 and 2017 | 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	(1)
Suspended Since 2016 and 2017 | 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	6
Suspended Since 2016 and 2017 | 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	2
Suspended Since 2016 and 2017 | 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	11
Suspended Since 2016 and 2017 | 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	(7)
Suspended Since 2014 and 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	49
Suspended Since 2014 and 2015 | 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	7
Suspended Since 2014 and 2015 | 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	3
Suspended Since 2014 and 2015 | 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	6
Suspended Since 2014 and 2015 | 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	8
Suspended Since 2014 and 2015 | 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	3
Suspended Since 2014 and 2015 | 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	12
Suspended Since 2014 and 2015 | 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	10
Suspended Since 2013 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	283
Suspended Since 2013 and Prior | 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	38
Suspended Since 2013 and Prior | 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	19
Suspended Since 2013 and Prior | 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	47
Suspended Since 2013 and Prior | 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	80
Suspended Since 2013 and Prior | 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	19
Suspended Since 2013 and Prior | 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	77
Suspended Since 2013 and Prior | 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	$ 3

Capitalized Exploratory Well _5

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Undeveloped leasehold costs, net	$ 2,373	$ 2,922	$ 2,197
International
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	53
Domestic
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	31
Delaware Basin
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	2,200
Eagle Ford
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized undeveloped leasehold cost	$ 100

Capitalized Exploratory Well _6

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Rollforward of Undeveloped Lease Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Proved Developed and Undeveloped Reserves [Roll Forward]
Undeveloped Leasehold Costs, Beginning of Period	$ 2,922	$ 2,197
Additions to Undeveloped Leasehold Costs	47	1,859
Transfers to Proved Properties	(453)	(174)
Assets Sold	(142)	(884)
Impairment	(1)	(62)
Other	0	(14)
Undeveloped Leasehold Costs, Net of Impairment, End of Period	$ 2,373	$ 2,922

Asset Retirement Obligations -

Asset Retirement Obligations - Change in AROs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance	$ 875	$ 935
Liabilities Incurred	25	94
Liabilities Settled	(345)	(82)
Revisions of Estimates	293	(65)
Reclassification to Liabilities Associated with Assets Held for Sale	(1)	(54)
Accretion Expense	33	47
Asset Retirement Obligations, Ending Balance	$ 880	$ 875

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	$ 345	$ 82
Revisions of Estimates	293	(65)
Liabilities Incurred	25	94
Reclassification to Liabilities Associated with Assets Held for Sale	1	54
Gulf of Mexico assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	216
Greeley Crescent DJ Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		19
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	104	43
Revisions of Estimates	287
Wells Offshore Israel
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	10
Equatorial Guinea [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	9
North Sea
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	(17)	(42)
Greeley Crescent Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled	$ 24
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
US Onshore and Gulf of Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		(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
Clayton Williams Energy
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Incurred		63
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Incurred		31
West Africa
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		$ 15

Long-Term Debt - Summary of Deb

Long-Term Debt - Summary of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt	$ 6,675	$ 6,859
Unamortized Discount	(22)	(24)
Unamortized Premium	0	12
Unamortized Debt Issuance Costs	(38)	(40)
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs	6,615	6,807
Capital Lease Obligations, Current	(41)	(61)
Long-Term Debt Due After One Year	6,574	6,746
Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Debt	$ 0	$ 230
Interest Rate	0.00%	2.27%
Senior Notes, due May 1, 2021
Debt Instrument [Line Items]
Debt	$ 0	$ 379
Interest Rate	0.00%	5.63%
Senior Notes, due December 15, 2021
Debt Instrument [Line Items]
Debt	$ 1,000	$ 1,000
Interest Rate	4.15%	4.15%
Senior Notes, due October 15, 2023
Debt Instrument [Line Items]
Debt	$ 100	$ 100
Interest Rate	7.25%	7.25%
Senior Notes, due November 15, 2024
Debt Instrument [Line Items]
Debt	$ 650	$ 650
Interest Rate	3.90%	3.90%
Senior Notes, due April 1, 2027
Debt Instrument [Line Items]
Debt	$ 250	$ 250
Interest Rate	8.00%	8.00%
Senior Notes, due January 15, 2028
Debt Instrument [Line Items]
Debt	$ 600	$ 600
Interest Rate	3.85%	3.85%
Senior Notes, due March 1, 2041
Debt Instrument [Line Items]
Debt	$ 850	$ 850
Interest Rate	6.00%	6.00%
Senior Notes, due November 15, 2043
Debt Instrument [Line Items]
Debt	$ 1,000	$ 1,000
Interest Rate	5.25%	5.25%
Senior Notes, due November 15, 2044
Debt Instrument [Line Items]
Debt	$ 850	$ 850
Interest Rate	5.05%	5.05%
Senior Notes, due August 15, 2047
Debt Instrument [Line Items]
Debt	$ 500	$ 500
Interest Rate	4.95%	4.95%
Other Senior Notes and Debentures
Debt Instrument [Line Items]
Debt	$ 92	$ 92
Interest Rate	7.13%	7.13%
Capital Lease Obligations
Debt Instrument [Line Items]
Capital Lease Obligations	$ 223	$ 273
Interest Rate	0.00%	0.00%
Senior Notes, due June 1, 2024
Debt Instrument [Line Items]
Debt	$ 8
Senior Debentures due August 1, 2097
Debt Instrument [Line Items]
Debt	$ 84
Revolving Credit Facility | Noble Midstream Services Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Debt		$ 85
Interest Rate	3.67%	2.75%
Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility
Debt Instrument [Line Items]
Debt	$ 500	$ 0
Interest Rate	3.42%	0.00%

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($)	Jul. 31, 2018	Aug. 15, 2017	May 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2018	Feb. 24, 2017
Debt Instrument [Line Items]
Debt						$ 6,675,000,000	$ 6,859,000,000
Repayments of senior debt						384,000,000	1,114,000,000	$ 1,383,000,000
Unamortized discount						22,000,000	24,000,000
Proceeds from issuance of senior notes						0	1,086,000,000	$ 0
Unamortized Premium						0	12,000,000
Senior Notes
Debt Instrument [Line Items]
Unamortized discount		$ 4,000,000
Debt issuance costs, gross		11,000,000
Proceeds from issuance of senior notes		1,100,000,000
Loss on debt					$ 98,000,000
Noble Midstream | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity						$ 500,000,000
Noble Midstream | Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity							350,000,000		$ 800,000,000
Noble Midstream | Line of Credit | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Basis spread						0.50%
Noble Midstream | Line of Credit | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread						1.00%
Line of Credit | Noble Midstream
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 500,000,000
Credit facility, term						3 years
Minimum | Line of Credit | Noble Midstream | Base Rate
Debt Instrument [Line Items]
Basis spread	0.00%
Minimum | Line of Credit | Noble Midstream | Eurodollar
Debt Instrument [Line Items]
Basis spread	1.00%
Maximum | Line of Credit | Noble Midstream | Base Rate
Debt Instrument [Line Items]
Basis spread	0.50%
Maximum | Line of Credit | Noble Midstream | Eurodollar
Debt Instrument [Line Items]
Basis spread	1.50%
Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Maximum borrowing capacity						$ 4,000,000,000
Credit facility fee rate basis points, minimum						0.10%
Credit facility fee rate basis points, maximum						0.25%
Credit facility interest rate, Eurodollar rate plus, minimum						0.90%
Credit facility interest rate, Eurodollar rate plus, maximum						1.50%
Credit facility covenant term debt to capitalization ratio maximum						65.00%
Debt						$ 0	$ 230,000,000
Interest Rate						0.00%	2.27%
Noble Midstream Services Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Repayments of term loan facility				$ 480,000,000
Debt						$ 60,000,000
Noble Midstream Services Term Loan Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Debt						$ 500,000,000	$ 0
Interest Rate						3.42%	0.00%
Senior Notes, due May 1, 2021
Debt Instrument [Line Items]
Debt						$ 0	$ 379,000,000
Repayments of senior debt			$ 395,000,000
Interest Rate						0.00%	5.63%
Senior Notes, due May 1, 2021 | Senior Notes
Debt Instrument [Line Items]
Extinguishment of Debt, Amount			$ 379,000,000
Senior Notes, due January 15, 2028
Debt Instrument [Line Items]
Debt						$ 600,000,000	$ 600,000,000
Interest Rate						3.85%	3.85%
Senior Notes, due January 15, 2028 | Senior Notes
Debt Instrument [Line Items]
Face amount		$ 600,000,000
Interest Rate		3.85%
Senior Notes, due August 15, 2047
Debt Instrument [Line Items]
Debt						$ 500,000,000	$ 500,000,000
Interest Rate						4.95%	4.95%
Senior Notes, due August 15, 2047 | Senior Notes
Debt Instrument [Line Items]
Face amount		$ 500,000,000
Interest Rate		4.95%
Senior Notes, due March 1, 2019 | Senior Notes
Debt Instrument [Line Items]
Interest Rate				8.25%
Debt redemption amount		$ 1,100,000,000
Unamortized Premium		$ 96,000,000
Leviathan Term Loan Facility, due February 23, 2025 | Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity										$ 1,000,000,000
Long-term line of credit										$ 625,000,000

Long-Term Debt - Debt Maturitie

Long-Term Debt - Debt Maturities (Details) $ in Millions	Dec. 31, 2018USD ($)
Debt Disclosure [Abstract]
2,019	$ 0
2,020	0
2,021	1,500
2,022	0
2,023	160
Thereafter	4,792
Total	$ 6,452

Marcellus Shale Firm Transpor_3

Marcellus Shale Firm Transportation Commitments - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Purchase Commitment [Line Items]
Commitment amount		$ 1,500
Purchased Oil and Gas		296	$ 0	$ 0
Marcellus Shale Firm Transportation and Other Obligations (1)
Long-term Purchase Commitment [Line Items]
Marcellus Exit Cost Accrual		$ 0	93
Appalachian Gateway Project
Long-term Purchase Commitment [Line Items]
Exit costs			41
Leach/Rayne Xpress
Long-term Purchase Commitment [Line Items]
Exit costs			$ 52
Minimum
Long-term Purchase Commitment [Line Items]
Term		4 years
Minimum | Marcellus Shale Firm Transportation and Other Obligations (1)
Long-term Purchase Commitment [Line Items]
Term		2 years
Maximum
Long-term Purchase Commitment [Line Items]
Term		15 years
Maximum | Marcellus Shale Firm Transportation and Other Obligations (1)
Long-term Purchase Commitment [Line Items]
Term		10 years
Subsequent Event | Leach/Rayne Xpress
Long-term Purchase Commitment [Line Items]
Exit costs	$ 92
Commitment reduction	$ 350

Marcellus Shale Firm Transpor_4

Marcellus Shale Firm Transportation Commitments - Rollforward of Accrued Transportation Commitment (Details) - Marcellus Shale Firm Transportation and Other Obligations (1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Rollforward Of Contractual Obligations [Roll Forward]
Balance at Beginning of Period	$ 90	$ 0
Marcellus Exit Cost Accrual	0	93
Payments, Net of Accretion	(10)	(3)
Balance at End of Period	80	90
Other Current Liabilities
Rollforward Of Contractual Obligations [Roll Forward]
Balance at Beginning of Period	14
Balance at End of Period	13	14
Other Noncurrent Liabilities
Rollforward Of Contractual Obligations [Roll Forward]
Balance at Beginning of Period	76
Balance at End of Period	$ 67	$ 76

Marcellus Shale Firm Transpor_5

Marcellus Shale Firm Transportation Commitments - Income Statement Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Purchase Commitment [Line Items]
Purchased Oil and Gas	$ 296	$ 0	$ 0
Purchased Oil and Gas | Operating Segments | United States
Long-term Purchase Commitment [Line Items]
Sales of Purchased Oil and Gas	113	0	0
Purchased Oil and Gas	108	0	0
Firm Transportation Expense | Operating Segments | United States
Long-term Purchase Commitment [Line Items]
Purchased Oil and Gas	29	0	0
Unutilized Firm Transportation Expense | Operating Segments | United States
Long-term Purchase Commitment [Line Items]
Purchased Oil and Gas	3	0	0
Sales of Purchased Gas, Net | Operating Segments | United States
Long-term Purchase Commitment [Line Items]
Purchased Oil and Gas	$ 140	$ 0	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Thousands	1 Months Ended		12 Months Ended			48 Months Ended
	Sep. 30, 2018USD ($)well	Jul. 31, 2018USD ($)well	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2018USD ($)
Other Commitments [Line Items]
Wells requiring corrective action | well		5
Wells alleged noncompliance | well	8
Settlement amount	$ 1,600	$ 135
Commitment amount			$ 1,500,000
Rental expense for office buildings and oil and gas operations equipment			90,000	$ 69,000	$ 76,000
Consent Decree
Other Commitments [Line Items]
Corrective actions			5,000			$ 84,000
Mitigation projects			4,000
Supplemental environmental projects			4,000
Consent Decree - Corrective Actions At Certain Tank Systems
Other Commitments [Line Items]
Corrective actions						$ 77,000
Other Transportation and Gathering Obligations
Other Commitments [Line Items]
Commitment amount			$ 612,000
Minimum
Other Commitments [Line Items]
Term			4 years
Minimum | Marcellus Shale Firm Transportation and Other Obligations (1)
Other Commitments [Line Items]
Term			2 years
Maximum
Other Commitments [Line Items]
Term			15 years
Maximum | Marcellus Shale Firm Transportation and Other Obligations (1)
Other Commitments [Line Items]
Term			10 years
Administrative Penalty Subject To Deferral Period
Other Commitments [Line Items]
Settlement amount		$ 41
Administrative Penalty Subject To Offset
Other Commitments [Line Items]
Settlement amount	$ 1,400

Commitments and Contingencies_2

Commitments and Contingencies - Minimum Commitments Due (Details) $ in Millions	Dec. 31, 2018USD ($)
Other Commitments [Line Items]
2,019	$ 614
2,020	400
2,021	327
2,022	275
2,023	270
2024 and Thereafter	1,504
Total	3,390
Purchase and Service Obligations
Other Commitments [Line Items]
2,019	197
2,020	29
2,021	13
2,022	6
2,023	21
2024 and Thereafter	5
Total	271
Marcellus Shale Firm Transportation and Other Obligations (1)
Other Commitments [Line Items]
2,019	123
2,020	122
2,021	121
2,022	118
2,023	113
2024 and Thereafter	934
Total	1,531
Gathering, Transportation & Processing Obligations
Other Commitments [Line Items]
2,019	151
2,020	129
2,021	103
2,022	67
2,023	66
2024 and Thereafter	285
Total	801
Operating Lease Obligations
Other Commitments [Line Items]
2,019	91
2,020	74
2,021	59
2,022	62
2,023	50
2024 and Thereafter	176
Total	512
Capital Lease and Other Obligations
Other Commitments [Line Items]
2,019	52
2,020	46
2,021	31
2,022	22
2,023	20
2024 and Thereafter	104
Total	$ 275

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Components of income (loss) before income taxes [Abstract]
Domestic	$ (953)	$ (2,831)	$ (1,859)
Foreign	1,093	640	87
Income (Loss) Before Income Taxes	140	(2,191)	(1,772)
Current Taxes
Federal	22	(11)	(4)
State	2	1	5
Foreign	172	96	196
Total Current	196	86	197
Deferred Taxes
Federal	(123)	(1,258)	(784)
State	(7)	(8)	(24)
Foreign	60	39	(176)
Total Deferred	(70)	(1,227)	(984)
Total Income Tax Provision (Benefit) Attributable to Noble Energy	$ 126	$ (1,141)	$ (787)
Effective Tax Rate (in hundredths)	90.00%	52.10%	44.40%
Federal statutory tax rate reconciliation [Abstract]
Federal Statutory Rate (in hundredths)	21.00%	35.00%	35.00%
Effect of
Goodwill Impairment	192.50%	0.00%	0.00%
Change in Valuation Allowance	(170.20%)	(17.40%)	(2.00%)
US and Foreign Statutory Rate Change	80.70%	23.50%	1.60%
Accumulated Undistributed Foreign Earnings	0.00%	11.00%	7.20%
Transition Tax	0.00%	(4.80%)	0.00%
Difference Between US and Foreign Rates	17.90%	1.80%	(0.10%)
Earnings of Equity Method Investees	(20.10%)	1.90%	1.00%
Noncontrolling Interests	(12.10%)	1.10%	0.40%
State Taxes, Net of Federal Benefit	0.90%	0.30%	1.30%
Foreign Exploration Loss	(35.60%)	0.00%	0.00%
Global Intangible Low-Taxed Income (GILTI)	24.20%	0.00%	0.00%
Return to Provision	(17.10%)	(0.10%)	(0.20%)
Audit Settlement	5.10%	0.10%	(0.20%)
Oil Profits Tax - Israel	3.30%	(0.10%)	0.00%
Other, Net	(0.50%)	(0.20%)	0.40%
Effective Rate	90.00%	52.10%	44.40%
Deferred Tax Assets
Loss Carryforwards	$ 589	$ 902
Employee Compensation and Benefits	92	97
Mark to Market of Commodity Derivative Instruments	(27)
Mark to Market of Commodity Derivative Instruments		7
Foreign Tax Credits	138	366
Other	157	104
Total Deferred Tax Assets	949	1,476
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits	(320)	(549)
Net Deferred Tax Assets	629	927
Deferred Tax Liabilities
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments	(1,669)	(2,029)
Total Deferred Tax Liability	(1,669)	(2,029)
Net Deferred Tax Liability	$ (1,040)	$ (1,102)

Income Taxes - Net Deferred Tax

Income Taxes - Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Deferred Income Tax Asset - Noncurrent	$ 21	$ 25
Deferred Income Tax Liability - Noncurrent	(1,061)	(1,127)
Net Deferred Tax Liability	$ (1,040)	$ (1,102)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 14, 2018	Apr. 24, 2017
Tax Credit Carryforward [Line Items]
Deferred tax asset, TCJA		$ 10	$ 500
Additional taxable income, TCJA			767
Foreign tax credits			164
Toll tax accrued	$ 21	21	268
Operating loss carryforwards	2,400	2,400
Foreign loss carryforward	320	$ 320	$ 549
Federal Statutory Rate (in hundredths)		21.00%	35.00%	35.00%
Deferred Income Taxes		$ 70	$ 1,227	$ 984
Ownership interest sold				35.00%
Income Tax Expense (Benefit)		$ 126	$ (1,141)	$ (787)
Transition tax for accumulated foreign earnings	261
Effective Rate		90.00%	52.10%	44.40%
Clayton Williams Energy
Tax Credit Carryforward [Line Items]
Deferred tax liabilities						$ 307
Deferred tax assets						$ 450
One-time Deemed Repatriation
Tax Credit Carryforward [Line Items]
Foreign tax credits		$ 252		$ 240
Change in enacted tax rate, amount	5		$ 107
Income Tax Expense (Benefit)			(145)
Write-Off Of Foreign Exploration Losses
Tax Credit Carryforward [Line Items]
Change in enacted tax rate, amount		50
Global Intangible Low-Taxed Income
Tax Credit Carryforward [Line Items]
Change in enacted tax rate, amount		34
Foreign Loss Carryforward
Tax Credit Carryforward [Line Items]
Foreign loss carryforward	187	187	183
Foreign Tax Credit
Tax Credit Carryforward [Line Items]
Foreign loss carryforward	132	132	$ 366
Domestic Tax Authority
Tax Credit Carryforward [Line Items]
Operating loss carryforwards	1,700	1,700
Foreign Tax Authority
Tax Credit Carryforward [Line Items]
Operating loss carryforwards	$ 670	670
Israel
Tax Credit Carryforward [Line Items]
Deferred Income Taxes		$ 12
Effective Rate		46.80%
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%
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Tamar and Dalit Fields
Tax Credit Carryforward [Line Items]
Ownership interest sold					7.50%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Derivative Instruments Summary (Details)	Dec. 31, 2018bbl / dMMBTU / d$ / bbl$ / MMBTU
Crude Oil | 2019 Swaps NYMEX WTI
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	22,000
Weighted Average Fixed Price (in usd per unit)	56.96
Crude Oil | 2019 Three-Way Collars NYMEX WTI
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	33,000
Weighted Average Short Put Price (in usd per unit)	49.35
Weighted Average Floor Price (in usd per unit)	59.35
Weighted Average Ceiling Price (in usd per unit)	72.25
Crude Oil | 2019 Swaps ICE Brent
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	5,000
Weighted Average Fixed Price (in usd per unit)	57
Crude Oil | 2019 Three-Way Collars ICE Brent
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	3,000
Weighted Average Short Put Price (in usd per unit)	43
Weighted Average Floor Price (in usd per unit)	50
Weighted Average Ceiling Price (in usd per unit)	64.07
Crude Oil | 2019 Basis Swaps
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	27,000
Weighted Average Differential (in usd per unit)	(3.23)
Crude Oil | 2020 Swaption NYMEX WTI
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	5,000
Weighted Average Fixed Price (in usd per unit)	61.79
Crude Oil | 2020 Basis Swap
Derivative [Line Items]
Volume Per Day (in units per day) | bbl / d	15,000
Weighted Average Differential (in usd per unit)	(5.01)
Natural Gas | 2019 Swaps NYMEX HH
Derivative [Line Items]
Volume Per Day (in units per day) | MMBTU / d	86,500
Weighted Average Fixed Price (in usd per unit) | $ / MMBTU	4.36
Natural Gas | 2019 Three-Way Collars NYMEX HH
Derivative [Line Items]
Volume Per Day (in units per day) | MMBTU / d	104,000
Weighted Average Short Put Price (in usd per unit) | $ / MMBTU	2.25
Weighted Average Floor Price (in usd per unit) | $ / MMBTU	2.65
Weighted Average Ceiling Price (in usd per unit) | $ / MMBTU	2.95
Natural Gas | 2019 Three-Way Collars NYMEX HH
Derivative [Line Items]
Volume Per Day (in units per day) | MMBTU / d	21,500
Weighted Average Short Put Price (in usd per unit) | $ / MMBTU	3
Weighted Average Floor Price (in usd per unit) | $ / MMBTU	3.25
Weighted Average Ceiling Price (in usd per unit) | $ / MMBTU	4.08
Natural Gas | 2019 Basis Swaps
Derivative [Line Items]
Volume Per Day (in units per day) | MMBTU / d	52,000
Weighted Average Differential (in usd per unit) | $ / MMBTU	(0.74)

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities - Fair Value and Effect on Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Cash Paid (Received) in Settlement of Commodity Derivative Instruments	$ 161	$ (13)	$ (569)
Asset Derivative Instruments	180	2
Liability Derivative Instruments	27	73
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(224)	(50)	708
Total (Gain) Loss on Commodity Derivative Instruments	(63)	(63)	139
Crude Oil
Derivatives, Fair Value [Line Items]
Cash Paid (Received) in Settlement of Commodity Derivative Instruments	162	(14)	(499)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(225)	18	582
Total (Gain) Loss on Commodity Derivative Instruments	(63)	4	83
Natural Gas
Derivatives, Fair Value [Line Items]
Cash Paid (Received) in Settlement of Commodity Derivative Instruments	(1)	1	(70)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	1	(68)	126
Total (Gain) Loss on Commodity Derivative Instruments	0	(67)	$ 56
Current Assets
Derivatives, Fair Value [Line Items]
Asset Derivative Instruments	180	2
Current Liabilities
Derivatives, Fair Value [Line Items]
Liability Derivative Instruments	1	58
Noncurrent Assets
Derivatives, Fair Value [Line Items]
Asset Derivative Instruments	0	0
Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Liability Derivative Instruments	$ 26	$ 15

Fair Value Measurements and D_3

Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Nonrecurring Basis (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Financial Assets
Mutual Fund Investments	$ 38	$ 57
Commodity Derivative Instruments	180	2
Financial Liabilities
Commodity Derivative Instruments	(27)	(73)
Portion of Deferred Compensation Liability Measured at Fair Value	(43)	(71)
Stock Based Compensation Liability Measured at Fair Value	(8)	(10)
Quoted Prices in Active Markets (Level 1)
Financial Assets
Mutual Fund Investments	38	57
Commodity Derivative Instruments	0	0
Financial Liabilities
Commodity Derivative Instruments	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	(43)	(71)
Stock Based Compensation Liability Measured at Fair Value	(8)	(10)
Significant Other Observable Inputs (Level 2)
Financial Assets
Mutual Fund Investments	0	0
Commodity Derivative Instruments	187	7
Financial Liabilities
Commodity Derivative Instruments	(34)	(78)
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	0
Significant Unobservable Inputs (Level 3)
Financial Assets
Mutual Fund Investments	0	0
Commodity Derivative Instruments	0	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
Adjustment
Financial Assets
Mutual Fund Investments	0	0
Commodity Derivative Instruments	(7)	(5)
Financial Liabilities
Commodity Derivative Instruments	7	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 D_4

Fair Value Measurements and Disclosures - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge		$ 206
Goodwill	$ 110	110	$ 1,310		$ 1,400
Inventory impairment				$ 14
Firm transportation liability			93
Held-for-sale
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge	38
Held-for-sale | Gulf of Mexico assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge		$ 168
Held-for-sale | Certain midstream assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge	$ 37
Held-for-sale | Troubadour
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge			$ 70
Held-for-sale | Leviathan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge				$ 92
Texas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill					$ 1,300

Fair Value Measurements and D_5

Fair Value Measurements and Disclosures - Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Net	$ 6,452	$ 6,586
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Net	$ 6,121	$ 7,142

Equity Method Investments - Sum

Equity Method Investments - Summary of Equity Method Investments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 286	$ 305
Advantage Pipeline
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	73	70
AMPCO
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	131	129
Alba Plant
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	58	80
Other
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 24	$ 26

Equity Method Investments - Nar

Equity Method Investments - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Retained earnings related to undistributed earnings of equity method investees	$ 68
Difference between the carrying value of an equity method investment and the underlying net assets of the investee	13
Equity Method Investments	$ 286	$ 305
Advantage Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership interest in equity method investments	50.00%
Equity Method Investments	$ 73	70
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	$ 58	$ 80

Equity Method Investments - S_2

Equity Method Investments - Summarized Financial Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Balance Sheet Information
Current Assets	$ 387	$ 390
Noncurrent Assets	575	588
Current Liabilities	198	171
Noncurrent Liabilities	81	90
Statements of Operations Information
Operating Revenues	855	790	$ 667
Operating Expenses	284	303	355
Operating Income	571	487	312
Other Income, net	3	15	7
Income Before Income Taxes	574	502	319
Income Tax Provision	152	136	60
Net Income	$ 422	$ 366	$ 259

Additional Shareholders' Equi_3

Additional Shareholders' Equity Information - Common Stock Rollforward (Details) - USD ($) $ / shares in Units, $ in Millions	Apr. 24, 2017	Dec. 31, 2018	Dec. 31, 2017	Feb. 15, 2018
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares Received In Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock		720,000
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 Earnings (Loss) per Share (4)		15,004,591	15,619,276
Share repurchase program authorized amount				$ 750
Repurchase price (in usd per share)		$ 29.49
Common Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, beginning balance		528,743,381	471,360,427
Exercise of Common Stock Options		576,617	382,882
Restricted stock awards, net of forfeitures		2,488,363	2,912,936
Purchase and Retirement of Common Stock		(10,008,128)	0
Shares Exchanged in Clayton Williams Energy Acquisition		(745,232)	54,087,136
Shares, ending balance		521,055,001	528,743,381
Treasury Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, beginning balance		38,786,969	37,961,316
Shares Received In Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock		267,258	1,026,891
Rabbi Trust Shares Distributed and/or Sold		(202,239)	(201,238)
Shares, ending balance		38,851,988	38,786,969
Clayton Williams Energy
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares Exchanged in Clayton Williams Energy Acquisition	56,000,000
Restricted Stock | Clayton Williams Energy
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Awarded shares		1,900,000

Additional Shareholders' Equi_4

Additional Shareholders' Equity Information - Components of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Loss
Beginning Balance	$ 10,619	$ 9,600	$ 10,370
Realized Amounts Reclassified Into Earnings	(2)	5	5
Unrealized Change in Fair Value	0	(4)	(3)
Ending Balance	10,484	10,619	9,600
Total
Accumulated Other Comprehensive Loss
Beginning Balance	(30)	(31)	(33)
Ending Balance	(32)	(30)	(31)
Interest Rate Cash Flow Hedge
Accumulated Other Comprehensive Loss
Beginning Balance	(20)	(21)	(22)
Realized Amounts Reclassified Into Earnings	(3)	1	1
Unrealized Change in Fair Value	0	0	0
Ending Balance	(23)	(20)	(21)
Other Postretirement Benefit Plans
Accumulated Other Comprehensive Loss
Beginning Balance	(10)	(10)	(11)
Realized Amounts Reclassified Into Earnings	1	4	4
Unrealized Change in Fair Value	0	(4)	(3)
Ending Balance	$ (9)	$ (10)	$ (10)

Additional Shareholders' Equi_5

Additional Shareholders' Equity Information - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Derivative [Line Items]
Stranded tax assets	$ 6
Interest Rate Contract
Derivative [Line Items]
Loss on derivative	$ 24

Stock-Based and Other Compens_3

Stock-Based and Other Compensation Plans - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Total Stock-Based Compensation Expense	$ 62	$ 104	$ 77
Tax Benefit Recognized	(13)	(36)	(27)
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Total Stock-Based Compensation Expense	54	56	62
Exploration Expense and Other
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Total Stock-Based Compensation Expense	$ 8	$ 48	$ 15

Stock-Based and Other Compens_4

Stock-Based and Other Compensation Plans - Narrative (Details) $ / shares in Units, $ in Millions	Feb. 01, 2016simulation$ / sharesshares	Dec. 31, 2018USD ($)simulation$ / sharesshares	Dec. 31, 2017USD ($)simulation$ / sharesshares	Dec. 31, 2016USD ($)simulation$ / 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	$ 31	$ 32
Shares of common stock held by rabbi trust (in dollars per share) | $ / shares		$ 16.72
Deferred compensation arrangement most shares held by individual		200,000
Deferred compensation arrangement, percent of the most shares held by individual		75.00%
Deferred compensation distribution timeline		2 years
Deferred compensation arrangement plan, distribution amount		200,000	200,000	200,000
Deferred compensation arrangement shares sold		2,239	1,238	1,009
Deferred compensation arrangements trust plan, distribution amount | $		$ 18	$ 21	$ 22
Deferred compensation (income) expense | $		2	9	11
Deferred compensation liabilities | $		$ 104	116
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 | $		$ 5	$ 4	$ 10
Unrecognized compensation cost related to nonvested awards | $		$ 11
The weighted-average period over which unrecognized compensation cost is to be recognized (in years)		1 year 2 months 12 days
Expected volatility (in hundredths)		33.40%	33.20%	32.40%
Risk-free rate (in hundredths)		2.60%	2.20%	1.60%
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to nonvested awards | $		$ 74
The weighted-average period over which unrecognized compensation cost is to be recognized (in years)		1 year 6 months
Total fair value of vested restricted stock | $		$ 29	$ 34	$ 24
Weighted average award date fair value, shares awarded (in dollars per share) | $ / shares		$ 27.96	$ 35.45	$ 29.99
Number of Simulations | simulation		10,000,000	500,000	500,000
Expected volatility (in hundredths)		35.00%	35.00%	38.00%
Risk-free rate (in hundredths)		2.30%	1.50%	1.00%
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		$ 30.68
Weighted average award date fair value (in dollars per share) | $ / shares		32.72	$ 37.21
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)		29,000,000
Number of shares of common stock reserved for issuance (in shares)		26,621,632
Shares of common stock available for future grants and awards (in shares)		21,084,928
Expiration period (in years)		10 years
2017 Long-Term Incentive Plan | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period		3 years
2017 Long-Term Incentive Plan | Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period		2 years
2017 Long-Term Incentive Plan | Restricted Stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option vesting period		3 years
2017 Long-Term Incentive Plan | Performance Shares
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)		708,996
Number of shares of common stock reserved for issuance (in shares)		576,798
Shares of common stock available for future grants and awards (in shares)		397,979
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)	1,000,000
Number of Simulations | simulation	500,000
Risk-free rate (in hundredths)	0.90%
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 | $		$ 8

Stock-Based and Other Compens_5

Stock-Based and Other Compensation Plans - Assumptions and Award Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock Option
Assumptions used to value stock option awards [Abstract]
Expected term (in years)	6 years 8 months 12 days	6 years 4 months 24 days	6 years 3 months 18 days
Expected volatility (in hundredths)	33.40%	33.20%	32.40%
Risk-free rate (in hundredths)	2.60%	2.20%	1.60%
Expected dividend yield (in hundredths)	1.20%	0.90%	0.70%
Weighted-average grant-date fair value of options granted (in dollars per share)	$ 10.47	$ 13.26	$ 10.10
Restricted Stock
Assumptions used to value stock option awards [Abstract]
Expected volatility (in hundredths)	35.00%	35.00%	38.00%
Risk-free rate (in hundredths)	2.30%	1.50%	1.00%

Stock-Based and Other Compens_6

Stock-Based and Other Compensation Plans - Stock Option Activity (Details) - Stock Option $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares
Options
Outstanding, beginning balance (in shares) | shares	15,549,222
Granted (in shares) | shares	551,888
Exercised (in shares) | shares	(576,617)
Forfeited (in shares) | shares	(1,672,473)
Outstanding, ending balance (in shares) | shares	13,852,020
Exercisable (in shares) | shares	11,866,188
Weighted Average Exercise Price
Weighted average exercise price per share outstanding, beginning balance (in dollars per share) | $ / shares	$ 43.42
Weighted average exercise price per share granted (in dollars per share) | $ / shares	30.20
Weighted average exercise price per share exercised (in dollars per share) | $ / shares	34.55
Weighted average exercise price per share forfeited (in dollars per share) | $ / shares	40.04
Weighted average exercise price per share outstanding, ending balance (in dollars per share) | $ / shares	44.04
Weighted average exercise price per exercisable share (in dollars per share) | $ / shares	$ 45.58
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 | $	$ 0
Aggregate intrinsic value, exercisable shares | $	$ 0

Stock-Based and Other Compens_7

Stock-Based and Other Compensation Plans - Assumptions Used For Restricted Stock (Details) - Restricted Stock - simulation	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Simulations	10,000,000	500,000	500,000
Expected volatility (in hundredths)	35.00%	35.00%	38.00%
Risk-free rate (in hundredths)	2.30%	1.50%	1.00%

Stock-Based and Other Compens_8

Stock-Based and Other Compensation Plans - Restricted Stock and Phantom Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Phantom Share Units (PSUs) | Subject to Time Vesting
Number of Shares
Outstanding, beginning balance (in shares)	610,159
Vested (in shares)	(83,276)
Forfeited (in shares)	(59,518)
Outstanding, ending balance (in shares)	467,365	610,159
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
Phantom Share Units (PSUs) | Subject to Market Conditions
Number of Shares
Outstanding, beginning balance (in shares)	167,483
Vested (in shares)	0
Forfeited (in shares)	(17,187)
Outstanding, ending balance (in shares)	150,296	167,483
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
Restricted Stock
Weighted Average Award Date Fair Value
Weighted average award date fair value, shares awarded (in dollars per share)	$ 27.96	$ 35.45	$ 29.99
Restricted Stock | Subject to Time Vesting
Number of Shares
Outstanding, beginning balance (in shares)	1,839,737
Awarded (in shares)	2,702,426
Vested (in shares)	(982,280)
Forfeited (in shares)	(386,992)
Outstanding, ending balance (in shares)	3,172,891	1,839,737
Weighted Average Award Date Fair Value
Weighted average award date fair value, beginning of period (in dollars per share)	$ 37.21
Weighted average award date fair value, shares awarded (in dollars per share)	30.68
Weighted average award date fair value, shares vested (in dollars per share)	35.28
Weighted average award date fair value, shares forfeited (in dollars per share)	32.65
Weighted average award date fair value, end of period (in dollars per share)	$ 32.72	$ 37.21
Restricted Stock | Subject to Market Conditions
Number of Shares
Outstanding, beginning balance (in shares)	1,212,705
Awarded (in shares)	874,960
Vested (in shares)	0
Forfeited (in shares)	(702,031)
Outstanding, ending balance (in shares)	1,385,634	1,212,705
Weighted Average Award Date Fair Value
Weighted average award date fair value, beginning of period (in dollars per share)	$ 25.55
Weighted average award date fair value, shares awarded (in dollars per share)	19.56
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)	25.52
Weighted average award date fair value, end of period (in dollars per share)	$ 21.74	$ 25.55

Stock-Based and Other Compens_9

Stock-Based and Other Compensation Plans - Components of Rabbi Trust (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Mutual Fund Investments	$ 38	$ 57
Noble Energy Common Stock (at Fair Value)	5	14
Total Rabbi Trust Assets	43	71
Liability Under Related Deferred Compensation Plan	$ 43	$ 71
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust	267,792	470,030