Noble Energy (NBL) 10-Q 7 Nov 19 2019 Q3 Quarterly report Financial data

Cover Page

Cover Page	9 Months Ended
	Sep. 30, 2019shares
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	001-07964
Entity Registrant Name	NOBLE ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-0785597
Entity Address, Address Line One	1001 Noble Energy Way
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77070
City Area Code	(281)
Local Phone Number	872-3100
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	NBL
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	478,298,006
Entity Central Index Key	0000072207
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Amendment Flag	false

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues
Revenue from Sales	$ 1,119	$ 1,273	$ 3,264	$ 3,789
Total	1,119	1,273	3,264	3,789
Costs and Expenses
Production Expense	297	273	862	886
Depreciation, Depletion and Amortization	583	485	1,619	1,418
General and Administrative	91	107	298	316
Other Operating Expense, Net	61	27	257	107
Gain on Divestitures, Net	0	(193)	0	(859)
Asset Impairments	0	0	0	168
Total	1,128	775	3,332	2,240
Operating (Loss) Income	(9)	498	(68)	1,549
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments	(129)	155	23	483
Interest, Net of Amount Capitalized	67	70	196	216
Other Non-Operating Expense (Income), Net	2	(34)	7	(10)
Total	(60)	191	226	689
Income (Loss) Before Income Taxes	51	307	(294)	860
Income Tax Expense (Benefit)	15	59	(49)	44
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests	36	248	(245)	816
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	19	21	61	58
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$ 17	$ 227	$ (306)	$ 758
Net Income (Loss) Attributable to Noble Energy Common Shareholders per Share
Basic ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.57
Diluted ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.56
Weighted Average Number of Common Shares Outstanding
Basic (in shares)	478	482	478	484
Diluted (in shares)	480	484	478	486
Oil, NGL and Gas Sales
Revenues
Revenue from Sales	$ 1,003	$ 1,136	$ 2,894	$ 3,409
Sales of Purchased Oil and Gas
Revenues
Revenue from Sales	87	72	264	191
Costs and Expenses
Cost of Purchased Oil and Gas	96	76	296	204
Other Revenue
Revenues
Revenue from Sales	$ 29	$ 65	$ 106	$ 189

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents	$ 473	$ 716
Accounts Receivable, Net	677	616
Other Current Assets	277	418
Total Current Assets	1,427	1,750
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	30,445	29,002
Property, Plant and Equipment, Other	1,045	891
Total Property, Plant and Equipment, Gross	31,490	29,893
Accumulated Depreciation, Depletion and Amortization	(12,693)	(11,474)
Total Property, Plant and Equipment, Net	18,797	18,419
Other Noncurrent Assets	1,780	841
Total Assets	22,004	21,010
Current Liabilities
Accounts Payable – Trade	1,395	1,207
Other Current Liabilities	1,190	519
Total Current Liabilities	2,585	1,726
Long-Term Debt	6,941	6,574
Deferred Income Taxes	954	1,061
Other Noncurrent Liabilities	1,338	1,165
Total Liabilities	11,818	10,526
Commitments and Contingencies
Mezzanine Equity
Redeemable Noncontrolling Interest, Net	103	0
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; 522 Million and 520 Million Shares Issued, respectively	5	5
Additional Paid in Capital	8,258	8,203
Accumulated Other Comprehensive Loss	(30)	(32)
Treasury Stock, at Cost; 39 Million Shares	(735)	(730)
Retained Earnings	1,506	1,980
Noble Energy Share of Equity	9,004	9,426
Noncontrolling Interests	1,079	1,058
Total Shareholders' Equity	10,083	10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity	$ 22,004	$ 21,010

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2019	Dec. 31, 2018
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)	522,000,000	520,000,000
Treasury stock, shares (in shares)	39,000,000	39,000,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash Flows From Operating Activities
Net (Loss) Income Including Noncontrolling Interests	$ (245)	$ 816
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,619	1,418
Deferred Income Tax Benefit	(110)	(150)
Loss on Commodity Derivative Instruments	23	483
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	28	(160)
Other Adjustments for Noncash Items Included in Income	115	45
Gain on Divestitures, Net	0	(859)
Asset Impairments	0	168
Firm Transportation Exit Cost	92	0
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable	(13)	114
Increase (Decrease) in Accounts Payable	142	(91)
Other Current Assets and Liabilities, Net	(76)	73
Other Operating Assets and Liabilities, Net	(46)	(81)
Net Cash Provided by Operating Activities	1,529	1,776
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,998)	(2,589)
Acquisitions, Net of Cash Received	0	(653)
Additions to Equity Method Investments	(686)	0
Proceeds from Divestitures, Net	131	1,740
Other	(25)	0
Net Cash Used in Investing Activities	(2,528)	(1,502)
Cash Flows From Financing Activities
Proceeds from Commercial Paper Borrowings, Net	511	0
Dividends Paid, Common Stock	(168)	(156)
Purchase and Retirement of Common Stock	0	(223)
Contributions from Noncontrolling Interest Owners	27	348
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs	97	0
Repayment of Senior Notes	(9)	(384)
Other	(95)	(86)
Net Cash Provided by (Used in) Financing Activities	753	(266)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash	(246)	8
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	719	713
Cash, Cash Equivalents, and Restricted Cash at End of Period	473	721
Revolving Credit Facility
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facilities	50	1,450
Repayment of Revolving Credit Facilities	(50)	(1,680)
Term Loan Facility
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facilities	400	500
Noble Midstream Services Revolving Credit Facility | Revolving Credit Facility
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facilities	655	690
Repayment of Revolving Credit Facilities	$ (665)	$ (725)

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
Balance at Beginning of Period at Dec. 31, 2017	$ 10,619	$ 5	$ 8,438	$ (30)	$ (725)	$ 2,248	$ 683
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	574					554	20
Stock-based Compensation	17		17
Dividends	(48)					(48)
Purchase and Retirement of Common Stock	(67)		(67)
Clayton Williams Energy Acquisition	(25)		(25)
Distributions to Noncontrolling Interest Owners	(11)						(11)
Contributions from Noncontrolling Interest Owners	331						331
Other	(3)			1	(6)		2
Balance at End of Period at Mar. 31, 2018	11,387	5	8,363	(29)	(731)	2,754	1,025
Balance at Beginning of Period at Dec. 31, 2017	10,619	5	8,438	(30)	(725)	2,248	683
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	816
Balance at End of Period at Sep. 30, 2018	11,394	5	8,249	(27)	(731)	2,850	1,048
Balance at Beginning of Period at Mar. 31, 2018	11,387	5	8,363	(29)	(731)	2,754	1,025
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(6)					(23)	17
Stock-based Compensation	29		29
Dividends	(54)					(54)
Purchase and Retirement of Common Stock	(63)		(63)
Distributions to Noncontrolling Interest Owners	(11)						(11)
Other	(1)			1			(2)
Balance at End of Period at Jun. 30, 2018	11,281	5	8,329	(28)	(731)	2,677	1,029
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	248					227	21
Stock-based Compensation	17		17
Dividends	(54)					(54)
Purchase and Retirement of Common Stock	(103)		(103)
Distributions to Noncontrolling Interest Owners	(13)						(13)
Contributions from Noncontrolling Interest Owners	17						17
Other	1		6	1			(6)
Balance at End of Period at Sep. 30, 2018	11,394	5	8,249	(27)	(731)	2,850	1,048
Balance at Beginning of Period at Dec. 31, 2018	10,484	5	8,203	(32)	(730)	1,980	1,058
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(289)					(313)	24
Stock-based Compensation	14		14
Dividends	(53)					(53)
Distributions to Noncontrolling Interest Owners	(17)						(17)
Contributions from Noncontrolling Interest Owners	10						10
Other	(6)		2		(5)		(3)
Balance at End of Period at Mar. 31, 2019	10,143	5	8,219	(32)	(735)	1,614	1,072
Balance at Beginning of Period at Dec. 31, 2018	10,484	5	8,203	(32)	(730)	1,980	1,058
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(245)
Balance at End of Period at Sep. 30, 2019	10,083	5	8,258	(30)	(735)	1,506	1,079
Balance at Beginning of Period at Mar. 31, 2019	10,143	5	8,219	(32)	(735)	1,614	1,072
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	8					(10)	18
Stock-based Compensation	21		21
Dividends	(58)					(58)
Distributions to Noncontrolling Interest Owners	(19)						(19)
Contributions from Noncontrolling Interest Owners	11						11
Other	(2)		4	1			(7)
Balance at End of Period at Jun. 30, 2019	10,104	5	8,244	(31)	(735)	1,546	1,075
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	36					17	19
Stock-based Compensation	16		16
Dividends	(57)					(57)
Distributions to Noncontrolling Interest Owners	(19)						(19)
Contributions from Noncontrolling Interest Owners	6						6
Other	(3)		(2)	1			(2)
Balance at End of Period at Sep. 30, 2019	$ 10,083	$ 5	$ 8,258	$ (30)	$ (735)	$ 1,506	$ 1,079

Consolidated Statements of Sh_2

Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.12	$ 0.12	$ 0.11	$ 0.11	$ 0.11	$ 0.10

Organization and Nature of Oper

Organization and Nature of Operations	9 Months Ended
	Sep. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Note 1. Organization and Nature of Operations Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus areas being the DJ and Delaware Basins.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Note 2. Basis of Presentation Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 2018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018 . Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the minimum lease payments. As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make certain estimates and judgments regarding the lease term and lease payments, noted below. Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option. Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use. Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments. Revenue Recognition We recognize revenue at an amount that reflects the consideration we expect to be entitled to 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 (ASC 606). Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of September 30, 2019 , for those agreements. Our actual future sales volumes may exceed future minimum volume commitments. (millions) Remainder of 2019 2020 Total Natural Gas Revenues (1) $ 36 $ 199 $ 235 (1) The remaining performance obligations are estimated using the contractual base or floor price provision in effect. Future revenues under these contracts will vary from the amounts above due to components of variable consideration exceeding the contractual base or floor price provision. Redeemable Noncontrolling Interest In March 2019 , Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to fund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the commitment, with associated offering costs of $3 million , and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return. As GIP’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of equity on the consolidated balance sheet and, therefore, is reported as mezzanine equity. In addition, because the preferred equity was issued by a subsidiary of Noble Midstream Partners and is held by a third party, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to the earliest redemption date of the preferred equity. The accretion is offset against additional paid in capital. See Note 4. Acquisitions and Divestitures and Note 13. Fair Value Measurements and Disclosures . Recently Issued Accounting Standards Financial Instruments: Credit Losses In June 2016, the Financial Accounting Standards Board (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 current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements. Recently Adopted Accounting Standards Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained. The new standard provided a number of optional practical expedients. We elected: • the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs; • the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and • the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class). We adopted ASC 842 on January 1, 2019 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million , respectively, primarily related to operating leases. The $5 million difference between these amounts was recorded as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases . 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 and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements. 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 used the prospective method to early adopt this ASU in second quarter 2019, which did not have a material impact on our financial statements. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2019 2018 2019 2018 Other Revenue Income from Equity Method Investments and Other $ 10 $ 44 $ 43 $ 140 Midstream Services Revenues – Third Party 19 21 63 49 Total $ 29 $ 65 $ 106 $ 189 Production Expense Lease Operating Expense $ 132 $ 124 $ 405 $ 411 Production and Ad Valorem Taxes 52 47 142 151 Gathering, Transportation and Processing Expense 108 97 306 292 Other Royalty Expense 5 5 9 32 Total $ 297 $ 273 $ 862 $ 886 Other Operating Expense, Net Exploration Expense $ 25 $ 25 $ 82 $ 89 Marketing Expense 7 11 26 21 Firm Transportation Exit Cost — — 92 — Other, Net 29 (9 ) 57 (3 ) Total $ 61 $ 27 $ 257 $ 107 Balance Sheet Information Other balance sheet information is as follows: (millions) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 405 $ 383 Joint Interest Billings 177 137 Other 103 111 Allowance for Doubtful Accounts (8 ) (15 ) Total $ 677 $ 616 Other Current Assets Commodity Derivative Assets $ 90 $ 180 Inventories, Materials and Supplies 74 55 Assets Held for Sale (1) — 133 Prepaid Expenses and Other Current Assets 113 50 Total $ 277 $ 418 Other Noncurrent Assets Equity Method Investments (2) $ 959 $ 286 Operating Lease Right-of-Use Assets (3) 275 — Customer-Related Intangible Assets, Net (4) 286 310 Goodwill (4) 110 110 Other Assets, Noncurrent 150 135 Total $ 1,780 $ 841 Other Current Liabilities Production and Ad Valorem Taxes $ 147 $ 103 Asset Retirement Obligations 89 118 Interest Payable 87 66 Operating Lease Liabilities (3) 97 — Commercial Paper Borrowings 511 — Other Liabilities, Current 259 232 Total $ 1,190 $ 519 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 148 $ 147 Asset Retirement Obligations 699 762 Operating Lease Liabilities (3) 209 — Firm Transportation Exit Cost Accrual (5) 133 67 Other Liabilities, Noncurrent 149 189 Total $ 1,338 $ 1,165 (1) Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures . (2) See Note 4. Acquisitions and Divestitures . (3) Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases . (4) Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million , respectively. See Note 4. Acquisitions and Divestitures . (5) See Note 9. Exit Cost – Transportation Commitments . Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: Nine Months Ended September 30, (millions) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 473 $ 720 Restricted Cash at End of Period — 1 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 473 $ 721

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2019
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 (Canada, New Ventures and Colombia); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners 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 midstream projects. The chief operating decision maker analyzes income before income taxes to assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our operating and financial performance across periods. Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, are recorded at the Corporate level. Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Three Months Ended September 30, 2019 Crude Oil Sales $ 724 $ 645 $ 1 $ 78 $ — $ — $ — $ — NGL Sales 78 78 — — — — — — Natural Gas Sales 201 79 118 4 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,003 802 119 82 — — — — Sales of Purchased Oil and Gas 87 22 — — — 47 — 18 Income (Loss) from Equity Method Investments and Other 10 1 — 14 — (5 ) — — Midstream Services Revenues – Third Party 19 — — — — 19 — — Intersegment Revenues — — — — — 125 (125 ) — Total Revenues 1,119 825 119 96 — 186 (125 ) 18 Lease Operating Expense 132 111 7 22 — 1 (9 ) — Production and Ad Valorem Taxes 52 51 — — — 1 — — Gathering, Transportation and Processing Expense 108 173 1 — — 5 (71 ) — Other Royalty Expense 5 5 — — — — — — Total Production Expense 297 340 8 22 — 7 (80 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Depreciation, Depletion and Amortization 583 505 17 21 1 26 (8 ) 21 Cost of Purchased Oil and Gas 96 17 — — — 46 — 33 Gain on Commodity Derivative Instruments (129 ) (123 ) — (6 ) — — — — Income (Loss) Before Income Taxes 51 92 74 56 (17 ) 83 (23 ) (214 ) Additions to Long-Lived Assets, Excluding Acquisitions 595 377 129 46 2 56 (26 ) 11 Additions to Equity Method Investments 271 — 185 — — 86 — — Three Months Ended September 30, 2018 Crude Oil Sales $ 744 $ 655 $ 2 $ 87 $ — $ — $ — $ — NGL Sales 166 166 — — — — — — Natural Gas Sales 226 98 122 6 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,136 919 124 93 — — — — Sales of Purchased Oil and Gas 72 — — — — 46 — 26 Income from Equity Method Investments and Other 44 — — 34 — 10 — — Midstream Services Revenues – Third Party 21 — — — — 21 — — Intersegment Revenues — — — — — 91 (91 ) — Total Revenues 1,273 919 124 127 — 168 (91 ) 26 Lease Operating Expense 124 114 7 15 — — (12 ) — Production and Ad Valorem Taxes 47 46 — — — 1 — — Gathering, Transportation and Processing Expense 97 129 — — — 28 (60 ) — Other Royalty Expense 5 5 — — — — — — Total Production Expense 273 294 7 15 — 29 (72 ) — Depreciation, Depletion and Amortization 485 414 16 25 1 24 (5 ) 10 (Gain) Loss on Divestitures, Net (193 ) 5 — — — (198 ) — — Cost of Purchased Oil and Gas 76 — — — — 44 — 32 Loss on Commodity Derivative Instruments 155 140 — 15 — — — — Income (Loss) Before Income Taxes 307 31 143 68 (17 ) 268 (16 ) (170 ) Additions to Long-Lived Assets, Excluding Acquisitions 768 535 170 4 1 82 (22 ) (2 ) Nine Months Ended September 30, 2019 Crude Oil Sales $ 2,024 $ 1,807 $ 4 $ 213 $ — $ — $ — $ — NGL Sales 258 258 — — — — — — Natural Gas Sales 612 259 340 13 — — — — Total Crude Oil, NGL and Natural Gas Sales 2,894 2,324 344 226 — — — — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Sales of Purchased Oil and Gas 264 64 — — — 132 — 68 Income (Loss) from Equity Method Investments and Other 43 2 — 46 — (5 ) — — Midstream Services Revenues – Third Party 63 — — — — 63 — — Intersegment Revenues — — — — — 322 (322 ) — Total Revenues 3,264 2,390 344 272 — 512 (322 ) 68 Lease Operating Expense 405 350 26 56 — 3 (30 ) — Production and Ad Valorem Taxes 142 138 — — — 4 — — Gathering, Transportation and Processing Expense 306 439 1 — — 65 (199 ) — Other Royalty Expense 9 9 — — — — — — Total Production Expense 862 936 27 56 — 72 (229 ) — Depreciation, Depletion and Amortization 1,619 1,401 50 60 1 77 (21 ) 51 Cost of Purchased Oil and Gas 296 59 — — — 125 — 112 Firm Transportation Exit Cost 92 — — — — — — 92 Loss on Commodity Derivative Instruments 23 7 — 16 — — — — (Loss) Income Before Income Taxes (294 ) (85 ) 223 126 (48 ) 202 (52 ) (660 ) Additions to Long-Lived Assets, Excluding Acquisitions 1,954 1,367 380 64 14 174 (74 ) 29 Additions to Equity Method Investments 686 — 185 — — 501 — — Nine Months Ended September 30, 2018 Crude Oil Sales $ 2,266 $ 1,972 $ 6 $ 288 $ — $ — $ — $ — NGL Sales 449 449 — — — — — — Natural Gas Sales 694 316 362 16 — — — — Total Crude Oil, NGL and Natural Gas Sales 3,409 2,737 368 304 — — — — Sales of Purchased Oil and Gas 191 — — — — 110 — 81 Income from Equity Method Investments and Other 140 — — 105 — 35 — — Midstream Services Revenues – Third Party 49 — — — — 49 — — Intersegment Revenues — — — — — 257 (257 ) — Total Revenues 3,789 2,737 368 409 — 451 (257 ) 81 Lease Operating Expense 411 354 19 56 — — (18 ) — Production and Ad Valorem Taxes 151 147 — — — 4 — — Gathering, Transportation and Processing Expense 292 389 — — — 71 (168 ) — Other Royalty Expense 32 32 — — — — — — Total Production Expense 886 922 19 56 — 75 (186 ) — Depreciation, Depletion and Amortization 1,418 1,214 44 77 1 62 (13 ) 33 Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate (Gain) Loss on Divestitures, Net (859 ) 20 (376 ) — — (503 ) — — Asset Impairments 168 168 — — — — — — Cost of Purchased Oil and Gas 204 — — — — 106 — 98 Loss on Commodity Derivative Instruments 483 400 — 83 — — — — Income (Loss) Before Income Taxes 860 (94 ) 678 180 (44 ) 690 (52 ) (498 ) Additions to Long-Lived Assets, Excluding Acquisitions 2,608 1,630 533 9 3 479 (72 ) 26 September 30, 2019 Property, Plant and Equipment, Net $ 18,797 $ 13,170 $ 3,001 $ 801 $ 39 $ 1,682 $ (198 ) $ 302 December 31, 2018 Property, Plant and Equipment, Net $ 18,419 $ 13,044 $ 2,630 $ 805 $ 37 $ 1,742 $ (145 ) $ 306 (1) The 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.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2019
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions and Divestitures	Note 4. Acquisitions and Divestitures We maintain an ongoing portfolio management program and have engaged in various transactions over recent years. 2019 Asset Transactions Eastern Mediterranean Investment During third quarter 2019, we invested $185 million for a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.) in support of its planned acquisition of an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s planned equity acquisition of EMG, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of approximately 10% , net, in EMG. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers and support delivery of natural gas from our producing fields offshore Israel into Egypt. Divestiture of Reeves County Assets In February 2019, we closed the sale of certain proved and unproved non-core acreage in the Delaware Basin totaling approximately 13,000 net acres in Reeves County, Texas. We received cash consideration of approximately $131 million , recognizing no gain or loss on the sale. EPIC Pipeline Investments In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-Grade pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline. Both pipelines will transport production from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million and Noble Midstream Partners has since made additional capital contributions of $ 46 million and $ 168 million to EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the equity method. Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC to form a 50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. For the first nine months of 2019 , Noble Midstream Partners has made capital contributions of $ 53 million for construction of the pipeline. This investment is accounted for using the equity method. 2018 Asset Transactions Divestiture of Gulf of Mexico Assets In February 2018, we announced plans to sell our Gulf of Mexico assets for cash consideration of $ 480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As of March 31, 2018, we reduced the net book value of the Gulf of Mexico assets to $480 million . In addition, we retained certain transaction related obligations approximating $92 million which were subsequently settled upon closing. During first quarter 2018, we recorded impairment expense of $ 168 million associated with these assets held for sale. The transaction closed in second quarter 2018. We received net proceeds of $383 million and recorded a loss of $24 million . Divestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd., a publicly traded entity on the Tel Aviv Stock Exchange (Tamar Petroleum, TASE: TMRP). Total consideration included cash of $484 million and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million . 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 and tax expense of $86 million . In October 2018, we sold our shares in Tamar Petroleum for pre-tax proceeds of $163 million , net of transaction expenses. The sale was in accordance with the Israel Natural Gas Framework and completed our obligation to reduce 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. We received proceeds of $60 million , recognizing no gain or loss on the sale. 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 $308 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 second quarter 2018, we sold 7.5 million common units, receiving net proceeds of $135 million , net of underwriting fees, and recognized a gain of $109 million . During third quarter 2018, we sold the remaining 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners, receiving proceeds net of underwriting fees of approximately $248 million , and recognized a gain of $198 million . Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in the Greeley Crescent area of the DJ Basin, receiving proceeds of $64 million , resulting in no gain or loss on the sale. Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners acquired a 54.4% interest 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 Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owns a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and Black Diamond is consolidated as a VIE. We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on acquisition date fair values, and we recognized goodwill for the amount of the purchase price exceeding the fair values of the identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	9 Months Ended
	Sep. 30, 2019
Extractive Industries [Abstract]
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs	Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs Capitalized Exploratory Well Costs There were no significant changes to our capitalized exploratory well costs during the period. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions, except number of projects) September 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 15 $ 6 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 354 348 Capitalized Exploratory Well Costs, End of Period $ 369 $ 354 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 7 Undeveloped Leasehold Costs Changes in undeveloped leasehold costs are as follows: (millions) Nine Months Ended September 30, 2019 Undeveloped Leasehold Costs, Beginning of Period $ 2,306 Additions to Undeveloped Leasehold Costs 63 Transfers to Proved Properties (20 ) Undeveloped Leasehold Costs, End of Period $ 2,349 As of September 30, 2019 , undeveloped leasehold costs included $2.1 billion, $100 million, $76 million, and $59 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on the acreage. Other costs pertain to acreage that is being held by production.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Nine Months Ended September 30, (millions) 2019 2018 Asset Retirement Obligations, Beginning Balance $ 880 $ 875 Liabilities Incurred 17 16 Liabilities Settled (82 ) (309 ) Revisions of Estimates (60 ) 67 Accretion Expense 33 25 Asset Retirement Obligations, Ending Balance $ 788 $ 674 Nine Months Ended September 30, 2019 Liabilities settled relate primarily to abandonment of US onshore properties, principally in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates relate primarily to a decrease of $73 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells, partially offset by acceleration of timing estimates of $13 million for wells offshore Israel. Nine Months Ended September 30, 2018 Liabilities settled include $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $69 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily to increases in cost and timing of estimates of $84 million for US onshore, primarily in the DJ Basin, partially offset by decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean.

Debt

Debt	9 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Debt	Note 7. Debt Debt consists of the following: September 30, 2019 December 31, 2018 (millions, except percentages) Debt Interest Rate Debt Interest Rate Noble Energy, Excluding Noble Midstream Partners Revolving Credit Facility, due March 9, 2023 $ — — % $ — — % Commercial Paper Borrowings 511 (1 ) — — % Senior Notes and Debentures 5,884 (2 ) 5,892 (2 ) Finance Lease Obligations 206 — % 223 — % Total Noble Energy Debt, Excluding Noble Midstream Partners Debt 6,601 6,115 Noble Midstream Partners Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3) 50 3.45 % 60 3.67 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 3.17 % 500 3.42 % Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 400 3.05 % — — % Total Noble Midstream Partners Debt 950 560 Total Debt 7,551 6,675 Net Unamortized Discounts and Debt Issuance Costs (57 ) (60 ) Total Debt, Net of Unamortized Discounts and Debt Issuance Costs 7,494 6,615 Less Amounts Due Within One Year Commercial Paper Borrowings (511 ) — Finance Lease Obligations (42 ) (41 ) Long-Term Debt Due After One Year $ 6,941 $ 6,574 (1) As of September 30, 2019 , the weighted average interest rate for outstanding commercial paper was 2.63% . (2) As of September 30, 2019 and December 31, 2018 , the senior notes and debentures had weighted average interest rates of 5.00% and 5.01% , respectively. (3) As of September 30, 2019 and December 31, 2018 , the Noble Midstream Services Revolving Credit Facility had $ 800 million of capacity, of which $ 750 million and $ 740 million were available for borrowing, respectively. Commercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are either issued at a discounted price relative to the principal face value or bear interest at varying interest rates on a fixed or floating basis. Such discount prices or interest rates are dependent on market conditions and ratings assigned to the commercial paper program by credit agencies at the time of commercial paper issuance. At September 30, 2019 , outstanding commercial paper borrowings totaled $511 million , leaving approximately $ 3.5 billion available for borrowing under our $4.0 billion Revolving Credit Facility. Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Term Loan Credit Facility), that permits aggregate borrowings of up to $ 400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Subsequent Event On October 1, 2019, we issued $500 million of 3.25% notes due October 15, 2029 and $500 million of 4.20% notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations. Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures .

Leases

Leases	9 Months Ended
	Sep. 30, 2019
Leases [Abstract]
Leases	Note 8. Leases In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest. Balance Sheet Information ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location September 30, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 275 Finance Leases (2) Total Property, Plant and Equipment, Net 172 Total ROU Assets $ 447 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 97 Finance Leases Other Current Liabilities 42 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 209 Finance Leases Long-Term Debt 164 Total Lease Liabilities $ 512 (1) Operating lease ROU assets primarily include office space of $117 million , compressors of $93 million , and drilling rigs of $29 million . (2) Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million , both net of accumulated amortization. Statement of Operations Information The components of lease cost are as follows: (millions) Statement of Operations Location Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost (1) $ 30 $ 81 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 10 27 Interest Expense Interest, Net of Amount Capitalized 3 10 Short-term Lease Cost (2) (1) 88 357 Sublease Income General and Administrative (1 ) (3 ) Total Lease Cost $ 130 $ 472 (1) Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and, therefore, are included as part of oil and gas properties on our consolidated balance sheets. (2) Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. Cash Flow Information Supplemental cash flow information is as follows: Nine Months Ended September 30, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 50 $ 9 Investing Cash Flows 27 — Financing Cash Flows — 31 Non-Cash Activities ROU Assets Obtained in Exchange for Lease Liabilities (1) 93 15 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation . Maturity of Lease Liabilities Maturities of lease liabilities as of September 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 28 $ 13 $ 41 2020 100 49 149 2021 61 35 96 2022 44 25 69 2023 29 22 51 2024 and Thereafter 85 106 191 Total Lease Liabilities, Undiscounted 347 250 597 Less: Imputed Interest 41 44 85 Total Lease Liabilities (1) $ 306 $ 206 $ 512 (1) Includes the current portions of $ 97 million and $ 42 million for operating and finance leases, respectively. Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787 Other Information Other information related to our leases as of September 30, 2019 is as follows: Operating Leases Finance Leases Weighted-Average Remaining Lease Term 5.7 years 7.7 years Weighted-Average Discount Rate 4.40 % 5.02 %
Leases	Note 8. Leases In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest. Balance Sheet Information ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location September 30, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 275 Finance Leases (2) Total Property, Plant and Equipment, Net 172 Total ROU Assets $ 447 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 97 Finance Leases Other Current Liabilities 42 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 209 Finance Leases Long-Term Debt 164 Total Lease Liabilities $ 512 (1) Operating lease ROU assets primarily include office space of $117 million , compressors of $93 million , and drilling rigs of $29 million . (2) Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million , both net of accumulated amortization. Statement of Operations Information The components of lease cost are as follows: (millions) Statement of Operations Location Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost (1) $ 30 $ 81 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 10 27 Interest Expense Interest, Net of Amount Capitalized 3 10 Short-term Lease Cost (2) (1) 88 357 Sublease Income General and Administrative (1 ) (3 ) Total Lease Cost $ 130 $ 472 (1) Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and, therefore, are included as part of oil and gas properties on our consolidated balance sheets. (2) Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. Cash Flow Information Supplemental cash flow information is as follows: Nine Months Ended September 30, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 50 $ 9 Investing Cash Flows 27 — Financing Cash Flows — 31 Non-Cash Activities ROU Assets Obtained in Exchange for Lease Liabilities (1) 93 15 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation . Maturity of Lease Liabilities Maturities of lease liabilities as of September 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 28 $ 13 $ 41 2020 100 49 149 2021 61 35 96 2022 44 25 69 2023 29 22 51 2024 and Thereafter 85 106 191 Total Lease Liabilities, Undiscounted 347 250 597 Less: Imputed Interest 41 44 85 Total Lease Liabilities (1) $ 306 $ 206 $ 512 (1) Includes the current portions of $ 97 million and $ 42 million for operating and finance leases, respectively. Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787 Other Information Other information related to our leases as of September 30, 2019 is as follows: Operating Leases Finance Leases Weighted-Average Remaining Lease Term 5.7 years 7.7 years Weighted-Average Discount Rate 4.40 % 5.02 %

Exit Costs - Transportation Com

Exit Costs - Transportation Commitments	9 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Exit Costs - Transportation Commitments	Note 9. Exit Cost – Transportation Commitments In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of September 30, 2019 , our undiscounted financial commitment for the remaining obligations under these agreements was approximately $ 1.0 billion , which excludes the impact of future mitigation activities. Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations. Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign remaining capacity to a third-party effective January 1, 2021, extending through the end of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million , undiscounted. As a result of the assignment, we recorded firm transportation exit cost of $92 million, discounted, related to future commitments to the third party. We will continue efforts to mitigate the remaining component of these transportation agreements through 2020. Exit Costs Reconciliation of accrued costs at September 30, 2019 is as follows: Nine Months Ended September 30, (millions) 2019 2018 Balance at Beginning of Period (1) $ 80 $ 90 Firm Transportation Exit Cost Accrual 92 — Payments, Net of Accretion (6 ) (9 ) Balance at End of Period 166 81 Less: Current Portion Included in Other Current Liabilities 33 12 Long-term Portion Included in Other Noncurrent Liabilities $ 133 $ 69 (1) Amounts include the current portion of $13 million

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 10. 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 Clean Water Act Referral Notice In September 2018, we received a letter from the Department of Justice (DOJ) requesting an opportunity to discuss settlement of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 11. Income Taxes Income tax expense (benefit) consists of the following: Three Months Ended September 30, Nine Months Ended September 30, (millions, except percentages) 2019 2018 2019 2018 Current $ 24 $ 45 $ 61 $ 194 Deferred (9 ) 14 (110 ) (150 ) Total Income Tax Expense (Benefit) $ 15 $ 59 $ (49 ) $ 44 Effective Tax Rate 29.4 % 19.2 % 16.7 % 5.1 % Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ETR to current period earnings or loss before tax, which can produce interim ETR fluctuations. The ETR for the nine months ended September 30, 2019 varied as compared with 2018 , primarily due to a $145 million discrete tax benefit recorded in 2018 as a result of the intent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, current tax expense for the nine months ended September 30, 2018 includes foreign taxes related to a gain on the 2018 divestiture of a 7.5% interest in the Tamar field. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014 , Israel – 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea – 2013 .

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 12. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We enter into crude oil and natural gas price hedging arrangements to mitigate effects of commodity price volatility and enhance the predictability of cash flows for a portion of our crude oil and natural gas production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. Unsettled Commodity Derivative Instruments As of September 30, 2019 , the following crude oil derivative contracts were outstanding: 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 35,000 $ — $ 59.04 $ — $ — $ — 2019 Three-Way Collars NYMEX WTI 33,000 — — 49.35 59.35 72.25 2019 Sold Calls (1) NYMEX WTI 4,000 — 60.00 — — — 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 (2) 27,000 (3.23 ) — — — — 2020 Swaption NYMEX WTI 12,000 — 59.73 — — — 2020 Sold Calls (1) NYMEX WTI 8,000 — 65.59 — — — 2020 Swaps NYMEX WTI 28,000 — 58.09 — — — 2020 Three-Way Collars NYMEX WTI 30,000 — — 48.33 57.87 64.27 2020 Basis Swaps (2) 15,000 (5.01 ) — — — — (1) We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. (2) We entered into crude oil basis swap contracts to establish a fixed amount for 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 September 30, 2019 , the following natural gas derivative contracts were outstanding: 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 2019 Three-Way Collars NYMEX HH 104,000 $ — $ — $ 2.25 $ 2.65 $ 2.95 2019 Swaps NYMEX HH 46,000 — 3.00 — — — 2019 Basis Swaps CIG (1) 123,500 (0.64 ) — — — — 2019 Basis Swaps WAHA (1) 47,500 (1.28 ) — — — — 2020 Swaps NYMEX HH 90,000 — 2.60 — — — 2020 Sold Puts (2) NYMEX HH 90,000 — — 2.15 — — 2020 Swaption NYMEX HH 90,000 — 2.60 — — — 2020 Basis Swaps CIG (1) 54,000 (0.61 ) — — — — 2020 Basis Swaps WAHA (1) 49,500 (1.05 ) — — — — 2021 Basis Swaps WAHA (1) 14,000 (0.60 ) — — — — (1) We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing 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. (2) We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts. Fair Value Amounts The fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions): Asset Derivative Instruments Liability Derivative Instruments Balance Sheet Location September 30, 2019 December 31, 2018 Balance Sheet Location September 30, 2019 December 31, 2018 Other Current Assets $ 90 $ 180 Other Current Liabilities $ 10 $ 1 Other Noncurrent Assets 25 — Other Noncurrent Liabilities 3 26 Total $ 115 $ 180 $ 13 $ 27 See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) was as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2019 2018 2019 2018 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (6 ) $ 68 $ (8 ) $ 164 Natural Gas (7 ) (1 ) (20 ) (4 ) Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments (13 ) 67 (28 ) 160 Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (115 ) 85 54 316 Natural Gas (1 ) 3 (3 ) 7 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (116 ) 88 51 323 (Gain) Loss on Commodity Derivative Instruments Crude Oil (121 ) 153 46 480 Natural Gas (8 ) 2 (23 ) 3 Total (Gain) Loss on Commodity Derivative Instruments $ (129 ) $ 155 $ 23 $ 483

Fair Value Measurements and Dis

Fair Value Measurements and Disclosures	9 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements and Disclosures	Note 13. Fair Value Measurements and Disclosures Assets and Liabilities Measured at Fair Value on a Recurring Basis Cash and 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. Fair values are based on quoted market prices for identical assets. Commodity Derivative Instruments We estimate the fair values of our derivative instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the 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 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 values of put options sold and contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. See Note 12. Derivative Instruments and Hedging Activities . Deferred Compensation Liability Fair 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 at the end of each reporting period. Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Adjustment (1) Fair Value Measurement September 30, 2019 Financial Assets: Mutual Fund Investments $ 42 $ — $ — $ — $ 42 Commodity Derivative Instruments — 155 — (40 ) 115 Financial Liabilities: Commodity Derivative Instruments — (53 ) — 40 (13 ) Portion of Deferred Compensation Liability Measured at Fair Value (48 ) — — — (48 ) Stock Based Compensation Liability Measured at Fair Value (3 ) — — — (3 ) 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 ) (1) Amount represents the impact of netting provisions within our master agreements allowing us to net cash settle asset and liability positions with the same counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Firm Transportation Exit Cost Accrual In January 2019, we recorded a firm transportation exit cost liability at fair value of $92 million, representing the discounted present value of our remaining obligation under a permanent pipeline capacity assignment in the Marcellus Shale. See Note 9. Exit Cost – Transportation Commitments . Redeemable Noncontrolling Interest In March 2019, we recorded redeemable noncontrolling interest associated with the issuance to GIP of preferred equity in Noble Midstream Partners at fair value of $97 million , including issuance date proceeds of $100 million netted with associated issuance costs of $3 million . See Note 2. Basis of Presentation . Additional Fair Value Disclosures Debt The fair value of fixed-rate, public debt is estimated based on published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy. Our non-public debt, including our Revolving Credit Facility, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair values to be Level 2 measurements on the fair value hierarchy. See Note 7. Debt . Fair value information regarding our debt is as follows: September 30, 2019 December 31, 2018 (millions) Carrying Amount Fair Value (1) Carrying Amount Fair Value Debt (2) $ 7,345 $ 7,963 $ 6,452 $ 6,121 (1) As of September 30, 2019 , the difference between the carrying amount and the fair value is primarily due to low US treasury rates. (2) Represents total debt excluding finance lease obligations. See Note 7. Debt .

Net Income (Loss) Per Share Att

Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders	9 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders	Note 14. Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders Noble Energy's basic income (loss) per share of common stock is computed by dividing net income (loss) attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted income (loss) per share: Three Months Ended September 30, Nine Months Ended September 30, (millions, except per share amounts) 2019 2018 2019 2018 Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy $ 17 $ 227 $ (306 ) $ 758 Weighted Average Number of Shares Outstanding, Basic (1) 478 482 478 484 Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust 2 2 — 2 Weighted Average Number of Shares Outstanding, Diluted 480 484 478 486 Income (Loss) Per Share, Basic $ 0.04 $ 0.47 $ (0.64 ) $ 1.57 Income (Loss) Per Share, Diluted $ 0.04 $ 0.47 $ (0.64 ) $ 1.56 Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 13 15 14 (1) Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program.

Basis of Presentation (Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Presentation	Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 2018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018 .
Consolidation	Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.
Estimates	Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
Leases	Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the minimum lease payments. As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make certain estimates and judgments regarding the lease term and lease payments, noted below. Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option. Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use. Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments.
Revenue Recognition	Revenue Recognition We recognize revenue at an amount that reflects the consideration we expect to be entitled to 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 (ASC 606).
Redeemable Noncontrolling Interest	Redeemable Noncontrolling Interest In March 2019 , Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to fund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the commitment, with associated offering costs of $3 million , and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return.
Recently Issued and Recently Adopted Accounting Standards	Recently Issued Accounting Standards Financial Instruments: Credit Losses In June 2016, the Financial Accounting Standards Board (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 current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements. Recently Adopted Accounting Standards Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained. The new standard provided a number of optional practical expedients. We elected: • the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs; • the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and • the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class). We adopted ASC 842 on January 1, 2019 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million , respectively, primarily related to operating leases. The $5 million difference between these amounts was recorded as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases . 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 and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements. 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

Basis of Presentation (Tables)

Basis of Presentation (Tables)	9 Months Ended
	Sep. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table includes estimated revenues, as of September 30, 2019 , for those agreements. Our actual future sales volumes may exceed future minimum volume commitments. (millions) Remainder of 2019 2020 Total Natural Gas Revenues (1) $ 36 $ 199 $ 235 (1)
Statement of Operations Information	Other statements of operations information is as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2019 2018 2019 2018 Other Revenue Income from Equity Method Investments and Other $ 10 $ 44 $ 43 $ 140 Midstream Services Revenues – Third Party 19 21 63 49 Total $ 29 $ 65 $ 106 $ 189 Production Expense Lease Operating Expense $ 132 $ 124 $ 405 $ 411 Production and Ad Valorem Taxes 52 47 142 151 Gathering, Transportation and Processing Expense 108 97 306 292 Other Royalty Expense 5 5 9 32 Total $ 297 $ 273 $ 862 $ 886 Other Operating Expense, Net Exploration Expense $ 25 $ 25 $ 82 $ 89 Marketing Expense 7 11 26 21 Firm Transportation Exit Cost — — 92 — Other, Net 29 (9 ) 57 (3 ) Total $ 61 $ 27 $ 257 $ 107
Balance Sheet Information Table	Other balance sheet information is as follows: (millions) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 405 $ 383 Joint Interest Billings 177 137 Other 103 111 Allowance for Doubtful Accounts (8 ) (15 ) Total $ 677 $ 616 Other Current Assets Commodity Derivative Assets $ 90 $ 180 Inventories, Materials and Supplies 74 55 Assets Held for Sale (1) — 133 Prepaid Expenses and Other Current Assets 113 50 Total $ 277 $ 418 Other Noncurrent Assets Equity Method Investments (2) $ 959 $ 286 Operating Lease Right-of-Use Assets (3) 275 — Customer-Related Intangible Assets, Net (4) 286 310 Goodwill (4) 110 110 Other Assets, Noncurrent 150 135 Total $ 1,780 $ 841 Other Current Liabilities Production and Ad Valorem Taxes $ 147 $ 103 Asset Retirement Obligations 89 118 Interest Payable 87 66 Operating Lease Liabilities (3) 97 — Commercial Paper Borrowings 511 — Other Liabilities, Current 259 232 Total $ 1,190 $ 519 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 148 $ 147 Asset Retirement Obligations 699 762 Operating Lease Liabilities (3) 209 — Firm Transportation Exit Cost Accrual (5) 133 67 Other Liabilities, Noncurrent 149 189 Total $ 1,338 $ 1,165 (1) Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures . (2) See Note 4. Acquisitions and Divestitures . (3) Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases . (4) Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million , respectively. See Note 4. Acquisitions and Divestitures . (5) See Note 9. Exit Cost – Transportation Commitments .
Summary 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: Nine Months Ended September 30, (millions) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 473 $ 720 Restricted Cash at End of Period — 1 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 473 $ 721

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2019
Segment Reporting [Abstract]
Segment Information	Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Three Months Ended September 30, 2019 Crude Oil Sales $ 724 $ 645 $ 1 $ 78 $ — $ — $ — $ — NGL Sales 78 78 — — — — — — Natural Gas Sales 201 79 118 4 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,003 802 119 82 — — — — Sales of Purchased Oil and Gas 87 22 — — — 47 — 18 Income (Loss) from Equity Method Investments and Other 10 1 — 14 — (5 ) — — Midstream Services Revenues – Third Party 19 — — — — 19 — — Intersegment Revenues — — — — — 125 (125 ) — Total Revenues 1,119 825 119 96 — 186 (125 ) 18 Lease Operating Expense 132 111 7 22 — 1 (9 ) — Production and Ad Valorem Taxes 52 51 — — — 1 — — Gathering, Transportation and Processing Expense 108 173 1 — — 5 (71 ) — Other Royalty Expense 5 5 — — — — — — Total Production Expense 297 340 8 22 — 7 (80 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Depreciation, Depletion and Amortization 583 505 17 21 1 26 (8 ) 21 Cost of Purchased Oil and Gas 96 17 — — — 46 — 33 Gain on Commodity Derivative Instruments (129 ) (123 ) — (6 ) — — — — Income (Loss) Before Income Taxes 51 92 74 56 (17 ) 83 (23 ) (214 ) Additions to Long-Lived Assets, Excluding Acquisitions 595 377 129 46 2 56 (26 ) 11 Additions to Equity Method Investments 271 — 185 — — 86 — — Three Months Ended September 30, 2018 Crude Oil Sales $ 744 $ 655 $ 2 $ 87 $ — $ — $ — $ — NGL Sales 166 166 — — — — — — Natural Gas Sales 226 98 122 6 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,136 919 124 93 — — — — Sales of Purchased Oil and Gas 72 — — — — 46 — 26 Income from Equity Method Investments and Other 44 — — 34 — 10 — — Midstream Services Revenues – Third Party 21 — — — — 21 — — Intersegment Revenues — — — — — 91 (91 ) — Total Revenues 1,273 919 124 127 — 168 (91 ) 26 Lease Operating Expense 124 114 7 15 — — (12 ) — Production and Ad Valorem Taxes 47 46 — — — 1 — — Gathering, Transportation and Processing Expense 97 129 — — — 28 (60 ) — Other Royalty Expense 5 5 — — — — — — Total Production Expense 273 294 7 15 — 29 (72 ) — Depreciation, Depletion and Amortization 485 414 16 25 1 24 (5 ) 10 (Gain) Loss on Divestitures, Net (193 ) 5 — — — (198 ) — — Cost of Purchased Oil and Gas 76 — — — — 44 — 32 Loss on Commodity Derivative Instruments 155 140 — 15 — — — — Income (Loss) Before Income Taxes 307 31 143 68 (17 ) 268 (16 ) (170 ) Additions to Long-Lived Assets, Excluding Acquisitions 768 535 170 4 1 82 (22 ) (2 ) Nine Months Ended September 30, 2019 Crude Oil Sales $ 2,024 $ 1,807 $ 4 $ 213 $ — $ — $ — $ — NGL Sales 258 258 — — — — — — Natural Gas Sales 612 259 340 13 — — — — Total Crude Oil, NGL and Natural Gas Sales 2,894 2,324 344 226 — — — — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Sales of Purchased Oil and Gas 264 64 — — — 132 — 68 Income (Loss) from Equity Method Investments and Other 43 2 — 46 — (5 ) — — Midstream Services Revenues – Third Party 63 — — — — 63 — — Intersegment Revenues — — — — — 322 (322 ) — Total Revenues 3,264 2,390 344 272 — 512 (322 ) 68 Lease Operating Expense 405 350 26 56 — 3 (30 ) — Production and Ad Valorem Taxes 142 138 — — — 4 — — Gathering, Transportation and Processing Expense 306 439 1 — — 65 (199 ) — Other Royalty Expense 9 9 — — — — — — Total Production Expense 862 936 27 56 — 72 (229 ) — Depreciation, Depletion and Amortization 1,619 1,401 50 60 1 77 (21 ) 51 Cost of Purchased Oil and Gas 296 59 — — — 125 — 112 Firm Transportation Exit Cost 92 — — — — — — 92 Loss on Commodity Derivative Instruments 23 7 — 16 — — — — (Loss) Income Before Income Taxes (294 ) (85 ) 223 126 (48 ) 202 (52 ) (660 ) Additions to Long-Lived Assets, Excluding Acquisitions 1,954 1,367 380 64 14 174 (74 ) 29 Additions to Equity Method Investments 686 — 185 — — 501 — — Nine Months Ended September 30, 2018 Crude Oil Sales $ 2,266 $ 1,972 $ 6 $ 288 $ — $ — $ — $ — NGL Sales 449 449 — — — — — — Natural Gas Sales 694 316 362 16 — — — — Total Crude Oil, NGL and Natural Gas Sales 3,409 2,737 368 304 — — — — Sales of Purchased Oil and Gas 191 — — — — 110 — 81 Income from Equity Method Investments and Other 140 — — 105 — 35 — — Midstream Services Revenues – Third Party 49 — — — — 49 — — Intersegment Revenues — — — — — 257 (257 ) — Total Revenues 3,789 2,737 368 409 — 451 (257 ) 81 Lease Operating Expense 411 354 19 56 — — (18 ) — Production and Ad Valorem Taxes 151 147 — — — 4 — — Gathering, Transportation and Processing Expense 292 389 — — — 71 (168 ) — Other Royalty Expense 32 32 — — — — — — Total Production Expense 886 922 19 56 — 75 (186 ) — Depreciation, Depletion and Amortization 1,418 1,214 44 77 1 62 (13 ) 33 Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate (Gain) Loss on Divestitures, Net (859 ) 20 (376 ) — — (503 ) — — Asset Impairments 168 168 — — — — — — Cost of Purchased Oil and Gas 204 — — — — 106 — 98 Loss on Commodity Derivative Instruments 483 400 — 83 — — — — Income (Loss) Before Income Taxes 860 (94 ) 678 180 (44 ) 690 (52 ) (498 ) Additions to Long-Lived Assets, Excluding Acquisitions 2,608 1,630 533 9 3 479 (72 ) 26 September 30, 2019 Property, Plant and Equipment, Net $ 18,797 $ 13,170 $ 3,001 $ 801 $ 39 $ 1,682 $ (198 ) $ 302 December 31, 2018 Property, Plant and Equipment, Net $ 18,419 $ 13,044 $ 2,630 $ 805 $ 37 $ 1,742 $ (145 ) $ 306 (1) The 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.

Capitalized Exploratory Well _2

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)	9 Months Ended
	Sep. 30, 2019
Extractive Industries [Abstract]
Aging of Capitalized Well Costs	The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions, except number of projects) September 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 15 $ 6 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 354 348 Capitalized Exploratory Well Costs, End of Period $ 369 $ 354 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 7
Rollforward of Undeveloped Lease Costs	Changes in undeveloped leasehold costs are as follows: (millions) Nine Months Ended September 30, 2019 Undeveloped Leasehold Costs, Beginning of Period $ 2,306 Additions to Undeveloped Leasehold Costs 63 Transfers to Proved Properties (20 ) Undeveloped Leasehold Costs, End of Period $ 2,349

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2019
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in ARO are as follows: Nine Months Ended September 30, (millions) 2019 2018 Asset Retirement Obligations, Beginning Balance $ 880 $ 875 Liabilities Incurred 17 16 Liabilities Settled (82 ) (309 ) Revisions of Estimates (60 ) 67 Accretion Expense 33 25 Asset Retirement Obligations, Ending Balance $ 788 $ 674

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Schedule of Debt	Debt consists of the following: September 30, 2019 December 31, 2018 (millions, except percentages) Debt Interest Rate Debt Interest Rate Noble Energy, Excluding Noble Midstream Partners Revolving Credit Facility, due March 9, 2023 $ — — % $ — — % Commercial Paper Borrowings 511 (1 ) — — % Senior Notes and Debentures 5,884 (2 ) 5,892 (2 ) Finance Lease Obligations 206 — % 223 — % Total Noble Energy Debt, Excluding Noble Midstream Partners Debt 6,601 6,115 Noble Midstream Partners Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3) 50 3.45 % 60 3.67 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 3.17 % 500 3.42 % Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 400 3.05 % — — % Total Noble Midstream Partners Debt 950 560 Total Debt 7,551 6,675 Net Unamortized Discounts and Debt Issuance Costs (57 ) (60 ) Total Debt, Net of Unamortized Discounts and Debt Issuance Costs 7,494 6,615 Less Amounts Due Within One Year Commercial Paper Borrowings (511 ) — Finance Lease Obligations (42 ) (41 ) Long-Term Debt Due After One Year $ 6,941 $ 6,574 (1) As of September 30, 2019 , the weighted average interest rate for outstanding commercial paper was 2.63% . (2) As of September 30, 2019 and December 31, 2018 , the senior notes and debentures had weighted average interest rates of 5.00% and 5.01% , respectively. (3) As of September 30, 2019 and December 31, 2018 , the Noble Midstream Services Revolving Credit Facility had $ 800 million of capacity, of which $ 750 million and $ 740 million were available for borrowing, respectively.

Leases (Tables)

Leases (Tables)	9 Months Ended
	Sep. 30, 2019
Leases [Abstract]
Summary of Operating and Finance Lease	ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location September 30, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 275 Finance Leases (2) Total Property, Plant and Equipment, Net 172 Total ROU Assets $ 447 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 97 Finance Leases Other Current Liabilities 42 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 209 Finance Leases Long-Term Debt 164 Total Lease Liabilities $ 512 (1) Operating lease ROU assets primarily include office space of $117 million , compressors of $93 million , and drilling rigs of $29 million . (2) Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million , both net of accumulated amortization. Other information related to our leases as of September 30, 2019 is as follows: Operating Leases Finance Leases Weighted-Average Remaining Lease Term 5.7 years 7.7 years Weighted-Average Discount Rate 4.40 % 5.02 %
Lease Expense	The components of lease cost are as follows: (millions) Statement of Operations Location Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost (1) $ 30 $ 81 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 10 27 Interest Expense Interest, Net of Amount Capitalized 3 10 Short-term Lease Cost (2) (1) 88 357 Sublease Income General and Administrative (1 ) (3 ) Total Lease Cost $ 130 $ 472 (1) Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and, therefore, are included as part of oil and gas properties on our consolidated balance sheets. (2) Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less.
Supplemental Cash Flow Information	Supplemental cash flow information is as follows: Nine Months Ended September 30, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 50 $ 9 Investing Cash Flows 27 — Financing Cash Flows — 31 Non-Cash Activities ROU Assets Obtained in Exchange for Lease Liabilities (1) 93 15 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation .
Operating Lease Liability Maturity	Maturities of lease liabilities as of September 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 28 $ 13 $ 41 2020 100 49 149 2021 61 35 96 2022 44 25 69 2023 29 22 51 2024 and Thereafter 85 106 191 Total Lease Liabilities, Undiscounted 347 250 597 Less: Imputed Interest 41 44 85 Total Lease Liabilities (1) $ 306 $ 206 $ 512 (1) Includes the current portions of $ 97 million and $ 42
Finance Lease Liability Maturity	Maturities of lease liabilities as of September 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 28 $ 13 $ 41 2020 100 49 149 2021 61 35 96 2022 44 25 69 2023 29 22 51 2024 and Thereafter 85 106 191 Total Lease Liabilities, Undiscounted 347 250 597 Less: Imputed Interest 41 44 85 Total Lease Liabilities (1) $ 306 $ 206 $ 512 (1) Includes the current portions of $ 97 million and $ 42
Schedule of Future Minimum Rental Payments for Operating Leases	Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787
Schedule of Future Minimum Lease Payments for Finance Leases	Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787

Exit Costs - Transportation C_2

Exit Costs - Transportation Commitments (Tables)	9 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Rollforward of Accrued Transportation Commitment	Reconciliation of accrued costs at September 30, 2019 is as follows: Nine Months Ended September 30, (millions) 2019 2018 Balance at Beginning of Period (1) $ 80 $ 90 Firm Transportation Exit Cost Accrual 92 — Payments, Net of Accretion (6 ) (9 ) Balance at End of Period 166 81 Less: Current Portion Included in Other Current Liabilities 33 12 Long-term Portion Included in Other Noncurrent Liabilities $ 133 $ 69 (1) Amounts include the current portion of $13 million which is included in other current liabilities in our consolidated balance sheets.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Income Tax Provision (Benefit)	Income tax expense (benefit) consists of the following: Three Months Ended September 30, Nine Months Ended September 30, (millions, except percentages) 2019 2018 2019 2018 Current $ 24 $ 45 $ 61 $ 194 Deferred (9 ) 14 (110 ) (150 ) Total Income Tax Expense (Benefit) $ 15 $ 59 $ (49 ) $ 44 Effective Tax Rate 29.4 % 19.2 % 16.7 % 5.1 %

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unsettled Derivative Instruments	As of September 30, 2019 , the following crude oil derivative contracts were outstanding: 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 35,000 $ — $ 59.04 $ — $ — $ — 2019 Three-Way Collars NYMEX WTI 33,000 — — 49.35 59.35 72.25 2019 Sold Calls (1) NYMEX WTI 4,000 — 60.00 — — — 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 (2) 27,000 (3.23 ) — — — — 2020 Swaption NYMEX WTI 12,000 — 59.73 — — — 2020 Sold Calls (1) NYMEX WTI 8,000 — 65.59 — — — 2020 Swaps NYMEX WTI 28,000 — 58.09 — — — 2020 Three-Way Collars NYMEX WTI 30,000 — — 48.33 57.87 64.27 2020 Basis Swaps (2) 15,000 (5.01 ) — — — — (1) We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. (2) We entered into crude oil basis swap contracts to establish a fixed amount for 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 September 30, 2019 , the following natural gas derivative contracts were outstanding: 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 2019 Three-Way Collars NYMEX HH 104,000 $ — $ — $ 2.25 $ 2.65 $ 2.95 2019 Swaps NYMEX HH 46,000 — 3.00 — — — 2019 Basis Swaps CIG (1) 123,500 (0.64 ) — — — — 2019 Basis Swaps WAHA (1) 47,500 (1.28 ) — — — — 2020 Swaps NYMEX HH 90,000 — 2.60 — — — 2020 Sold Puts (2) NYMEX HH 90,000 — — 2.15 — — 2020 Swaption NYMEX HH 90,000 — 2.60 — — — 2020 Basis Swaps CIG (1) 54,000 (0.61 ) — — — — 2020 Basis Swaps WAHA (1) 49,500 (1.05 ) — — — — 2021 Basis Swaps WAHA (1) 14,000 (0.60 ) — — — — (1) We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing 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. (2) We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts.
Fair Value of Derivative Instruments	The fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions): Asset Derivative Instruments Liability Derivative Instruments Balance Sheet Location September 30, 2019 December 31, 2018 Balance Sheet Location September 30, 2019 December 31, 2018 Other Current Assets $ 90 $ 180 Other Current Liabilities $ 10 $ 1 Other Noncurrent Assets 25 — Other Noncurrent Liabilities 3 26 Total $ 115 $ 180 $ 13 $ 27
Derivative Instruments, (Gain) Loss	The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) was as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2019 2018 2019 2018 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (6 ) $ 68 $ (8 ) $ 164 Natural Gas (7 ) (1 ) (20 ) (4 ) Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments (13 ) 67 (28 ) 160 Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (115 ) 85 54 316 Natural Gas (1 ) 3 (3 ) 7 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (116 ) 88 51 323 (Gain) Loss on Commodity Derivative Instruments Crude Oil (121 ) 153 46 480 Natural Gas (8 ) 2 (23 ) 3 Total (Gain) Loss on Commodity Derivative Instruments $ (129 ) $ 155 $ 23 $ 483

Fair Value Measurements and D_2

Fair Value Measurements and Disclosures (Tables)	9 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Adjustment (1) Fair Value Measurement September 30, 2019 Financial Assets: Mutual Fund Investments $ 42 $ — $ — $ — $ 42 Commodity Derivative Instruments — 155 — (40 ) 115 Financial Liabilities: Commodity Derivative Instruments — (53 ) — 40 (13 ) Portion of Deferred Compensation Liability Measured at Fair Value (48 ) — — — (48 ) Stock Based Compensation Liability Measured at Fair Value (3 ) — — — (3 ) 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 ) (1) Amount represents the impact of netting provisions within our master agreements allowing us to net cash settle asset and liability positions with the same counterparty.
Additional fair value disclosures	Fair value information regarding our debt is as follows: September 30, 2019 December 31, 2018 (millions) Carrying Amount Fair Value (1) Carrying Amount Fair Value Debt (2) $ 7,345 $ 7,963 $ 6,452 $ 6,121 (1) As of September 30, 2019 , the difference between the carrying amount and the fair value is primarily due to low US treasury rates. (2) Represents total debt excluding finance lease obligations. See Note 7. Debt .

Net Income (Loss) Per Share A_2

Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders (Tables)	9 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Schedule of earnings per share	The following table summarizes the calculation of basic and diluted income (loss) per share: Three Months Ended September 30, Nine Months Ended September 30, (millions, except per share amounts) 2019 2018 2019 2018 Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy $ 17 $ 227 $ (306 ) $ 758 Weighted Average Number of Shares Outstanding, Basic (1) 478 482 478 484 Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust 2 2 — 2 Weighted Average Number of Shares Outstanding, Diluted 480 484 478 486 Income (Loss) Per Share, Basic $ 0.04 $ 0.47 $ (0.64 ) $ 1.57 Income (Loss) Per Share, Diluted $ 0.04 $ 0.47 $ (0.64 ) $ 1.56 Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 13 15 14 (1) Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program.

Basis of Presentation - Perform

Basis of Presentation - Performance Obligation, Expected Timing (Details) $ in Millions	Sep. 30, 2019USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Natural Gas Revenues	$ 235
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-10-01
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Natural Gas Revenues	$ 36
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected timing	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Natural Gas Revenues	$ 199
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected timing	1 year

Basis of Presentation - Narrati

Basis of Presentation - Narrative (Details) - USD ($) $ in Millions	Jan. 01, 2019	Mar. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Goodwill			$ 110		$ 110
ROU Assets			275		$ 0
Lease liabilities			306
Proceeds from issuance of preferred equity			97	$ 0
ASU 2016-02
Finite-Lived Intangible Assets [Line Items]
ROU Assets	$ 282
Lease liabilities	287
Deferred tax impact	$ 5
Noble Midstream
Finite-Lived Intangible Assets [Line Items]
Equity commitment		$ 200	$ 100
Proceeds from issuance of preferred equity		100
Issuance costs of preferred equity		$ 3
Annual dividend rate			6.50%
EPIC Crude Holdings, LP | Noble Midstream
Finite-Lived Intangible Assets [Line Items]
Step acquisition, percentage acquired			30.00%

Basis of Presentation - Stateme

Basis of Presentation - Statements of Operations Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Other Revenue
Revenue from Sales	$ 1,119	$ 1,273	$ 3,264	$ 3,789
Production Expense
Lease Operating Expense	132	124	405	411
Production and Ad Valorem Taxes	52	47	142	151
Gathering, Transportation and Processing Expense	108	97	306	292
Total	297	273	862	886
Other Operating Expense, Net
Exploration Expense	25	25	82	89
Marketing Expense	7	11	26	21
Firm Transportation Exit Cost	0	0	92	0
Other, Net	29	(9)	57	(3)
Total	61	27	257	107
Other Revenue
Other Revenue
Revenue from Sales	29	65	106	189
Income from Equity Method Investments and Other
Other Revenue
Revenue from Sales	10	44	43	140
Midstream Services Revenues – Third Party
Other Revenue
Revenue from Sales	19	21	63	49
Other Royalty Expense
Production Expense
Cost of Purchased Oil and Gas	$ 5	$ 5	$ 9	$ 32

Basis of Presentation - Balance

Basis of Presentation - Balance Sheet Information (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Accounts Receivable, Net
Commodity Sales	$ 405	$ 383
Joint Interest Billings	177	137
Other	103	111
Allowance for Doubtful Accounts	(8)	(15)
Total	677	616
Other Current Assets
Commodity Derivative Assets	90	180
Inventories, Materials and Supplies	74	55
Assets Held for Sale	0	133
Prepaid Expenses and Other Current Assets	113	50
Total	277	418
Other Noncurrent Assets
Equity Method Investments	959	286
Operating Lease Right of Use Assets	275	0
Customer-Related Intangible Assets, Net	286	310
Goodwill	110	110
Other Assets, Noncurrent	150	135
Total	1,780	841
Other Current Liabilities
Production and Ad Valorem Taxes	147	103
Asset Retirement Obligations	89	118
Interest Payable	87	66
Operating Lease Liabilities	97	0
Commercial Paper Borrowings	511	0
Other Liabilities, Current	259	232
Total	1,190	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	148	147
Asset Retirement Obligations	699	762
Operating Lease Liabilities	209	0
Firm Transportation Exit Cost Accrual	133	67
Other Liabilities, Noncurrent	149	189
Total	1,338	1,165
Accumulated amortization	$ 54	$ 30

Basis of Presentation - Compone

Basis of Presentation - Components of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and Cash Equivalents	$ 473	$ 716	$ 720	$ 675
Restricted Cash	0	3	1	38
Cash, Cash Equivalents, and Restricted Cash	$ 473	$ 719	$ 721	$ 713

Segment Information - Operating

Segment Information - Operating Results by Segment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenue from Sales	$ 1,119	$ 1,273	$ 3,264	$ 3,789
Lease Operating Expense	132	124	405	411
Production and Ad Valorem Taxes	52	47	142	151
Gathering, Transportation and Processing Expense	108	97	306	292
Total Production Expense	297	273	862	886
Depreciation, Depletion and Amortization	583	485	1,619	1,418
Firm Transportation Exit Cost	0	0	92	0
(Gain) Loss on Divestitures, Net	0	(193)	0	(859)
Asset Impairments				168
(Gain) Loss on Commodity Derivative Instruments	(129)	155	23	483
Income (Loss) Before Income Taxes	51	307	(294)	860
Additions to Long-Lived Assets, Excluding Acquisitions	595	768	1,954	2,608
Additions to Equity Method Investments	271		686	0
Property, Plant and Equipment, Net	18,797		18,797		$ 18,419
Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	(125)	(91)	(322)	(257)
Lease Operating Expense	(9)	(12)	(30)	(18)
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	(71)	(60)	(199)	(168)
Total Production Expense	(80)	(72)	(229)	(186)
Depreciation, Depletion and Amortization	(8)	(5)	(21)	(13)
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	(23)	(16)	(52)	(52)
Additions to Long-Lived Assets, Excluding Acquisitions	(26)	(22)	(74)	(72)
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	(198)		(198)		(145)
Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	18	26	68	81
Lease Operating Expense	0	0	0	0
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	0	0	0	0
Total Production Expense	0	0	0	0
Depreciation, Depletion and Amortization	21	10	51	33
Firm Transportation Exit Cost			92
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	(214)	(170)	(660)	(498)
Additions to Long-Lived Assets, Excluding Acquisitions	11	(2)	29	26
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	302		302		306
United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	825	919	2,390	2,737
Lease Operating Expense	111	114	350	354
Production and Ad Valorem Taxes	51	46	138	147
Gathering, Transportation and Processing Expense	173	129	439	389
Total Production Expense	340	294	936	922
Depreciation, Depletion and Amortization	505	414	1,401	1,214
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		5		20
Asset Impairments				168
(Gain) Loss on Commodity Derivative Instruments	(123)	140	7	400
Income (Loss) Before Income Taxes	92	31	(85)	(94)
Additions to Long-Lived Assets, Excluding Acquisitions	377	535	1,367	1,630
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	13,170		13,170		13,044
United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	186	168	512	451
Lease Operating Expense	1	0	3	0
Production and Ad Valorem Taxes	1	1	4	4
Gathering, Transportation and Processing Expense	5	28	65	71
Total Production Expense	7	29	72	75
Depreciation, Depletion and Amortization	26	24	77	62
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		(198)		(503)
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	83	268	202	690
Additions to Long-Lived Assets, Excluding Acquisitions	56	82	174	479
Additions to Equity Method Investments	86		501
Property, Plant and Equipment, Net	1,682		1,682		1,742
United States | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	125	91	322	257
Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	119	124	344	368
Lease Operating Expense	7	7	26	19
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	1	0	1	0
Total Production Expense	8	7	27	19
Depreciation, Depletion and Amortization	17	16	50	44
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		(376)
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	74	143	223	678
Additions to Long-Lived Assets, Excluding Acquisitions	129	170	380	533
Additions to Equity Method Investments	185		185
Property, Plant and Equipment, Net	3,001		3,001		2,630
West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	96	127	272	409
Lease Operating Expense	22	15	56	56
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	0	0	0	0
Total Production Expense	22	15	56	56
Depreciation, Depletion and Amortization	21	25	60	77
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	(6)	15	16	83
Income (Loss) Before Income Taxes	56	68	126	180
Additions to Long-Lived Assets, Excluding Acquisitions	46	4	64	9
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	801		801		805
Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Lease Operating Expense	0	0	0	0
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	0	0	0	0
Total Production Expense	0	0	0	0
Depreciation, Depletion and Amortization	1	1	1	1
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	(17)	(17)	(48)	(44)
Additions to Long-Lived Assets, Excluding Acquisitions	2	1	14	3
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	39		39		$ 37
Oil, NGL and Gas Sales
Segment Reporting Information [Line Items]
Revenue from Sales	1,003	1,136	2,894	3,409
Oil, NGL and Gas Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Oil, NGL and Gas Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Oil, NGL and Gas Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	802	919	2,324	2,737
Oil, NGL and Gas Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Oil, NGL and Gas Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	119	124	344	368
Oil, NGL and Gas Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	82	93	226	304
Oil, NGL and Gas Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales
Segment Reporting Information [Line Items]
Revenue from Sales	724	744	2,024	2,266
Crude Oil Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	645	655	1,807	1,972
Crude Oil Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	1	2	4	6
Crude Oil Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	78	87	213	288
Crude Oil Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales
Segment Reporting Information [Line Items]
Revenue from Sales	78	166	258	449
NGL Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	78	166	258	449
NGL Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales
Segment Reporting Information [Line Items]
Revenue from Sales	201	226	612	694
Natural Gas Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	79	98	259	316
Natural Gas Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	118	122	340	362
Natural Gas Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	4	6	13	16
Natural Gas Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased of Gas
Segment Reporting Information [Line Items]
Revenue from Sales	87	72	264	191
Cost of Purchased Oil and Gas	96	76	296	204
Cost of Purchased of Gas | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Cost of Purchased of Gas | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	18	26	68	81
Cost of Purchased Oil and Gas	33	32
Cost of Purchased of Gas | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	22	0	64	0
Cost of Purchased Oil and Gas	17	0
Cost of Purchased of Gas | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	47	46	132	110
Cost of Purchased Oil and Gas	46	44
Cost of Purchased of Gas | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Cost of Purchased of Gas | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Cost of Purchased of Gas | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Income (Loss) from Equity Method Investments and Other
Segment Reporting Information [Line Items]
Revenue from Sales	10	44	43	140
Income (Loss) from Equity Method Investments and Other | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Income (Loss) from Equity Method Investments and Other | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Income (Loss) from Equity Method Investments and Other | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	1	0	2	0
Income (Loss) from Equity Method Investments and Other | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	(5)	10	(5)	35
Income (Loss) from Equity Method Investments and Other | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Income (Loss) from Equity Method Investments and Other | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	14	34	46	105
Income (Loss) from Equity Method Investments and Other | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party
Segment Reporting Information [Line Items]
Revenue from Sales	19	21	63	49
Midstream Services Revenues – Third Party | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	19	21	63	49
Midstream Services Revenues – Third Party | United States | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0		0
Midstream Services Revenues – Third Party | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Other Royalty Expense
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	5	5	9	32
Other Royalty Expense | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | Corporate
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | United States | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	5	5	9	32
Other Royalty Expense | United States | Noble Midstream
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	$ 0	$ 0	0	0
Cost of Purchased Oil and Gas
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			296	204
Cost of Purchased Oil and Gas | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			0	0
Cost of Purchased Oil and Gas | Corporate
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			112	98
Cost of Purchased Oil and Gas | United States | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			59	0
Cost of Purchased Oil and Gas | United States | Noble Midstream
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			125	106
Cost of Purchased Oil and Gas | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			0	0
Cost of Purchased Oil and Gas | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			0	0
Cost of Purchased Oil and Gas | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			$ 0	$ 0

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details) a in Thousands, shares in Millions, $ in Millions	1 Months Ended					3 Months Ended				9 Months Ended
	Feb. 28, 2019USD ($)aMMBbls	Oct. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)shares	Jan. 31, 2018USD ($)	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)shares	Jun. 30, 2018USD ($)shares	Mar. 31, 2018USD ($)	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2021	Dec. 31, 2019	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Feb. 28, 2018USD ($)	Feb. 01, 2018shares
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 271				$ 686	$ 0
Cash consideration						959				959					$ 286
Asset Impairments						0	$ 0			0	168
Proceeds from divestiture										131	1,740
Gain (loss) on divestiture						0	193			0	859
Cash consideration										0	$ (653)
Intangible assets						286				286					310
Goodwill						110				$ 110					$ 110
CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture					$ 308		248	$ 135
Gain (loss) on divestiture					196		$ 198	$ 109
Shares sold (in shares) | shares							14.2	7.5
Greeley Crescent
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture			$ 64
Noble Midstream | Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration					681
Property, plant and equipment					206
Intangible assets					340
Goodwill					$ 110
EMED Pipeline BV
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 185
Percentage acquired						25.00%				25.00%
EMG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage acquired						39.00%				39.00%
EPIC Y-Grade, LP | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 46
Step acquisition, percentage acquired						15.00%				15.00%
Cash consideration														$ 227
EPIC Crude Holdings, LP | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 168
Step acquisition, percentage acquired						30.00%				30.00%
Delaware Crossing JV | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration						$ 53				$ 53
Pipeline capacity (in MBbl/d) | MMBbls	160
Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest				32.50%					32.50%
CNX Midstream Partners
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity owned (units) | shares																	21.7
Saddle Butte | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest					54.40%
Disposed by sale | Reeves County Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved and unproved non-core acreage sold (in acres) | a	13
Proceeds from divestitures	$ 131
Disposed by sale | Gulf of Mexico Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value				$ 480					$ 480							$ 480
Retained transaction related obligations				92					92
Asset Impairments									$ 168
Proceeds from divestiture								$ 383
Gain (loss) on divestiture								$ (24)
Disposed by sale | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on divestiture				$ 376
Percentage ownership sold				7.50%					7.50%
Cash consideration				$ 484
Shares received in divestiture (in shares) | shares				38.5
Value of shares				$ 224
Tax effect				$ 86
Proceeds from sale, net of expenses		$ 163
Disposed by sale | Southwest Royalties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale					$ 60
Scenario, Forecast | EMG Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage acquired													10.00%
Scenario, Forecast | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest												25.00%
CNX Midstream Partners | CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership			22.30%		50.00%		22.30%				22.30%						34.10%

Capitalized Exploratory Well _3

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Capitalized Exploratory Well Costs (Details) $ in Millions	Sep. 30, 2019USD ($)project	Dec. 31, 2018USD ($)project
Extractive Industries [Abstract]
Exploratory Well Costs Capitalized for a Period of One Year or Less	$ 15	$ 6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	354	348
Capitalized Exploratory Well Costs, End of Period	$ 369	$ 354
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project	7	7

Capitalized Exploratory Well _4

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Rollforward of Undeveloped Leasehold Costs (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Proved Developed and Undeveloped Reserves [Roll Forward]
Undeveloped Leasehold Costs, Beginning of Period	$ 2,306
Additions to Undeveloped Leasehold Costs	63
Transfers to Proved Properties	(20)
Undeveloped Leasehold Costs, End of Period	$ 2,349

Capitalized Exploratory Well _5

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Delaware Basin
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	$ 2,100
Eagle Ford Shale
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	100
Other US Onshore Properties
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	76
Other Int'l
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	$ 59

Asset Retirement Obligations -

Asset Retirement Obligations - ARO Activity (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance	$ 880	$ 875
Liabilities Incurred	17	16
Liabilities Settled	(82)	(309)
Revisions of Estimates	(60)	67
Accretion Expense	33	25
Asset Retirement Obligations, Ending Balance	$ 788	$ 674

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	$ (60)	$ 67
Liabilities Settled	82	309
DJ Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	(73)
Offshore Israel
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	$ 13
Gulf of Mexico Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		216
Greeley Crescent
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		24
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		84
Liabilities Settled		69
North Sea abandonment project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		(11)
Eastern Mediterranean
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		$ (6)

Debt - Summary of Debt (Details

Debt - Summary of Debt (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Finance Lease Obligations	$ 206
Total Debt	7,551	$ 6,675
Net Unamortized Discounts and Debt Issuance Costs	(57)	(60)
Total Debt	7,494	6,615
Commercial Paper Borrowings	(511)	0
Finance Lease Obligations	(42)	(41)
Long-Term Debt Due After One Year	6,941	6,574
Noble Midstream Services Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	800
Available borrowing capacity	$ 750	$ 740
Senior Notes and Debentures
Debt Instrument [Line Items]
Weighted average interest rate	5.00%	5.01%
Noble Energy
Debt Instrument [Line Items]
Finance Lease Obligations	$ 206	$ 223
Finance Lease Obligations, Interest Rate	0.00%	0.00%
Total Debt	$ 6,601	$ 6,115
Noble Energy | Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Debt	$ 0	$ 0
Interest Rate	0.00%	0.00%
Noble Energy | Commercial Paper
Debt Instrument [Line Items]
Debt	$ 511	$ 0
Weighted average interest rate, commercial paper	2.63%
Noble Energy | Senior Notes and Debentures
Debt Instrument [Line Items]
Debt	$ 5,884	5,892
Noble Midstream Partners
Debt Instrument [Line Items]
Total Debt	950	560
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Debt	$ 50	$ 60
Interest Rate	3.45%	3.67%
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due July 31, 2021
Debt Instrument [Line Items]
Debt	$ 500	$ 500
Interest Rate	3.17%	3.42%
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due August 23, 2022
Debt Instrument [Line Items]
Debt	$ 400
Interest Rate	3.05%	0.00%

Debt - Narrative (Details)

Debt - Narrative (Details) - USD ($)	3 Months Ended	9 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Commercial paper		$ 511,000,000
Commercial Paper
Debt Instrument [Line Items]
Borrowing capacity		4,000,000,000
Available borrowing capacity		3,500,000,000
Senior Notes October 2029
Debt Instrument [Line Items]
Borrowing capacity		$ 500,000,000
Interest Rate		3.25%
Senior Notes October 2049
Debt Instrument [Line Items]
Borrowing capacity		$ 500,000,000
Interest Rate		4.20%
Senior Notes December 2021
Debt Instrument [Line Items]
Interest Rate		4.15%
Debt redemption		$ 1,000,000,000
Scenario, Forecast
Debt Instrument [Line Items]
Debt extinguishment fees	$ 44,000,000
Revolving Credit Facility | Noble Midstream | Noble Midstream Services Term Loan Credit Facility, due August 23, 2022
Debt Instrument [Line Items]
Debt		$ 400,000,000
Interest Rate		3.05%	0.00%

Leases - Right-of-use Assets an

Leases - Right-of-use Assets and Liability (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
ROU Assets
Operating Leases	$ 275	$ 0
Finance Leases	172
Total ROU Assets	447
Current Liabilities
Operating Leases	97	0
Finance Leases	42	41
Noncurrent Liabilities
Operating Leases	209	$ 0
Finance Leases	164
Total Lease Liabilities	512
Office Space
ROU Assets
Operating Leases	117
Finance Leases	92
Compressors
ROU Assets
Operating Leases	93
Drilling Rigs
ROU Assets
Operating Leases	29
Trunklines
ROU Assets
Operating Leases	$ 32

Leases - Lease Expense (Details

Leases - Lease Expense (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Leases [Abstract]
Operating Lease Cost	$ 30	$ 81
Finance Lease Cost
Amortization Expense	10	27
Interest Expense	3	10
Short-term Lease Cost	88	357
Sublease Income	(1)	(3)
Total Lease Cost	$ 130	$ 472

Leases - Cash Flow Information

Leases - Cash Flow Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows, Operating Leases	$ 50
Operating Cash Flows, Finance Leases	9
Investing Cash Flows, Operating Leases	27
Financing Cash Flows, Finance Leases	31
ROU Assets Obtained in Exchange for Lease Liability, Operating	93
ROU Assets Obtained in Exchange for Lease Liability, Finance	$ 15

Leases - Lease Maturity (Detail

Leases - Lease Maturity (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Operating Leases
Remainder of 2019	$ 28
2020	100
2021	61
2022	44
2023	29
2024 and thereafter	85
Total Lease Liabilities, Undiscounted	347
Less: Imputed Interest	41
Total Lease Liabilities	306
Finance Leases
Remainder of 2019	13
2020	49
2021	35
2022	25
2023	22
2024 and Thereafter	106
Total Lease Liabilities, Undiscounted	250
Less: Imputed Interest	44
Total Lease Liabilities	206
Total
Remainder of 2019	41
2019		$ 143
2020	149	120
2021	96	90
2022	69	84
2023	51	70
2024 and Thereafter	191	280
Total Lease Liabilities, Undiscounted	597	787
Liabilities, Undiscounted Excess Amount	85
Lease Liability	512
Operating lease liability, current	97	0
Finance lease liability, current	$ 42	41
Operating Leases
2019		91
2020		74
2021		59
2022		62
2023		50
2024 and Thereafter		176
Total Lease Liabilities, Undiscounted		512
Finance Leases
2019		52
2020		46
2021		31
2022		22
2023		20
2024 and Thereafter		104
Total Lease Liabilities, Undiscounted		$ 275

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rates (Details)	Sep. 30, 2019	Dec. 31, 2018
Weighted-Average Remaining Lease Term (Years)
Operating Leases	5 years 8 months 12 days
Finance Leases		7 years 8 months 12 days
Weighted-Average Discount Rate
Operating Leases	4.40%
Finance Leases		5.02%

Exit Costs - Transportation C_3

Exit Costs - Transportation Commitments - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018
Long-term Purchase Commitment [Line Items]
Reduction of transportation contracts	$ 350
Marcellus Shale Firm Transportation Agreement
Long-term Purchase Commitment [Line Items]
Commitment amount		$ 1,000
Firm Transportation Exit Cost Accrual	$ 92	$ 92	$ 0

Exit Costs - Transportation C_4

Exit Costs - Transportation Commitments - Rollfoward of Accrued Transportation Commitment (Details) - Marcellus Shale Firm Transportation Agreement - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Rollforward Of Contractual Obligations [Roll Forward]
Balance at Beginning of Period	$ 80	$ 80	$ 90
Firm Transportation Exit Cost Accrual	$ 92	92	0
Payments, Net of Accretion		(6)	(9)
Balance at End of Period		166	81
Other Current Liabilities
Rollforward Of Contractual Obligations [Roll Forward]
Balance at End of Period		33	12
Accrued exit costs, current				$ 13
Other Noncurrent Liabilities
Rollforward Of Contractual Obligations [Roll Forward]
Balance at End of Period		$ 133	$ 69

Income Taxes - Components of In

Income Taxes - Components of Income Tax (Benefit) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Current	$ 24	$ 45	$ 61	$ 194
Deferred	(9)	14	(110)	(150)
Total Income Tax Expense (Benefit)	$ 15	$ 59	$ (49)	$ 44
Effective Tax Rate	29.40%	19.20%	16.70%	5.10%

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Mar. 31, 2018
Operating Loss Carryforwards [Line Items]
Tax benefit from Tax Reform Legislation and Toll Tax	$ 145
Tamar and Dalit Fields | Disposed by sale
Operating Loss Carryforwards [Line Items]
Percentage of divestiture farmed out		7.50%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Summary of Outstanding Derivative Contracts (Details)	Sep. 30, 2019bbl / dMMBTU / d$ / bbl$ / MMBTU
Crude Oil Contract | NYMEX WTI - Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	35,000
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	33,000
Crude Oil Contract | NYMEX WTI - Sold Calls 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	4,000
Crude Oil Contract | ICE Brent - Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	5,000
Crude Oil Contract | ICE Brent - Three-Way Collars 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	3,000
Crude Oil Contract | Basis Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	27,000
Crude Oil Contract | NYMEX WTI - Swaption 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	12,000
Crude Oil Contract | NYMEX WTI - Sold Calls 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	8,000
Crude Oil Contract | NYMEX WTI - Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	28,000
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	30,000
Crude Oil Contract | Basis Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	15,000
Natural Gas Contract | NYMEX HH - Three-Way Collars 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	104,000
Natural Gas Contract | NYMEX HH - Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	46,000
Natural Gas Contract | CIG - Basis Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	123,500
Natural Gas Contract | WAHA - Basis Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	47,500
Natural Gas Contract | NYMEX HH - Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	90,000
Natural Gas Contract | NYMEX HH - Sold Puts 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	90,000
Natural Gas Contract | NYMEX HH - Swaption 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	90,000
Natural Gas Contract | CIG - Basis Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	54,000
Natural Gas Contract | WAHA - Basis Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	49,500
Natural Gas Contract | WAHA - Basis Swaps 2021
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	14,000
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	59.04
Swaps | Crude Oil Contract | NYMEX WTI - Sold Calls 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	60
Swaps | Crude Oil Contract | ICE Brent - Swaps 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	57
Swaps | Crude Oil Contract | Basis Swaps 2019
Derivative [Line Items]
Weighted Average Differential ($ per bbl)	(3.23)
Swaps | Crude Oil Contract | NYMEX WTI - Swaption 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	59.73
Swaps | Crude Oil Contract | NYMEX WTI - Sold Calls 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	65.59
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	58.09
Swaps | Crude Oil Contract | Basis Swaps 2020
Derivative [Line Items]
Weighted Average Differential ($ per bbl)	(5.01)
Swaps | Natural Gas Contract | NYMEX HH - Swaps 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU	3
Swaps | Natural Gas Contract | CIG - Basis Swaps 2019
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(0.64)
Swaps | Natural Gas Contract | WAHA - Basis Swaps 2019
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(1.28)
Swaps | Natural Gas Contract | NYMEX HH - Swaps 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU	2.60
Swaps | Natural Gas Contract | NYMEX HH - Swaption 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU	2.60
Swaps | Natural Gas Contract | CIG - Basis Swaps 2020
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(0.61)
Swaps | Natural Gas Contract | WAHA - Basis Swaps 2020
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(1.05)
Swaps | Natural Gas Contract | WAHA - Basis Swaps 2021
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(0.60)
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl)	49.35
Weighted Average Floor Price ($ per bbl)	59.35
Weighted Average Ceiling Price ($ per bbl)	72.25
Collars | Crude Oil Contract | ICE Brent - Three-Way Collars 2019
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl)	43
Weighted Average Floor Price ($ per bbl)	50
Weighted Average Ceiling Price ($ per bbl)	64.07
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2020
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl)	48.33
Weighted Average Floor Price ($ per bbl)	57.87
Weighted Average Ceiling Price ($ per bbl)	64.27
Collars | Natural Gas Contract | NYMEX HH - Three-Way Collars 2019
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl) | $ / MMBTU	2.25
Weighted Average Floor Price ($ per bbl) | $ / MMBTU	2.65
Weighted Average Ceiling Price ($ per bbl) | $ / MMBTU	2.95
Collars | Natural Gas Contract | NYMEX HH - Sold Puts 2020
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl) | $ / MMBTU	2.15

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities - Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 115		$ 115		$ 180
Derivative Liability, Fair Value	13		13		27
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(13)	$ 67	(28)	$ 160
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(116)	88	51	323
Total (Gain) Loss on Commodity Derivative Instruments	(129)	155	23	483
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	90		90		180
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	10		10		1
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	25		25		0
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	3		3		$ 26
Crude Oil
Derivatives, Fair Value [Line Items]
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(6)	68	(8)	164
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(115)	85	54	316
Total (Gain) Loss on Commodity Derivative Instruments	(121)	153	46	480
Natural Gas
Derivatives, Fair Value [Line Items]
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(7)	(1)	(20)	(4)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(1)	3	(3)	7
Total (Gain) Loss on Commodity Derivative Instruments	$ (8)	$ 2	$ (23)	$ 3

Fair Value Measurements and D_3

Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Financial Assets:
Mutual Fund Investments		$ 38
Commodity Derivative Instruments	$ 115	180
Financial Liabilities:
Commodity Derivative Instruments	(13)	(27)
Portion of Deferred Compensation Liability Measured at Fair Value	(48)	(43)
Stock Based Compensation Liability Measured at Fair Value	(3)	(8)
Quoted Prices in Active Markets (Level 1)
Financial Assets:
Mutual Fund Investments		38
Commodity Derivative Instruments	0	0
Financial Liabilities:
Commodity Derivative Instruments	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	(48)	(43)
Stock Based Compensation Liability Measured at Fair Value	(3)	(8)
Significant Other Observable Inputs (Level 2)
Financial Assets:
Mutual Fund Investments		0
Commodity Derivative Instruments	155	187
Financial Liabilities:
Commodity Derivative Instruments	(53)	(34)
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
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
Scenario, Adjustment
Financial Assets:
Mutual Fund Investments		0
Commodity Derivative Instruments	(40)	(7)
Financial Liabilities:
Commodity Derivative Instruments	40	7
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	$ 0
Mutual Fund Investments
Financial Assets:
Mutual Fund Investments	42
Mutual Fund Investments | Quoted Prices in Active Markets (Level 1)
Financial Assets:
Mutual Fund Investments	42
Mutual Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Assets:
Mutual Fund Investments	0
Mutual Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Assets:
Mutual Fund Investments	0
Mutual Fund Investments | Scenario, Adjustment
Financial Assets:
Mutual Fund Investments	$ 0

Fair Value Measurements and D_4

Fair Value Measurements and Disclosures - Narrative (Details) - USD ($) $ in Millions	1 Months Ended		9 Months Ended
	Mar. 31, 2019	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Redeemable Noncontrolling Interest, Net	$ 97		$ 103		$ 0
Proceeds from issuance of preferred equity			97	$ 0
Noble Midstream
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proceeds from issuance of preferred equity	100
Issuance costs of preferred equity	$ 3
Marcellus Shale Firm Transportation Agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Firm transportation exit cost accrual		$ 92	$ 92	$ 0

Fair Value Measurements and D_5

Fair Value Measurements and Disclosures - Fair Value of Debt (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	$ 7,345	$ 6,452
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	$ 7,963	$ 6,121

Net Income (Loss) Per Share A_3

Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Abstract]
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$ 17	$ 227	$ (306)	$ 758
Weighted Average, Number of Shares Outstanding, Basic (in shares)	478	482	478	484
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (in shares)	2	2	0	2
Weighted Average, Number of Shares Outstanding, Diluted (in shares)	480	484	478	486
(Loss) Income Per Share, Basic ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.57
(Loss) Income Per Share, Diluted ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.56
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above (in shares)	14	13	15	14
Share purchase plan, authorized amount	$ 750		$ 750