Concho Resources (CXO) 10-K 19 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 14, 2020	Jun. 30, 2019
Document Documentand Entity Information [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-33615
Entity Registrant Name	Concho Resources Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	76-0818600
Entity Address, Address Line One	One Concho Center
Entity Address, Address Line Two	600 West Illinois Avenue
Entity Address, City or Town	Midland
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	79701
City Area Code	(432)
Local Phone Number	683-7443
Title of 12(b) Security	Common Stock, $0.001 par value
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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 Public Float			$ 20,479,372,863
Entity Common Stock, Shares Outstanding		196,705,121
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Trading Symbol	CXO
Current Fiscal Year End Date	0001358071
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 70	$ 0
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas	584	466
Joint operations and other	304	365
Inventory	30	35
Derivative instruments	6	484
Prepaid costs and other	61	59
Total current assets	1,055	1,409
Property and equipment:
Oil and natural gas properties, successful efforts method	28,785	31,706
Accumulated depletion and depreciation	(7,895)	(9,701)
Total oil and natural gas properties, net	20,890	22,005
Other property and equipment, net	437	308
Total property and equipment, net	21,327	22,313
Deferred loan costs, net	7	10
Goodwill	1,917	2,224
Intangible assets, net	17	19
Noncurrent derivative instruments	11	211
Other assets	398	108
Total assets	24,732	26,294
Current liabilities:
Accounts payable - trade	53	50
Book overdrafts	0	159
Revenue payable	268	253
Accrued drilling costs	386	574
Derivative instruments	112	0
Other current liabilities	363	320
Total current liabilities	1,182	1,356
Long-term debt	3,955	4,194
Deferred tax liabilities, net	1,654	1,808
Noncurrent derivative instruments	7	0
Asset retirement obligations and other long-term liabilities	152	168
Commitments and contingencies (Note 11)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 198,863,681 and 201,288,884 shares issued at December 31, 2019 and 2018, respectively	0	0
Additional paid-in capital	14,608	14,773
Retained earnings	3,320	4,126
Treasury stock, at cost; 1,175,026 and 1,031,655 shares at December 31, 2019 and 2018, respectively	(146)	(131)
Total stockholders’ equity	17,782	18,768
Total liabilities and stockholders’ equity	$ 24,732	$ 26,294

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares issued (in shares)	198,863,681	201,288,884
Treasury shares (in shares)	1,175,026	1,031,655

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating revenues:
Total operating revenues	$ 4,592,000,000	$ 4,151,000,000	$ 2,586,000,000
Operating costs and expenses:
Production and ad valorem taxes	349,000,000	305,000,000	199,000,000
Exploration and abandonments	201,000,000	65,000,000	59,000,000
Depreciation, depletion and amortization	1,964,000,000	1,478,000,000	1,146,000,000
Accretion of discount on asset retirement obligations	10,000,000	10,000,000	8,000,000
Impairments of long-lived assets	890,000,000	0	0
Impairments of goodwill	282,000,000	0	0
General and administrative (including non-cash stock-based compensation of $85, $82 and $60 for the years ended December 31, 2019, 2018 and 2017, respectively)	326,000,000	311,000,000	244,000,000
(Gain) loss on derivatives	895,000,000	(832,000,000)	126,000,000
Gain on disposition of assets, net	(170,000,000)	(800,000,000)	(678,000,000)
Transaction costs	1,000,000	39,000,000	3,000,000
Total operating costs and expenses	5,579,000,000	1,221,000,000	1,515,000,000
Income (loss) from operations	(987,000,000)	2,930,000,000	1,071,000,000
Other income (expense):
Interest expense	(185,000,000)	(149,000,000)	(146,000,000)
Loss on extinguishment of debt	0	0	(66,000,000)
Other, net	313,000,000	108,000,000	22,000,000
Total other income (expense)	128,000,000	(41,000,000)	(190,000,000)
Income (loss) before income taxes	(859,000,000)	2,889,000,000	881,000,000
Income tax (expense) benefit	154,000,000	(603,000,000)	75,000,000
Net income (loss)	$ (705,000,000)	$ 2,286,000,000	$ 956,000,000
Earnings per share:
Basic net income (loss) (in dollars per share)	$ (3.55)	$ 13.28	$ 6.44
Diluted net income (loss) (in dollars per share)	$ (3.55)	$ 13.25	$ 6.41
Oil
Operating revenues:
Total operating revenues	$ 4,126,000,000	$ 3,443,000,000	$ 2,092,000,000
Natural Gas
Operating revenues:
Total operating revenues	466,000,000	708,000,000	494,000,000
Oil And Natural Gas Production
Operating costs and expenses:
Operating costs and expenses	716,000,000	590,000,000	408,000,000
Gathering, Processing and Transportation
Operating costs and expenses:
Operating costs and expenses	$ 115,000,000	$ 55,000,000	$ 0

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Non-cash stock-based compensation	$ 85	$ 82	$ 60

Consolidated Statement of Stock

Consolidated Statement of Stockholders Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock Issued	Additional Paid-in Capital	Retained Earnings	Treasury Stock
Balance (in shares) at Dec. 31, 2016		146,489			430
Balance at Dec. 31, 2016	$ 7,631	$ 0	$ 6,791	$ 884	$ (44)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	956			956	$ 0
Common stock issued in business combinations (in shares)		2,177
Common stock issued in business combinations	291		291
Stock options exercised (in shares)		20
Units granted (in shares)		490
Performance unit share conversion (in shares)		249
Cancellation of restricted stock (in shares)		(100)
Stock-based compensation	60		60
Purchase of treasury stock (in shares)					168
Purchase of treasury stock	(23)				$ (23)
Balance (in shares) at Dec. 31, 2017		149,325			598
Balance at Dec. 31, 2017	8,915	$ 0	7,142	1,840	$ (67)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,286			2,286	$ 0
Common stock issued in business combinations (in shares)		50,915
Common stock issued in business combinations	7,549		7,549
Units granted (in shares)		687
Performance unit share conversion (in shares)		447
Cancellation of restricted stock (in shares)		(85)
Stock-based compensation	82		82
Purchase of treasury stock (in shares)					434
Purchase of treasury stock	(64)				$ (64)
Balance (in shares) at Dec. 31, 2018		201,289			1,032
Balance at Dec. 31, 2018	18,768	$ 0	14,773	4,126	$ (131)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(705)			(705)	$ 0
Common stock issued in business combinations	0
Common stock repurchased and retired (in shares)		(3,300)
Common stock repurchased and retired	(250)	$ 0	(250)
Units granted (in shares)		776
Performance unit share conversion (in shares)		246
Cancellation of restricted stock (in shares)		(147)
Stock-based compensation	85		85
Common stock dividends ($0.50 per share)	(101)			(101)
Purchase of treasury stock (in shares)					143
Purchase of treasury stock	(15)				$ (15)
Balance (in shares) at Dec. 31, 2019		198,864			1,175
Balance at Dec. 31, 2019	$ 17,782	$ 0	$ 14,608	$ 3,320	$ (146)

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Paranthetical) (Details)	12 Months Ended
	Dec. 31, 2019$ / shares
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.50

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (705,000,000)	$ 2,286,000,000	$ 956,000,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,964,000,000	1,478,000,000	1,146,000,000
Accretion of discount on asset retirement obligations	10,000,000	10,000,000	8,000,000
Impairments of long-lived assets	890,000,000	0	0
Impairments of goodwill	282,000,000	0	0
Exploration and abandonments	166,000,000	35,000,000	27,000,000
Non-cash stock-based compensation expense	85,000,000	82,000,000	60,000,000
Deferred income taxes	(154,000,000)	605,000,000	(71,000,000)
Net gain on disposition of assets and other non-operating items	(459,000,000)	(800,000,000)	(678,000,000)
(Gain) loss on derivatives	895,000,000	(832,000,000)	126,000,000
Net settlements received from (paid on) derivatives	(98,000,000)	(218,000,000)	79,000,000
Loss on extinguishment of debt	0	0	66,000,000
Other	0	(92,000,000)	(1,000,000)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	(90,000,000)	(35,000,000)	(126,000,000)
Prepaid costs and other	(2,000,000)	(10,000,000)	(9,000,000)
Inventory	1,000,000	(12,000,000)	0
Accounts payable	3,000,000	1,000,000	14,000,000
Revenue payable	28,000,000	52,000,000	52,000,000
Other current liabilities	20,000,000	8,000,000	46,000,000
Net cash provided by operating activities	2,836,000,000	2,558,000,000	1,695,000,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties	(3,069,000,000)	(2,496,000,000)	(1,581,000,000)
Acquisitions of oil and natural gas properties	(54,000,000)	(136,000,000)	(908,000,000)
Additions to property, equipment and other assets	(117,000,000)	(90,000,000)	(44,000,000)
Proceeds from the disposition of assets	1,260,000,000	361,000,000	832,000,000
Direct transaction costs for asset acquisitions and dispositions	(13,000,000)	(3,000,000)	(18,000,000)
Distribution from equity method investment	0	148,000,000	0
Net cash used in investing activities	(1,993,000,000)	(2,216,000,000)	(1,719,000,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	2,935,000,000	3,316,000,000	1,001,000,000
Payments on credit facility	(3,177,000,000)	(3,396,000,000)	(679,000,000)
Issuance of senior notes, net	0	1,595,000,000	1,794,000,000
Repayments of senior notes	0	0	(2,150,000,000)
Repayments of RSP debt	0	(1,690,000,000)	0
Debt extinguishment costs	0	(83,000,000)	(63,000,000)
Payments for loan costs	0	(16,000,000)	(25,000,000)
Payment of common stock dividends	(100,000,000)	0	0
Purchases of treasury stock	(15,000,000)	(64,000,000)	(23,000,000)
Purchases of common stock under share repurchase program	(250,000,000)	0	0
Increase (decrease) in book overdrafts	(159,000,000)	(4,000,000)	116,000,000
Other	(7,000,000)	0	0
Net cash used in financing activities	(773,000,000)	(342,000,000)	(29,000,000)
Net increase (decrease) in cash and cash equivalents	70,000,000	0	(53,000,000)
Cash and cash equivalents at beginning of period	0	0	53,000,000
Cash and cash equivalents at end of period	70,000,000	0	0
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest	207,000,000	118,000,000	139,000,000
Cash paid for income taxes	0	2,000,000	13,000,000
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of common stock for business combinations	$ 0	$ 7,549,000,000	$ 291,000,000

Organization and nature of oper

Organization and nature of operations	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and nature of operations	Organization and nature of operations Concho Resources Inc., a Delaware corporation (the “Company”) is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. The Company’s operations are primarily focused in the Permian Basin of West Texas and Southeast New Mexico.

Summary of significant accounti

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of significant accounting policies	Summary of significant accounting policies Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also included the accounts of a variable interest entity (“VIE”) where the Company was the primary beneficiary of the arrangements until the VIE structure dissolved in January 2018. See Note 5 for additional information regarding the circumstances surrounding the VIE. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated. Reclassifications. Certain prior period amounts have been reclassified to conform to the 2019 presentation. These reclassifications had no impact on net income (loss), total assets, liabilities and stockholders’ equity or total cash flows. Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, goodwill, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary transactions, fair value of derivative financial instruments and income taxes. Assets held for sale. On the date at which the Company determines the asset group met all of the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the asset or asset group to be sold and reclassifies these assets as held for sale in its consolidated balance sheets. The assets held for sale are measured at the fair value less cost to sell. Cash and cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, 2019, the majority of the Company’s cash was invested in stable value government money market funds. Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Oil and natural gas sales receivables related to these operations are generally unsecured. Joint interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of $7 million and $5 million for the years ended December 31, 2019 and 2018 , respectively. Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of weighted average cost or net realizable value. Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. The Company recognized depletion expense of approximately $1.9 billion , $1.5 billion and $1.1 billion during the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well; and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the Company’s large multi-well project development program, capital intensive nature and geographical location of certain projects, it may take longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. The Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves and is transferred to proved oil and natural gas properties or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s exploratory well costs. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred. Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2019 and 2018 , the Company capitalized interest of $19 million and $8 million , respectively, primarily related to the Company’s development projects. The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recognized an impairment expense of $890 million during the year ended December 31, 2019 related to its proved oil and natural gas properties, but did not recognize an impairment expense during the years ended December 31, 2018 and 2017 . See Note 8 for additional information regarding the Company’s impairment expense. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. During the years ended December 31, 2019 , 2018 and 2017 , the Company recognized expense of $147 million , $35 million and $27 million , respectively, related to abandoned and expiring acreage, which is included in exploration and abandonments expense in the accompanying consolidated statements of operations. Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 39 years. The Company had other capital assets of $437 million and $308 million , net of accumulated depreciation of $126 million and $109 million , at December 31, 2019 and December 31, 2018 , respectively. During the years ended December 31, 2019 , 2018 and 2017 , the Company recognized depreciation expense of $30 million , $22 million and $21 million , respectively. Nonmonetary transactions. In connection with nonmonetary transactions, which include exchanges of producing and non-producing assets, the Company must evaluate the transaction to determine appropriate accounting treatment. In general, the basic principle of accounting for nonmonetary transactions is based on the fair values involved, which is the same basis used in monetary transactions and results in the recognition of gains and losses. However, certain nonmonetary transactions meet criteria that require modification of the basic principle that necessitate recording values based on historical book value. The Company determines the treatment of nonmonetary transactions based on the individual facts and circumstances of each transaction. In cases where nonmonetary transactions are recorded at fair value, the Company makes various assumptions. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties, similar to the valuation of the fair value of oil and natural gas assets acquired during a business combination. Any resulting difference between the fair value of the assets involved and their carrying value is recorded as a gain or loss in the consolidated statement of operations. Goodwill. Goodwill is assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of July 1 of each year. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. The reporting unit’s fair value is the Company’s enterprise value calculated as the combined market capitalization of the Company’s equity plus a control premium, and the fair value of the Company’s long-term debt. If the results of the quantitative test are such that the fair value of the reporting unit is less than the carrying value, goodwill is then reduced by an amount that is equal to the amount by which the carrying value of the reporting unit exceeds the fair value. The Company performed an annual quantitative impairment test during the third quarter of 2019 . The fair value of the reporting unit exceeded the carrying value of net assets at July 1, 2019. As discussed in Note 5 , in August 2019, the Company entered into a definitive agreement to sell its assets in the New Mexico Shelf. The Company classified these assets as held for sale at August 29, 2019. The Company allocated $81 million of goodwill to this disposal group, all of which the Company impaired. This impairment charge was recorded in impairments of goodwill on the consolidated statements of operations for the year ended December 31, 2019 . See Note 8 for additional impairment discussion of this disposal group. In conjunction with the allocation and impairment of goodwill related to the New Mexico Shelf disposal group, the Company performed a quantitative impairment test for the remaining goodwill. No additional impairment was recorded as the fair value of the reporting unit exceeded the carrying value. The Company also performed an impairment test at September 30, 2019 due to declines in the Company’s market capitalization and at December 31, 2019 due to declines in observed control premiums. The estimated fair value of the reporting unit at September 30, 2019 exceeded the carrying value of our net assets. However, during the fourth quarter of 2019, the Company’s estimated fair value declined further resulting in a $201 million impairment charge at December 31, 2019 . As such, the Company recorded total impairment charges of $282 million during the year ended December 31, 2019 . The Company used an average stock price over a determined period to estimate the fair value of the reporting unit at December 31, 2019, which the Company believes removes the impact of short term market fluctuations. In addition, the Company’s control premium was based on the estimated median control premium of transactions involving companies in the Company’s industry. The Company did not recognize an impairment expense during the year ended December 31, 2018. It is reasonably possible that the estimates of our enterprise value may change in the future resulting in the need to impair goodwill. Currently, the primary factor that may negatively affect the Company’s enterprise value is a continued depressed level of the Company’s stock price. Many factors affecting the Company’s stock price are beyond the Company’s control and the Company cannot predict the potential effects on the price of its common stock. Stock markets in general can also experience considerable price and volume fluctuations. In addition, deteriorating industry, market and economic conditions could negatively impact the control premium and the Company’s enterprise value, which could lead to additional impairments of the Company’s goodwill balance. Equity method investments. The Company holds membership interests in certain entities and accounts for these investments using the equity method of accounting. • The Company owns a 50 percent membership interest in Beta Holding Company, LLC, a midstream joint venture formed to construct a crude oil gathering system in the Midland Basin. • The Company owns a 20 percent membership interest in Solaris Midstream Holdings, LLC, an entity that owns and operates water gathering, transportation, disposal, recycling and storage infrastructure assets in the Permian Basin. • The Company owns a preferred membership interest in WaterBridge Operating LLC, an entity that operates and manages various water infrastructure assets located in the Permian Basin. The Company includes its equity method investment balance in other assets on the consolidated balance sheets. The Company records its share of equity investment earnings and losses in other income (expense) on the consolidated statements of operations. Equity investment earnings and losses are adjusted to account for any basis difference. The Company recorded equity method investment income of $12 million , $4 million and $7 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company also contributed certain water infrastructure assets and recorded a gain of $297 million and $79 million , which is included in gain on disposition of assets, net on the Company’s consolidated statements of operations for the years ended December 31, 2019 and 2018 , respectively. Until May 2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that owned and operated Oryx I, a crude oil gathering and transportation system in the Delaware Basin (“Oryx I”). In February 2018, Oryx obtained a term loan of $800 million . The proceeds were used in part to fund a cash distribution to its equity holders, of which the Company received a distribution of $157 million . Of this amount, $54 million fully offset the Company’s net investment in Oryx. The net investment of $54 million included $45 million of the Company’s contributions made to Oryx and $9 million of equity income. The remaining distribution of $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations for the year ended December 31, 2018. In May 2019, Oryx completed the sale of 100 percent of its equity interests in Oryx I. The Company received $289 million , net of closing costs, in connection with the sale of Oryx I and recorded a gain in other income (expense) on the Company’s consolidated statement of operations for the year ended December 31, 2019 . In February 2017, the Company closed on the divestiture of its 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the Delaware Basin. See Note 5 for additional information regarding the disposition of ACC. Regulatory and environmental compliance. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations and are capitalized. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures that are noncapital in nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revisions until settlement occurs. See Note 11 for additional information. Litigation contingencies. The Company is a party to proceedings and claims incidental to its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. The amount of any resulting losses may differ from these estimates. An accrual is recorded for a material loss contingency when its occurrence is probable and the amount is reasonably estimable. See Note 11 for additional information. Income taxes. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. At December 31, 2019 and 2018, the Company had unrecognized tax benefits primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain. The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense. On December 22, 2017, the President of the United States (the “President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” (“TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”) to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allowed companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year. The Company elected to apply SAB 118 and, as such, recorded provisional amounts for the income tax balances reported in its consolidated financial statements at December 31, 2017. At December 31, 2018, the Company completed its accounting for all tax effects of the TCJA and made an adjustment to its provisional amounts related to the deductibility of certain compensation based on available regulatory and interpretive guidance. Derivative instruments. The Company recognizes its derivative instruments, other than commodity derivative contracts that are designated as normal purchase and normal sale contracts, as either assets or liabilities measured at fair value. The Company nets the fair value of the derivative instruments by counterparty in the accompanying consolidated balance sheets when the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated balance sheets. Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related oil and natural gas property asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability through accretion expense. Based on certain factors, including commodity prices and costs, the Company may revise its previous estimates of the liability, which would also increase or decrease the related oil and natural gas property asset. Purchases of common stock. Common stock purchased and held in treasury is recorded at cost. For common stock repurchased and retired, the excess of cost over par value is charged to additional paid-in capital. Revenue recognition. On January 1, 2018, the Company adopted ASC Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”) using the modified retrospective approach. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and does not have a material impact on the Company’s reported net income (loss), cash flows from operations or statement of stockholders’ equity. The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. All revenues are recognized in the geographical region of the Permian Basin. Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers. The Company enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At December 31, 2019 and 2018 , the Company had receivables related to contracts with customers of $584 million and $466 million , respectively. Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in gathering, processing and transportation on the Company’s consolidated statements of operations and are accounted for as costs incurred directly and not netted from the transaction price. Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Company receives natural gas liquids and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in gathering, processing and transportation on the Company’s consolidated statements of operations. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14A, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions of general and administrative expense. Such fees totaled $18 million , $19 million and $16 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Stock-based compensation . Stock-based compensation expense is recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their grant date fair values. Stock-based compensation awards vest over a period generally ranging from one to ten years . The Company utilizes the average of the high and low stock prices at each grant date to determine the fair value of restricted stock and the Monte Carlo simulation method to determine the fair value of performance unit awards. The Company recognizes forfeitures on stock-based compensation awards as they occur. Recently adopted accounting pronouncements. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which requires all leases with a term greater than one year to be recognized on the consolidated balance sheet while maintaining similar classifications for finance and operating leases. Lease expense recognition on the consolidated statements of operations was effectively unchanged. The Company adopted this guidance on January 1, 2019. The Company made policy elections not to capitalize short-term leases for

Exploratory well costs

Exploratory well costs	12 Months Ended
	Dec. 31, 2019
Capitalized Exploratory Well Costs [Abstract]
Exploratory well costs	Exploratory well costs The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Unaudited Supplementary Data for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations. The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Beginning capitalized exploratory well costs $ 523 $ 182 $ 151 Additions to exploratory well costs pending the determination of proved reserves (a) 271 581 180 Reclassifications due to determination of proved reserves (503 ) (226 ) (147 ) Exploratory well costs charged to expense (6 ) — — Disposition of wells (7 ) (14 ) (2 ) Ending capitalized exploratory well costs $ 278 $ 523 $ 182 (a) Balance at December 31, 2018 includes $82 million of exploratory well costs acquired as part of the RSP Acquisition, as defined in Note 4 . The following table provides an aging at December 31, 2019 and 2018 of capitalized exploratory well costs based on the date drilling was completed: (in millions, except number of projects) December 31, 2019 2018 Capitalized exploratory well costs that have been capitalized for a period of one year or less $ 263 $ 523 Capitalized exploratory well costs that have been capitalized for a period greater than one year 15 — Total capitalized exploratory well costs $ 278 $ 523 Number of projects with exploratory well costs that have been capitalized for a period greater than one year 2 — The Company expects to complete three gross wells associated with two projects with $15 million

RSP acquisition

RSP acquisition	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
RSP Acquisition	RSP Acquisition On July 19, 2018 , the Company completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). RSP was an independent oil and natural gas company engaged in the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of RSP’s acreage was located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin. The acquisition added approximately 92,000 net acres. Under the terms of the Agreement and Plan of Merger (the “Acquisition Agreement”), each share of RSP common stock was converted into 0.320 of a share of the Company’s common stock. The Company issued approximately 51 million shares of common stock at a price of $148.27 per share, resulting in total consideration paid by the Company to the former RSP shareholders of approximately $7.5 billion . In connection with the closing of the RSP Acquisition, the Company repaid outstanding principal under RSP’s revolving credit facility and redeemed and canceled all of RSP’s outstanding unsecured senior notes. See Note 10 for additional information regarding the Company’s debt activity. In connection with the RSP Acquisition, the Company incurred $32 million of costs related to consulting, investment banking, advisory, legal and other acquisition-related fees during the year ended December 31, 2018, which are included in transaction costs in operating costs and expenses on the consolidated statements of operations. In addition, the Company acquired 670,369 shares of common stock from RSP employees for the payment of withholding taxes due on the vesting of their restricted shares pursuant to the Acquisition Agreement, resulting in an increase of $32 million in the Company’s treasury stock balance during the year ended December 31, 2018. Purchase price allocation. The RSP Acquisition has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of RSP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Goodwill is not deductible for income tax purposes. The following table sets forth the Company’s final purchase price allocation: (in millions) Total purchase price $ 7,549 Fair value of liabilities assumed: Accounts payable – trade $ 48 Accrued drilling costs 79 Current derivative instruments 10 Other current liabilities 116 Long-term debt 1,758 Deferred income taxes 515 Asset retirement obligations 20 Noncurrent derivative instruments 5 Total liabilities assumed $ 2,551 Total purchase price plus liabilities assumed $ 10,100 Fair value of assets acquired: Accounts receivable $ 194 Current derivative instruments 36 Other current assets 21 Proved oil and natural gas properties 4,055 Unproved oil and natural gas properties 3,565 Other property and equipment 5 Noncurrent derivative instruments 2 Implied goodwill 2,222 Total assets acquired $ 10,100 The fair values of assets acquired and liabilities assumed were based on the following key inputs: Oil and natural gas properties The fair value of proved and unproved oil and natural gas properties was measured using valuation techniques that convert the future cash flows to a single discounted amount. Significant inputs to the valuation of proved and unproved oil and natural gas properties include estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average costs of capital. The Company utilized a combination of the NYMEX strip pricing and consensus pricing, adjusted for differentials, to value the reserves. The Company’s estimates of commodity prices for purposes of determining discounted cash flows ranged from a 2018 price of $66.59 per barrel of oil decreasing to a 2022 price of $63.41 per barrel of oil. Similarly, natural gas prices ranged from a 2018 price of $2.80 per MMBtu then rising to a 2022 price of $3.09 per MMBtu. Both oil and natural gas commodity prices were held flat after 2022 and adjusted for inflation. The Company then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired. The fair value of asset retirement obligations totaled $20 million and is included in proved oil and natural gas properties with a corresponding liability in the table above. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. The inputs used to value oil and natural gas properties and asset retirement obligations require significant judgment and estimates made by management and represent Level 3 inputs. Financial instruments and other The fair value measurements of long-term debt were estimated based on the market prices and represent Level 1 inputs. The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves, implied market volatility, contract terms and prices and discount factors as of the close date of the RSP Acquisition and represent Level 2 inputs. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk and the derivative instruments in a liability position include a measure of the Company’s own nonperformance risk, each based on the current published credit default swap rates. The fair values determined for accounts receivable, accounts payable – trade, accrued drilling costs and other current liabilities were equivalent to the carrying value due to their short-term nature. Other current liabilities include $10 million of liabilities primarily related to certain regulatory obligations. Deferred income taxes The RSP Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in RSP’s assets and liabilities, adjusted for differences between the purchase price allocated to the assets acquired and liabilities assumed based on the fair value and the carryover tax basis. See Note 12 for additional discussion of deferred income taxes. Goodwill recognized was primarily attributable to the following factors: (i) operating and administrative synergies and (ii) net deferred tax liabilities arising from the differences between the purchase price allocated to RSP’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. For the operating and administrative synergies, the total consideration for the RSP Acquisition included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the RSP Acquisition creates for the Company’s stockholders, including additional potential for exploration and development opportunities and additional scale and efficiencies in basins in which the Company operates. Approximately $506 million of operating revenues and $274 million of income from operations attributed to the RSP Acquisition are included in the Company’s results of operations from the closing date on July 19, 2018 through December 31, 2018. Pro forma data. The following unaudited pro forma combined condensed financial data for the years ended December 31, 2018 and 2017 was derived from the historical financial statements of the Company giving effect to the RSP Acquisition, as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for RSP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert RSP’s outstanding shares of common stock and equity awards as of the closing date of the RSP Acquisition, (ii) the depletion of RSP’s fair-valued proved oil and gas properties and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of $32 million for the year ended December 31, 2018 and acquisition-related costs incurred by RSP and severance payments to certain RSP employees that totaled $56 million for the year ended December 31, 2018. The pro forma results of operations do not include any cost savings or other synergies that may result from the RSP Acquisition. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the period. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the RSP Acquisition taken place on January 1, 2017 and is not intended to be a projection of future results. (in millions, except per share amounts) Years Ended December 31, 2018 2017 (unaudited) Operating revenues $ 4,798 $ 3,390 Net income $ 2,552 $ 1,197 Earnings per share: Basic net income $ 12.75 $ 6.02 Diluted net income $ 12.73 $ 5.99

Acquisitions, divestitures and

Acquisitions, divestitures and nonmonetary transactions	12 Months Ended
	Dec. 31, 2019
Acquisitions, Divestitures, And Non-Monetary Transactions [Abstract]
Acquisitions, divestitures and nonmonetary transactions	Acquisitions, divestitures and nonmonetary transactions During the year ended December 31, 2019 , the Company closed on the following transactions: New Mexico Shelf divestiture. On August 29, 2019, the Company entered into a definitive agreement to sell its assets in the New Mexico Shelf. The Company determined these assets and liabilities to be held for sale at August 29, 2019 and recorded an impairment charge of $3 million , included in impairments of long-lived assets on the Company’s consolidated statement of operations for the year ended December 31, 2019 , to reduce the carrying value of these assets to their estimated fair value less costs to sell. This transaction closed in November 2019 for total proceeds of $837 million , subject to post-closing adjustments. The Company recorded a pre-tax loss of $27 million , included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the year ended December 31, 2019 . Additionally, the Company impaired the carrying value of goodwill by $81 million , reflecting the portion of the Company’s goodwill allocated to the assets sold. Nonmonetary transactions. During 2019 , the Company completed multiple nonmonetary transactions. These transactions included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, the Company recorded net pre-tax losses of $104 million , including a $23 million reduction of the carrying value of goodwill, reflecting the portion of the Company’s goodwill related to the assets sold. During the year ended December 31, 2018 , the Company closed on the following transactions (exclusive of the RSP Acquisition disclosed in Note 4 ): February 2018 acquisition and divestiture. In February 2018, the Company closed on an acquisition treated as a business combination where it received producing wells with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, the Company divested approximately 34,000 net acres located primarily in the northern portion of the Delaware Basin. The business acquired was valued at approximately $755 million as compared to the historical book value of the divested assets of approximately $180 million , which resulted in a non-cash gain of approximately $575 million , included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the year ended December 31, 2018. The fair value of the assets acquired totaled approximately $755 million , which was comprised of approximately $245 million of proved properties, approximately $480 million of unproved properties and approximately $30 million of other assets. The fair value of the assets received in the business combination approximated the fair value of assets disposed. Delaware Basin divestitures. In January 2018, the Company closed on two asset sales transactions of certain non-core assets in Reeves and Ward Counties, Texas, with combined proceeds of approximately $280 million . After direct transaction costs, the Company recorded a pre-tax gain of approximately $134 million , which is included in gain on disposition of assets, net on its consolidated statement of operations for the year ended December 31, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres. These divestitures completed a transaction structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended, that the Company entered into concurrent with its July 2017 Midland Basin acquisition, as further described below. Upon completion of the Reverse 1031 Exchange in January 2018, the assets and liabilities attributable to the acquisition that were held by the VIE were conveyed to the Company, and the VIE structure was dissolved. Nonmonetary transactions. During 2018, the Company completed multiple nonmonetary transactions. These transactions included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, the Company recorded pre-tax gains of approximately $15 million . During the year ended December 31, 2017 , the Company closed on the following transactions: Delaware Basin acquisition. In January and April 2017, the Company closed on the two-part acquisition in the northern Delaware Basin. As consideration for the entire acquisition, the Company paid approximately $160 million in cash, of which $43 million was held in escrow at December 31, 2016, and issued to the seller approximately 2.2 million shares of its common stock with an approximate value of $291 million . ACC divestiture. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. The Company and its joint venture partner entered into separate agreements to sell 100 percent of their respective ownership interests in ACC. After adjustments for debt and working capital, the Company received cash proceeds from the sale of approximately $801 million . After direct transaction costs, the Company recorded a pre-tax gain on disposition of assets of approximately $655 million which is included in gain on disposition of assets, net on its consolidated statement of operations for the year ended December 31, 2017. The Company’s net investment in ACC at the time of closing was approximately $129 million . Midland Basin acquisition. In July 2017, the Company completed an acquisition in the Midland Basin. As consideration for the acquisition, the Company paid approximately $595 million in cash. Concurrent with the acquisition, the Company entered into a transaction structured as a Reverse 1031 Exchange. In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operated the properties pursuant to a management agreement with the VIE. At December 31, 2017, the Company was determined to be the primary beneficiary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. The assets held by the VIE attributable to the acquisition were conveyed to the Company and the VIE structure terminated upon the completion of the Reverse 1031 Exchange. Nonmonetary transactions. During 2017, the Company completed multiple nonmonetary transactions. The transactions included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and as a result the Company recorded pre-tax gains totaling approximately $26 million .

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The Company’s asset retirement obligation transactions during the years ended December 31, 2019 , 2018 and 2017 are summarized in the table below: (in millions) Years Ended December 31, 2019 2018 2017 Asset retirement obligations, beginning of period $ 179 $ 141 $ 130 Liabilities incurred from new wells 7 4 2 Liabilities assumed in acquisitions 4 26 10 Accretion expense 10 10 8 Disposition of wells (66 ) (4 ) (1 ) Liabilities settled upon plugging and abandoning wells (7 ) (7 ) (5 ) Revision of estimates (a) 12 9 (3 ) Asset retirement obligations, end of period $ 139 $ 179 $ 141 (a) The revisions to the Company’s asset retirement obligation estimates for the years ended December 31, 2019 and 2018 were primarily due to increased costs in New Mexico.

Incentive plans

Incentive plans	12 Months Ended
	Dec. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Incentive plans	Incentive plans Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of its employees. During the years ended December 31, 2019 , 2018 and 2017 , the Company matched 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual eligible compensation, subject to federal limits. The Company’s contributions to the plan for the years ended December 31, 2019 , 2018 and 2017 were $15 million , $12 million and $10 million , respectively. Stock incentive plan. On May 16, 2019, the Company’s stockholders approved and adopted the Company’s 2019 Stock Incentive Plan (“the Plan”), which, among other things, increased the total shares authorized for issuance from 10.5 million to 15.0 million . At December 31, 2019 , the Company had 5.0 million shares of common stock available for future grants. Shares issued as a result of awards granted under the Plan are generally new common shares. Restricted stock awards. All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the year ended December 31, 2019 is presented below: Number of Restricted Shares Weighted Average Grant Date Fair Value Per Share Outstanding at December 31, 2018 1,364,699 $ 128.08 Shares granted 776,189 $ 98.83 Shares cancelled / forfeited (147,336 ) $ 113.69 Lapse of restrictions (508,200 ) $ 126.82 Outstanding at December 31, 2019 1,485,352 $ 113.74 For restricted stock awards granted, stock-based compensation expense is recognized in the Company’s consolidated financial statements on an accelerated basis over the awards’ vesting periods based on their grant date fair values. The restricted stock-based compensation awards generally vest over a period ranging from one to ten years . The Company utilizes the average of the high and low stock prices on the grant date for the fair value of restricted stock. The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Fair value for awards granted during the period (a) $ 77 $ 94 $ 60 Fair value for awards vested during the period $ 52 $ 54 $ 49 Stock-based compensation expense from restricted stock $ 63 $ 60 $ 43 Income tax benefit related to restricted stock $ 10 $ 14 $ 11 (a) The weighted average grant date fair value per share amounts were $98.83 , $137.31 and $123.16 for the years ended December 31, 2019 , 2018 and 2017 , respectively. Performance unit awards. During the years ended December 31, 2019 , 2018 and 2017 , the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. Other than the performance units with a five-year performance period described below, the performance period is typically 3 years . In January 2019, the Company granted 212,947 performance unit awards. Included in this grant were 38,952 performance unit awards granted to certain officers, of which 19,476 have a three -year performance period and 19,476 have a five -year performance period. For these 38,952 performance unit awards, at the end of each performance period, each of these performance unit awards will convert into a restricted stock award with the number of shares determined based upon performance criteria, which will then vest at a rate of 20 percent per year commencing on the sixth anniversary of the grant date. All other performance unit awards granted during 2019 will vest at the end of a three -year performance period. The grant date fair value is determined using the Monte Carlo simulation method and is expensed ratably over the performance period. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 Risk-free interest rate 2.45% - 2.47% 2.00% 1.47% Range of volatilities 23.3% - 50.0% 23.5% - 64.0% 24.8% - 60.2% The following table summarizes the performance unit activity for the year ended December 31, 2019 : Number of Units Grant Date Fair Value Performance units: Outstanding at December 31, 2018 218,391 $ 201.97 Units granted (a) 212,947 $ 144.03 Lapse of restrictions (b) (106,901 ) $ 187.31 Outstanding at December 31, 2019 324,437 $ 168.77 (a) Includes 38,952 performance unit awards granted to certain officers in January 2019 that may convert into shares of restricted stock awards at the end of each performance period that will be subject to additional vesting conditions. (b) On December 31, 2019 , the performance period ended for these performance units. Each unit converted into 0.38 shares representing 40,631 shares of common stock issued on January 2, 2020. The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Fair value for awards granted during the period (a) $ 31 $ 24 $ 20 Fair value for awards vested during the period $ 26 $ 68 $ 68 Stock-based compensation expense from performance units $ 22 $ 22 $ 17 Income tax benefit related to performance units $ 5 $ 14 $ 2 (a) The weighted average grant date fair value per unit amounts were $144.03 , $216.03 and $183.48 for the years ended December 31, 2019 , 2018 and 2017 , respectively. Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31, 2019 : (in millions) 2020 $ 61 2021 36 2022 12 2023 2 2024 1 Thereafter 2 Total $ 114

Disclosures about fair value me

Disclosures about fair value measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Disclosures about fair value measurements	Disclosures about fair value measurements The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy: Level 1 : Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 : Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures. Level 3 : Prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources ( i.e. , supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures. Financial Assets and Liabilities Measured at Fair Value The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31, 2019 and 2018 : (in millions) December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Assets: Derivative instruments $ 17 $ 17 $ 695 $ 695 Liabilities: Derivative instruments $ 119 $ 119 $ — $ — Credit facility $ — $ — $ 242 $ 242 $600 million 4.375% senior notes due 2025 (a) $ 595 $ 620 $ 594 $ 591 $1,000 million 3.75% senior notes due 2027 (a) $ 990 $ 1,054 $ 989 $ 939 $1,000 million 4.3% senior notes due 2028 (a) $ 989 $ 1,091 $ 988 $ 980 $800 million 4.875% senior notes due 2047 (a) $ 789 $ 941 $ 789 $ 761 $600 million 4.85% senior notes due 2048 (a) $ 592 $ 697 $ 592 $ 573 (a) The carrying value includes associated deferred loan costs and any discount. Credit facility. The carrying amount of the Company’s amended and restated credit facility (“Credit Facility”) approximates its fair value, as the applicable interest rates are variable and reflective of market rates. Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy. Other financial assets and liabilities . The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments. Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, 2019 and 2018 . The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets. December 31, 2019 Fair Value Measurements Using Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets Current: Commodity derivatives $ — $ 108 $ — $ 108 $ (102 ) $ 6 Noncurrent: Commodity derivatives — 31 — 31 (20 ) 11 Liabilities Current: Commodity derivatives — (214 ) — (214 ) 102 (112 ) Noncurrent: Commodity derivatives — (27 ) — (27 ) 20 (7 ) Net derivative instruments $ — $ (102 ) $ — $ (102 ) $ — $ (102 ) December 31, 2018 Fair Value Measurements Using Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets Current: Commodity derivatives $ — $ 543 $ — $ 543 $ (59 ) $ 484 Noncurrent: Commodity derivatives — 243 — 243 (32 ) 211 Liabilities Current: Commodity derivatives — (59 ) — (59 ) 59 — Noncurrent: Commodity derivatives — (32 ) — (32 ) 32 — Net derivative instruments $ — $ 695 $ — $ 695 $ — $ 695 Concentrations of credit risk. At December 31, 2019 , the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. See Note 13 for information regarding the Company’s major customers and derivative counterparties. The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 9 for additional information regarding the Company’s derivative activities. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Impairments of long-lived assets. The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. At June 30, 2019, the carrying amount of the proved properties of the Company’s Yeso field exceeded the expected undiscounted future net cash flows resulting in an impairment charge against earnings of $868 million , reducing the carrying value of the Yeso field to its estimated fair value of $968 million . This impairment charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets and was attributable primarily to certain downward adjustments to the Company’s economically recoverable proved oil and natural gas reserves. Additionally, during the third quarter of 2019, the Company further impaired the Yeso Field due to the decrease in future commodity prices and recorded an additional impairment charge of $20 million . These impairment charges were included in impairments of long-lived assets on the consolidated statement of operations for the year ended December 31, 2019 . At December 31, 2019 , the expected undiscounted future net cash flows were greater than the carrying amounts of the Company’s assets and no additional impairment was recorded. The assumptions used in calculating the estimated fair value of the Yeso field at June 30, 2019 and the Company’s assets at December 31, 2019 are below. The Company calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At June 30, 2019, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which were based on the NYMEX strip, ranged from a 2019 price of $58.32 per barrel of oil decreasing to a 2022 price of $53.58 then rising to a 2026 price of $54.47 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.38 per Mcf of natural gas increasing to a 2026 price of $2.99 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2026. At December 31, 2019 , the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2020 price of $58.83 per barrel of oil decreasing to a 2023 price of $51.31 per barrel of oil then rising to a 2026 price of $52.57 per barrel of oil. Natural gas prices ranged from a 2020 price of $2.29 per Mcf of natural gas increasing to a 2026 price of $2.55 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after 2026. The Company did not recognize any impairment loss during the years ended December 31, 2018 or 2017. The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, and (v) a market-based weighted average cost of capital. The Company utilized a combination of the NYMEX strip pricing and consensus pricing, adjusted for differentials, to value the reserves. These are classified as Level 3 fair value assumptions. At June 30, 2019, the Company’s estimate of commodity prices for purposes of determining discounted future cash flows ranged from a 2019 price of $58.32 per barrel of oil increasing to a 2026 price of $62.06 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.38 per Mcf of natural gas increasing to a 2026 price of $3.00 per Mcf of natural gas. These prices were then adjusted for location and quality differentials. Both oil and natural gas commodity prices for this purpose were inflated by two percent each year after 2026. The expected future net cash flows were discounted using a rate of 10 percent . At December 31, 2019 , the Company’s estimate of commodity prices for purposes of determining discounted future cash flows ranged from a 2020 price of $58.83 per barrel of oil decreasing to a 2021 price of $54.38 per barrel of oil then rising to a 2026 price of $59.01 per barrel of oil. Natural gas prices ranged from a 2020 price of $2.29 per Mcf of natural gas increasing to a 2026 price of $2.63 per Mcf of natural gas. These prices were then adjusted for location and quality differentials. Both oil and natural gas commodity prices for this purpose were inflated by two percent each year after 2026. The expected future net cash flows were discounted using a rate of 10 percent . It is reasonably possible that the estimate of undiscounted future net cash flows of the Company’s long-lived assets may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity prices including differentials, (ii) increases or decreases in production and capital costs, (iii) future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities, and (v) changes in income and expenses from integrated assets. Assets held for sale. The Company’s Yeso field was primarily composed of the New Mexico Shelf assets that the Company sold in November 2019. The assets and liabilities associated with the New Mexico Shelf divestiture were classified as held for sale at August 29, 2019 and were measured at their estimated fair value less cost to sell. The related fair value at August 29, 2019 was based upon anticipated sales proceeds less costs to sell. Because the Company’s closing and post-closing adjustments, primarily revenues and operating expenses, used to calculate the fair value less costs to sell were estimates that were both significant and unobservable, they were considered Level 3 fair value measurements. This transaction closed in November 2019 for total proceeds of $837 million , subject to additional post-closing adjustments. Refer to Note 5

Derivative financial instrument

Derivative financial instruments	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative financial instruments	Derivative financial instruments The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. At December 31, 2019 , the Company’s derivative financial instruments consisted of oil and natural gas swaps and basis swaps. Swap contracts allow the Company to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. Basis swap contracts allow the Company to receive a fixed price differential between market indices for the price of oil or natural gas. In connection with the RSP Acquisition, the Company assumed certain oil collar and three-way collar contracts. In these contracts, each collar has an established floor price and ceiling price, and certain collars also include a short put price (three-way collars). When the settlement price is below the established floor price, the Company receives an amount from its counterparty equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is above the established ceiling price, the Company pays its counterparty an amount equal to the difference between the settlement price and the ceiling price multiplied by the hedged contract volume. When the settlement price is between the established floor and the ceiling, no amounts are due to or from the counterparty. In case of a three-way collar, when the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the floor price and the short put price multiplied by the hedged contract volume. The Company had no outstanding collars or three-way collars at December 31, 2019. The Company also enters into fixed-price forward physical power purchase contracts to manage the volatility of the price of power needed for ongoing operations. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical contracts are not expected to be net cash settled, the Company has elected normal purchase or normal sale treatment and records these contracts at cost. The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its consolidated statements of operations as they occur. The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Gain (loss) on derivatives: Oil derivatives $ (1,003 ) $ 848 $ (172 ) Natural gas derivatives 108 (16 ) 46 Total $ (895 ) $ 832 $ (126 ) The following table represents the Company’s net cash receipts from (payments on) derivatives for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Net cash receipts from (payments on) derivatives: Oil derivatives $ (129 ) $ (213 ) $ 79 Natural gas derivatives 31 (5 ) — Total $ (98 ) $ (218 ) $ 79 Commodity derivative contracts. The following table sets forth the Company’s outstanding derivative contracts at December 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at December 31, 2019 are expected to settle by December 31, 2021. 2020 First Quarter Second Quarter Third Quarter Fourth Quarter Total 2021 Oil Price Swaps – WTI: (a) Volume (MBbl) 14,674 12,494 11,080 10,045 48,293 18,612 Price per Bbl $ 57.13 $ 56.90 $ 56.88 $ 57.00 $ 56.98 $ 54.19 Oil Price Swaps – Brent: (b) Volume (MBbl) 2,578 2,031 1,768 1,503 7,880 — Price per Bbl $ 60.78 $ 60.33 $ 60.29 $ 60.14 $ 60.43 $ — Oil Basis Swaps: (c) Volume (MBbl) 14,951 11,284 10,856 10,120 47,211 18,980 Price per Bbl $ (0.43 ) $ (0.56 ) $ (0.62 ) $ (0.71 ) $ (0.57 ) $ 0.64 Natural Gas Price Swaps – Henry Hub: (d) Volume (BBtu) 35,023 32,314 30,038 28,498 125,873 40,150 Price per MMBtu $ 2.46 $ 2.46 $ 2.47 $ 2.47 $ 2.47 $ 2.52 Natural Gas Basis Swaps – Henry Hub/El Paso Permian: (e) Volume (BBtu) 25,770 23,960 22,080 21,770 93,580 36,500 Price per MMBtu $ (1.06 ) $ (1.07 ) $ (1.07 ) $ (1.07 ) $ (1.07 ) $ (0.66 ) Natural Gas Basis Swaps – Henry Hub/WAHA: (f) Volume (BBtu) 7,280 7,280 7,360 7,360 29,280 10,950 Price per MMBtu $ (1.10 ) $ (1.10 ) $ (1.10 ) $ (1.10 ) $ (1.10 ) $ (0.66 ) (a) These oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price. (b) These oil derivative contracts are settled based on the Brent calendar-month average futures price. (c) The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis. (d) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price. (e) The basis differential price is between NYMEX – Henry Hub and El Paso Permian. (f) The basis differential price is between NYMEX – Henry Hub and WAHA. Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. The Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company. In September 2017, the Company elected to enter into an “Investment Grade Period,” as defined in Note 10 , under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See Note 10 for additional information regarding the Credit Facility.

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt The Company’s debt consisted of the following at December 31, 2019 and 2018 : (in millions) December 31, 2019 2018 Credit facility due 2022 $ — $ 242 4.375% unsecured senior notes due 2025 (a) 600 600 3.75% unsecured senior notes due 2027 1,000 1,000 4.3% unsecured senior notes due 2028 1,000 1,000 4.875% unsecured senior notes due 2047 800 800 4.85% unsecured senior notes due 2048 600 600 Unamortized original issue discount (9 ) (10 ) Senior notes issuance costs, net (36 ) (38 ) Less: current portion — — Total long-term debt $ 3,955 $ 4,194 (a) For each of the twelve month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are callable at 103.281% , 102.188% , 101.094% and 100% , respectively. Credit Facility. The Credit Facility has a maturity date of May 9, 2022 . At December 31, 2019 , the Company’s commitments from its bank group were $2.0 billion . In April 2017, the Company amended the Credit Facility to extend the maturity date and decrease unused lender commitments. The amendment also lowered the corporate ratings floor sufficient to automatically terminate an Investment Grade Period under the Credit Facility from (i) “Ba1” to “Ba2” for Moody’s Investors Service, Inc. (“Moody’s”) and (ii) “BB+” to “BB” for S&P Global Ratings (“S&P”). In September 2017, the Company elected to enter into an Investment Grade Period under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of the Company’s credit ratings below certain thresholds or by the Company’s election), the Credit Facility will once again be secured by a first lien on substantially all of the Company’s oil and natural gas properties and by a pledge of the equity interests in its subsidiaries. At December 31, 2019 , certain of the Company’s 100 percent owned subsidiaries were guarantors under the Credit Facility. During an Investment Grade Period, advances on the Credit Facility bear interest, at the Company’s option, based on (i) an alternative base rate, which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank ( 4.8 percent at December 31, 2019 ), (b) the federal funds effective rate plus 0.5 percent and (c) LIBOR plus 1.0 percent or (ii) LIBOR. The Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on the Company’s credit ratings from Moody’s and S&P. At the Company’s current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum. During the years ended December 31, 2019 , 2018 and 2017 , the Company incurred commitment fees on the unused portion of the available commitments of $4 million , $5 million and $6 million , respectively. The Company had $2.0 billion of unused commitments under the Credit Facility at December 31, 2019 . The Credit Facility contains various restrictive covenants and compliance requirements, which include: • maintenance of certain financial ratios, including maintenance of a quarterly ratio of consolidated total debt to consolidated earnings, as defined, before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other non-cash income and expenses to be no greater than 4.25 to 1.0, and during an Investment Grade Period, if the Company does not have both a rating of “Baa3” or better from Moody’s and a rating of “BBB-” or better from S&P, maintenance of a quarterly ratio of PV-9 of the Company’s oil and natural gas properties reflected in its most recently delivered reserve report to consolidated total debt to be no less than 1.50 to 1.0; • limits on the incurrence of additional indebtedness and certain types of liens; • restrictions as to mergers, combinations and dispositions of assets; and • restrictions on the payment of cash dividends. Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note 18 , and rank equally in right of payments with one another. On July 2, 2018, the Company issued $1,600 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 4.3% unsecured senior notes due 2028 (the “4.3% Notes”) and $600 million in aggregate principal amount of 4.85% unsecured senior notes due 2048 (the “4.85% Notes” and, together with the 4.3% Notes, the “Notes”). The 4.3% Notes were issued at a price equal to 99.660 percent of par, and the 4.85% Notes were issued at a price equal to 99.740 percent of par. The net proceeds of $1,579 million were used to redeem and cancel all of RSP’s outstanding $700 million aggregate principal amount of 6.625% unsecured senior notes due 2022 (the “RSP 2022 Notes”) and $450 million aggregate principal amount of 5.25% unsecured senior notes due 2025 (the “RSP 2025 Notes” and, together with the RSP 2022 Notes, the “RSP Notes”). The Company made aggregate payments of approximately $1.2 billion to redeem and cancel the RSP Notes, including make-whole call premiums of $35 million and $33 million for the RSP 2022 Notes and RSP 2025 Notes, respectively. The Company also paid accrued interest of $14 million on the RSP Notes. The remaining proceeds, along with borrowings under the Credit Facility, were used to repay the $540 million of outstanding principal under RSP’s revolving credit facility, including $1 million in accrued interest. See Note 4 for additional information regarding the RSP Acquisition. In September 2017, the Company issued $1,800 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “2017 Notes”). The 3.75% Notes were issued at a price equal to 99.636 percent of par, and the 4.875% Notes were issued at a price equal to 99.749 percent of par. The Company received net proceeds of $1,777 million . Additionally, in September 2017, the Company completed a cash tender offer (the “Tender Offer”) to purchase any and all of the outstanding $600 million aggregate principal amount of its 5.5% unsecured senior notes due 2022 and the outstanding $1,550 million aggregate principal amount of its 5.5% unsecured senior notes due 2023 (collectively, the “5.5% Notes”). The Company received tenders from the holders of $1,232 million in aggregate principal amount, or approximately 57.3 percent, of its outstanding 5.5% Notes in connection with the Tender Offer at a price of 102.934 percent of the unpaid principal amount plus accrued and unpaid interest to the settlement date. In connection with the Tender Offer, the Company redeemed the remaining outstanding 5.5% Notes not purchased in the Tender Offer at a price, including the make-whole premium as determined in accordance with the indentures, of 102.75 percent of the unpaid principal amount plus accrued and unpaid interest. Additionally in September 2017, the Company completed a satisfaction and discharge of the redeemed notes, where the Company prepaid interest to October 13, 2017. The Company used the net proceeds from the offering of the 2017 Notes, together with cash on hand and borrowings under its Credit Facility, to fund the Tender Offer and the redemption of its obligations under the indentures of the 5.5% Notes. As a result of these transactions, the Company recorded a loss on extinguishment of debt of $65 million for the year ended December 31, 2017. At December 31, 2019 , the Company was in compliance with the covenants under all of its debt instruments. Principal maturities of long-term debt. Principal maturities of long-term debt outstanding at December 31, 2019 were as follows: (in millions) 2020 $ — 2021 — 2022 — 2023 — 2024 — Thereafter 4,000 Total $ 4,000 Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Cash payments for interest $ 207 $ 118 $ 139 Non-cash interest 6 5 6 Net changes in accruals (9 ) 34 4 Interest costs incurred 204 157 149 Less: capitalized interest (19 ) (8 ) (3 ) Total interest expense $ 185 $ 149 $ 146

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies Severance agreements. The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total $10 million . Indemnifications . The Company has agreed to indemnify its directors and officers with respect to claims and damages arising from certain acts or omissions taken in such capacity. Legal actions . The Company is a party to proceedings and claims incidental to its business. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter. For material matters that the Company believes an unfavorable outcome is reasonably possible, it would disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. The Company does not believe that the loss for any other litigation matters and claims that are reasonably possible to occur will have a material adverse effect on its financial position, results of operations or liquidity. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any estimated accruals as appropriate. Severance tax, royalty and joint interest audits . The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. Regulatory and environmental compliance. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs. At December 31, 2019 and 2018 , the Company had regulatory and environmental liabilities of $10 million and $26 million , respectively, which are included in other current liabilities on the accompanying consolidated balance sheets. During the years ended December 31, 2019 , 2018 and 2017 , the Company recognized regulatory and environmental charges of $13 million , $23 million and $9 million , respectively, which are included in oil and natural gas production expense in the accompanying consolidated statements of operations. Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into, which includes throughput volume delivery commitments, fixed and variable power commitments, water commitment agreements, sand commitment agreements and other commitments. The Company’s drilling rig commitments are considered leases under ASU 2016-02 and are discussed in the “Leases” section below. The following table summarizes the Company’s commitments at December 31, 2019 : (in millions) Volume Delivery Commitments (b) Power Commitments (a) Other Commitments Total 2020 $ 8 $ 14 $ 29 $ 51 2021 19 14 38 71 2022 19 14 5 38 2023 19 14 2 35 2024 19 14 2 35 Thereafter 54 44 5 103 Total $ 138 $ 114 $ 81 $ 333 (a) Certain power commitments include a variable price component that is based on the last day settlement price of the NYMEX futures contract for the physical delivery period. (b) Volume delivery commitments do not include the oil marketing contract discussed in the table below. At December 31, 2019 , the Company’s delivery commitments covered the following gross volumes of oil and natural gas: Oil (in MMBbl) (a) Natural Gas (in MMcf) 2020 43 371 2021 51 7,267 2022 53 16,425 2023 51 16,425 2024 47 16,470 Thereafter 114 32,850 Total 359 89,808 (a) Included in the table above is an oil marketing contract with a third-party purchaser that requires the Company to deliver fifty thousand barrels of oil per day. Leases. The Company leases office space, office equipment, drilling rigs, field equipment and vehicles. Right-of-use assets and lease liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. Leased assets may be used in joint operations with other working interest owners. When the Company is the operator in a joint arrangement, the right-of-use assets and lease liabilities are determined on a gross basis. Certain leases contain variable costs above the minimum required payments and are not included in the right-of-use assets or lease liabilities. Options to extend or terminate a lease are included in the lease term when it is reasonably certain the Company will exercise that option. For operating leases, lease cost is recognized on a straight-line basis over the term of the lease. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheet. The Company elected a practical expedient to not separate non-lease components from lease components for the following asset types: office space, office equipment, drilling rigs, and field equipment. The Company did not elect this practical expedient for vehicle leases. The following table provides supplemental consolidated balance sheet information related to leases at December 31, 2019 : (in millions) Classification December 31, 2019 Assets Operating lease right-of-use assets Other property and equipment, net $ 15 Finance lease right-of-use assets Other property and equipment, net 16 Total lease right-of-use assets (a) $ 31 Liabilities Current: Operating Other current liabilities $ 8 Finance Other current liabilities 7 Noncurrent: Operating Asset retirement obligations and other long-term liabilities 9 Finance Asset retirement obligations and other long-term liabilities 10 Total lease liabilities (a) $ 34 (a) Total lease right-of-use assets and lease liabilities are gross amounts, and a portion of these costs will be reimbursed by other working interest owners. As of December 31, 2019 , the Company had additional operating leases that have not yet commenced. Future undiscounted lease payments of $15 million and estimated lease incentives of $5 million will be included in the determination of the right-of-use asset and lease liability upon lease commencement. The following table provides the components of lease cost, excluding lease cost related to short-term leases, for the year ended December 31, 2019 : (in millions) Classification December 31, 2019 Operating lease cost General and administrative $ 7 Finance lease cost Depreciation, depletion, and amortization (a) 8 Total lease cost $ 15 (a) Interest on lease liabilities related to finance leases was immaterial during the year ended December 31, 2019. The Company’s short-term leases are primarily composed of drilling rigs and certain field equipment. During the year ended December 31, 2019 , the Company’s gross lease costs related to its short-term leases were $307 million , of which $207 million were capitalized as part of oil and natural gas properties. A portion of these costs was reimbursed to the Company by other working interest owners. The following table summarizes supplemental cash flow information related to leases for the year ended December 31, 2019 : (in millions) December 31, 2019 Cash paid for amounts included in measurement of lease liabilities: Operating cash flows from operating leases $ 8 Financing cash flows from finance leases $ 7 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 3 Finance leases $ 9 The following table provides lease terms and discount rates related to leases at December 31, 2019 : December 31, 2019 Weighted average remaining lease term (years): Operating leases 3.2 Finance leases 2.8 Weighted average discount rate (a): Operating leases 4.7 % Finance leases 4.2 % (a) The Company uses the rate implicit in the contract, if readily determinable, or its incremental borrowing rate at the commencement date as the discount rate in determining the present value of the lease payments. The following table provides maturities of lease liabilities at December 31, 2019 : (in millions) Operating Leases Finance Leases 2020 $ 8 $ 7 2021 7 6 2022 2 4 2023 — 1 2024 — — Thereafter 2 — Total lease payments 19 18 Less: interest (2 ) (1 ) Present value of lease liabilities $ 17 $ 17 As discussed in Note 2, the Company elected a transition method to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. Per ASU 2016-02, an entity electing this transition method should provide the required disclosures under Topic 840 for all periods that continue to be in accordance with Topic 840. As such, the Company included the future minimum lease commitments table below as of December 31, 2018. In addition, lease payments associated with these operating leases were $13 million and $10 million for the years ended December 31, 2018 and 2017 , respectively. Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows: (in millions) 2019 $ 14 2020 12 2021 10 2022 3 2023 — Thereafter 1 Total $ 40

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income taxes	Income taxes The Company uses an asset and liability approach for financial accounting and reporting for income taxes. The Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) the deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Current: U.S. federal $ — $ — $ (6 ) U.S. state — (2 ) 2 Total current income tax benefit — (2 ) (4 ) Deferred: U.S. federal (112 ) 547 (94 ) U.S. state (42 ) 58 23 Total deferred income tax expense (benefit) (154 ) 605 (71 ) Total income tax expense (benefit) $ (154 ) $ 603 $ (75 ) The reconciliation between the income tax expense (benefit) computed by multiplying pre-tax income (loss) by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) is as follows: (in millions) Years Ended December 31, 2019 2018 2017 Income (loss) at U.S. federal statutory rate $ (180 ) $ 607 $ 308 Non-deductible goodwill 64 — — Enactment date and measurement period adjustments from the TCJA — (7 ) (398 ) State income taxes and enacted tax law changes, net of federal tax effect (13 ) 52 17 Change in estimated effective statutory state income tax rate (21 ) (8 ) — Excess tax benefit due to stock-based compensation — (12 ) (6 ) Research and development credits, net of unrecognized tax benefits (11 ) (41 ) — Other 7 12 4 Income tax expense (benefit) $ (154 ) $ 603 $ (75 ) Effective tax rate 18 % 21 % (9 )% On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to federal income tax laws, including a decrease in the federal corporate income tax rate from 35 percent to 21 percent , which was effective January 1, 2018. In accordance with SAB 118, the Company recorded, based on reasonable estimates, a $398 million decrease to its income tax provision at December 31, 2017. This provisional amount related to the re-measurement of certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future. At December 31, 2018, the Company completed its accounting for all of the enactment-date tax effects of the TCJA and recognized an adjustment of $7 million , which is included as a component of income tax expense. The Company monitors changes in enacted tax rates for the jurisdictions in which it operates. During 2019, the state of New Mexico enacted a tax law which, among other changes, amended the apportioned net operating loss (“NOL”) carryforwards for corporations. As a result of this law change, the Company recorded a deferred state tax benefit of $6 million for the year ended December 31, 2019. The Company monitors its state tax apportionment footprint and makes updates for changes in its projected activity, including changes in budgets and drilling plans, and changes as a result of acquisitions or divestitures, including the New Mexico Shelf divestiture in 2019. Based upon the Company’s projected future activity for the states in which it conducts business, the timing for when it anticipates its deferred tax items to become taxable, the enacted tax rates at such time deferred items become taxable and the New Mexico tax law change discussed above, the Company revised its estimated state tax rate for the year ended December 31, 2019. As a result, the Company recorded an income tax benefit of $21 million in its income tax provision for the year ended December 31, 2019. The Company revised its estimated state tax rate during 2018, primarily due to the impact of the RSP Acquisition. As a result, the Company recorded an income tax benefit of $8 million , net of federal tax benefit, in its income tax provision for the year ended December 31, 2018. The Company did not revise its estimated state rate and, as such, did not record an additional deferred state tax benefit for the year ended December 31, 2017. The Company recorded an income tax benefit of $12 million and $6 million for the years ended December 31, 2018 and 2017, respectively, related to an excess tax benefit on stock-based awards, which are recorded in the income tax provision pursuant to ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-based Payment Accounting,” (“ASU 2016-09”) adopted on January 1, 2017. The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows: (in millions) December 31, 2019 2018 Deferred tax assets: Stock-based compensation $ 24 $ 26 Derivative instruments 23 — Asset retirement obligation 31 41 Net operating losses and other carryforwards 590 525 Research and development and other credits 73 61 Other 22 17 Total deferred tax assets 763 670 Less: Valuation allowance (4 ) (3 ) Net deferred tax assets 759 667 Deferred tax liabilities: Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes (2,318 ) (2,270 ) Equity method investments (83 ) — Intangible assets - operating rights (4 ) (4 ) Derivative instruments — (158 ) Other (8 ) (43 ) Total deferred tax liabilities (2,413 ) (2,475 ) Net deferred tax liabilities $ (1,654 ) $ (1,808 ) The Company had net deferred tax liabilities of approximately $1.7 billion and $1.8 billion as of December 31, 2019 and 2018 , respectively. On July 19, 2018, the Company completed the RSP Acquisition. For federal income tax purposes, the transaction qualified as a tax-free merger whereby the Company acquired carryover tax basis in RSP’s assets and liabilities. As of December 31, 2018, the Company recorded an opening balance sheet deferred tax liability of $515 million based on its assessment of the carryover tax basis, and includes a deferred tax asset related to tax attributes acquired from RSP. The acquired income tax attributes primarily consist of NOLs and research and development credits that are subject to an annual limitation under Internal Revenue Code Section 382. The Company expects that these tax attributes will be fully utilized prior to expiration. Pursuant to management’s assessment, the Company does not believe a cumulative ownership change had occurred as of December 31, 2019 . As such, Section 382 of the Internal Revenue Code of 1986, as amended, is not expected to limit the Company’s ability to utilize its NOL carryforward. At December 31, 2019 , the Company had approximately $2.6 billion of federal NOLs, net of reduction for unrecognized tax benefits. At December 31, 2019 , the Company had approximately $1.5 billion of NOLs that will begin to expire in the tax year 2034 but are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of the limitations imposed by the TCJA. Additionally, the Company has estimated an apportioned New Mexico NOL of $749 million that will begin to expire in 2036. Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s NOLs and other deferred tax attributes will be utilized prior to their expiration. Management considered all factors, including the expected reversal of deferred tax liabilities (including the impact of available carryforward periods), historical operating income tax planning strategies and projected future taxable income. Based on the results of the assessment, a valuation allowance of $4 million and $3 million was recorded at December 31, 2019 and 2018 , respectively, related to charitable contribution carryforwards not anticipated to be utilized prior to expiration. Management determined that it is more likely than not that the Company will realize its remaining deferred tax assets. The following table sets forth changes in the Company’s unrecognized tax benefits: (in millions) December 31, 2019 December 31, 2018 Balance at beginning of year $ 72 $ — Additions for tax positions acquired — 26 Additions for prior period tax positions — 20 Reductions for prior period tax positions (1 ) — Additions for current tax period positions 11 26 Balance at end of year $ 82 $ 72 Total that, if recognized, would impact the effective income tax rate $ 74 $ 63 The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. The Company had unrecognized tax benefits primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain. The Company does not expect that a change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements. The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2014.

Major customers and derivative

Major customers and derivative counterparties	12 Months Ended
	Dec. 31, 2019
Major Customer Disclosure [Abstract]
Major customers and derivative counterparties	Major customers and derivative counterparties Sales to major customers. The Company’s share of oil and natural gas production is sold to various purchasers. The Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production. The following purchasers individually accounted for 10 percent or more of the Company’s consolidated oil and natural gas revenues during the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 Plains Marketing and Transportation, Inc. 17 % 18 % 21 % Enterprise Crude Oil LLC 10 % (a) (a) Holly Frontier Refining and Marketing, LLC (a) (a) 10 % (a) Purchaser did not account for 10% or more of total revenue for the period. Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. The Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company.

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related party transactions	Note 14. Related party transactions The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest. These payments were reported in the Company’s consolidated statements of operations and totaled $7 million , $8 million and $7 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. At December 31, 2019 , the Company had ownership interests in entities that operate and manage various infrastructure assets and accounts for these investments using the equity method. The Company made payments of $40 million to these entities and received payments of $3 million from these entities during the year ended December 31, 2019

Earnings per share

Earnings per share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Earnings per share	Earnings per share The Company uses the two-class method of calculating earnings per share because certain of the Company’s unvested share-based awards qualify as participating securities. The Company’s basic earnings (loss) per share attributable to common stockholders is computed as (i) net income (loss) as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings (loss) per share attributable to common stockholders is computed as (i) basic earnings (loss) attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding. The following table reconciles the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the years ended December 31, 2019 , 2018 and 2017 , respectively, under the two-class method: (in millions, except per share amounts) Years Ended December 31, 2019 2018 2017 Net income (loss) as reported $ (705 ) $ 2,286 $ 956 Participating basic earnings (a) (1 ) (17 ) (7 ) Basic earnings attributable to common stockholders (706 ) 2,269 949 Reallocation of participating earnings — — — Diluted earnings attributable to common stockholders $ (706 ) $ 2,269 $ 949 (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so. The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2019 , 2018 and 2017 : (in thousands) Years Ended December 31, 2019 2018 2017 Weighted average common shares outstanding: Basic 198,984 170,925 147,320 Dilutive common stock options — — 3 Dilutive performance units — 324 633 Diluted 198,984 171,249 147,956 The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive: (in thousands) Years Ended December 31, 2019 2018 2017 Number of antidilutive common shares: Antidilutive performance units 431 108 81

Stockholders' equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Stockholders' equity	Stockholders’ equity Share repurchase program. In September 2019, the Company announced that its board of directors authorized the initiation of a share repurchase program for up to $1.5 billion of the Company’s common stock. A portion of the proceeds from the New Mexico Shelf divestiture was used to initiate the share repurchase program. As of December 31, 2019 , the Company had repurchased and retired 3,300,370 shares under the program at an aggregate cost of $250 million . The Company’s share repurchase program may be modified, suspended or terminated at any time by the Company’s board of directors. The Company is not obligated to acquire any specific number of shares. Common stock dividends. The Company paid dividends of $100 million , or $0.50 per share, during the year ended December 31, 2019 . Any payment of future dividends will be at the discretion of the Company’s board of directors. Covenants contained in the Company’s agreement governing its Credit Facility and the indentures governing the Company’s senior notes could limit the payment of dividends.

Other current liabilities

Other current liabilities	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other current liabilities	Other current liabilities The following table provides the components of the Company’s other current liabilities at December 31, 2019 and 2018 : (in millions) December 31, 2019 2018 Other current liabilities: Accrued production costs $ 175 $ 135 Payroll related matters 37 49 Accrued interest 60 70 Settlements due on derivatives 38 — Asset retirement obligations 9 11 Other 44 55 Other current liabilities $ 363 $ 320

Subsidiary guarantors

Subsidiary guarantors	12 Months Ended
	Dec. 31, 2019
Guarantees [Abstract]
Subsidiary guarantors	Subsidiary guarantors At December 31, 2019 , certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee. See Note 10 for a summary of the Company’s senior notes. In accordance with practices accepted by the SEC, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, certain of the Company’s subsidiaries do not guarantee the Company’s senior notes and are included in the Company’s consolidated financial statements. These entities are 100 percent owned subsidiaries and are referred to as “Subsidiary Non-Guarantors” in the tables below. An additional entity did not guarantee the Company’s senior notes at December 31, 2017. This entity was a VIE that was formed to effectuate a tax-free exchange of assets. During 2018, the Reverse Exchange 1031 was completed and all assets and liabilities attributable to the VIE were conveyed to the Company. This entity did not guarantee the Company’s senior notes until the conveyance was completed. See Note 5 for additional information regarding the completion of the Reverse 1031 Exchange. The following condensed consolidating balance sheets at December 31, 2019 and 2018 , condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2019 , 2018 and 2017 , present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company. Condensed Consolidating Balance Sheet (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total ASSETS Accounts receivable - related parties $ 17,429 $ — $ — $ (17,429 ) $ — Other current assets 10 1,045 — — 1,055 Oil and natural gas properties, net — 20,874 16 — 20,890 Property and equipment, net — 437 — — 437 Investment in subsidiaries 5,635 — — (5,635 ) — Goodwill — 1,917 — — 1,917 Other long-term assets 22 411 — — 433 Total assets $ 23,096 $ 24,684 $ 16 $ (23,064 ) $ 24,732 LIABILITIES AND EQUITY Accounts payable - related parties $ — $ 17,413 $ 16 $ (17,429 ) $ — Other current liabilities 211 971 — — 1,182 Long-term debt 3,955 — — — 3,955 Other long-term liabilities 1,148 665 — — 1,813 Equity 17,782 5,635 — (5,635 ) 17,782 Total liabilities and equity $ 23,096 $ 24,684 $ 16 $ (23,064 ) $ 24,732 Condensed Consolidating Balance Sheet (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total ASSETS Accounts receivable - related parties $ 18,155 $ — $ — $ (18,155 ) $ — Other current assets 534 875 — — 1,409 Oil and natural gas properties, net — 21,988 17 — 22,005 Property and equipment, net — 308 — — 308 Investment in subsidiaries 5,411 — — (5,411 ) — Goodwill — 2,224 — — 2,224 Other long-term assets 224 124 — — 348 Total assets $ 24,324 $ 25,519 $ 17 $ (23,566 ) $ 26,294 LIABILITIES AND EQUITY Accounts payable - related parties $ — $ 18,138 $ 17 $ (18,155 ) $ — Other current liabilities 70 1,286 — — 1,356 Long-term debt 4,194 — — — 4,194 Other long-term liabilities 1,292 684 — — 1,976 Equity 18,768 5,411 — (5,411 ) 18,768 Total liabilities and equity $ 24,324 $ 25,519 $ 17 $ (23,566 ) $ 26,294 Condensed Consolidating Statement of Operations (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Total operating revenues $ — $ 4,591 $ 1 $ — $ 4,592 Total operating costs and expenses (898 ) (4,681 ) — — (5,579 ) Income (loss) from operations (898 ) (90 ) 1 — (987 ) Interest expense (185 ) — — — (185 ) Other, net 224 313 — (224 ) 313 Income (loss) before income taxes (859 ) 223 1 (224 ) (859 ) Income tax benefit 154 — — — 154 Net income (loss) $ (705 ) $ 223 $ 1 $ (224 ) $ (705 ) Condensed Consolidating Statement of Operations (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Total operating revenues $ — $ 4,146 $ 5 $ — $ 4,151 Total operating costs and expenses 829 (2,047 ) (3 ) — (1,221 ) Income from operations 829 2,099 2 — 2,930 Interest expense (149 ) — — — (149 ) Other, net 2,209 108 — (2,209 ) 108 Income before income taxes 2,889 2,207 2 (2,209 ) 2,889 Income tax expense (603 ) — — — (603 ) Net income $ 2,286 $ 2,207 $ 2 $ (2,209 ) $ 2,286 Condensed Consolidating Statement of Operations (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Consolidating Entries Total Total operating revenues $ — $ 2,566 $ 20 $ — $ 2,586 Total operating costs and expenses (129 ) (1,369 ) (17 ) — (1,515 ) Income (loss) from operations (129 ) 1,197 3 — 1,071 Interest expense (145 ) (1 ) — — (146 ) Loss on extinguishment of debt (66 ) — — — (66 ) Other, net 1,221 22 — (1,221 ) 22 Income before income taxes 881 1,218 3 (1,221 ) 881 Income tax benefit 75 — — — 75 Net income $ 956 $ 1,218 $ 3 $ (1,221 ) $ 956 Condensed Consolidating Statement of Cash Flows (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Net cash flows provided by operating activities $ 607 $ 2,229 $ — $ — $ 2,836 Net cash flows used in investing activities — (1,993 ) — — (1,993 ) Net cash flows used in financing activities (607 ) (166 ) — — (773 ) Net change in cash and cash equivalents — 70 — — 70 Cash and cash equivalents at beginning of period — — — — — Cash and cash equivalents at end of period $ — $ 70 $ — $ — $ 70 Condensed Consolidating Statement of Cash Flows (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Net cash flows provided by operating activities $ 338 $ 2,220 $ — $ — $ 2,558 Net cash flows used in investing activities — (2,216 ) — — (2,216 ) Net cash flows used in financing activities (338 ) (4 ) — — (342 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — — — — — Cash and cash equivalents at end of period $ — $ — $ — $ — $ — Condensed Consolidating Statement of Cash Flows (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Consolidating Entries Total Net cash flows provided by operating activities $ 145 $ 1,549 $ 1 $ — $ 1,695 Net cash flows used in investing activities — (1,105 ) (614 ) — (1,719 ) Net cash flows provided by (used in) financing activities (145 ) (497 ) 613 — (29 ) Net change in cash and cash equivalents — (53 ) — — (53 ) Cash and cash equivalents at beginning of period — 53 — — 53 Cash and cash equivalents at end of period $ — $ — $ — $ — $ —

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent events	Subsequent events Dividends. On February 18, 2020 , the Company’s board of directors declared a cash dividend of $0.20 per share for the first quarter of 2020. The total cash dividend, including the cash dividend on unvested restricted stock awards, of $39 million is expected to be paid on March 27, 2020 . New commodity derivative contracts. After December 31, 2019 , the Company entered into the following derivative contracts to hedge additional amounts of estimated future production: 2020 First Quarter Second Quarter Third Quarter Fourth Quarter Total 2021 2022 Oil Price Swaps – WTI: (a) Volume (MBbl) — — — — — 365 — Price per Bbl $ — $ — $ — $ — $ — $ 55.24 $ — Oil Basis Swaps: (b) Volume (MBbl) — 1,092 309 61 1,462 1,460 — Price per Bbl $ — $ 1.11 $ 1.05 $ 1.00 $ 1.09 $ 1.23 $ — Natural Gas Price Swaps - Henry Hub: (c) Volume (BBtu) — — — — — 29,200 36,500 Price per MMBtu $ — $ — $ — $ — $ — $ 2.34 $ 2.38 Natural Gas Basis Swaps - Henry Hub/El Paso Permian: (d) Volume (BBtu) — — — — — 14,600 29,200 Price per MMBtu $ — $ — $ — $ — $ — $ (1.08 ) $ (0.72 ) Natural Gas Basis Swaps - Henry Hub/WAHA: (e) Volume (BBtu) — — — — — 7,300 7,300 Price per MMBtu $ — $ — $ — $ — $ — $ (1.30 ) $ (0.85 ) (a) The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis. (c) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price. (d) The basis differential price is between NYMEX – Henry Hub and El Paso Permian. (e) The basis differential price is between NYMEX – Henry Hub and WAHA.

Summary of significant accoun_2

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also included the accounts of a variable interest entity (“VIE”) where the Company was the primary beneficiary of the arrangements until the VIE structure dissolved in January 2018. See Note 5 for additional information regarding the circumstances surrounding the VIE. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.
Reclassifications	Reclassifications. Certain prior period amounts have been reclassified to conform to the 2019 presentation. These reclassifications had no impact on net income (loss), total assets, liabilities and stockholders’ equity or total cash flows.
Use of estimates in the preparation of financial statements	Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, goodwill, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary transactions, fair value of derivative financial instruments and income taxes.
Assets held for sale	Assets held for sale. On the date at which the Company determines the asset group met all of the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the asset or asset group to be sold and reclassifies these assets as held for sale in its consolidated balance sheets. The assets held for sale are measured at the fair value less cost to sell.
Cash and cash equivalents	Cash and cash equivalents.
Accounts receivable	Accounts receivable.
Inventory	Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of weighted average cost or net realizable value.
Oil and natural gas properties	Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. The Company recognized depletion expense of approximately $1.9 billion , $1.5 billion and $1.1 billion during the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well; and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the Company’s large multi-well project development program, capital intensive nature and geographical location of certain projects, it may take longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. The Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves and is transferred to proved oil and natural gas properties or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s exploratory well costs. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred. Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2019 and 2018 , the Company capitalized interest of $19 million and $8 million , respectively, primarily related to the Company’s development projects. The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recognized an impairment expense of $890 million during the year ended December 31, 2019 related to its proved oil and natural gas properties, but did not recognize an impairment expense during the years ended December 31, 2018 and 2017 . See Note 8 for additional information regarding the Company’s impairment expense. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. During the years ended December 31, 2019 , 2018 and 2017 , the Company recognized expense of $147 million , $35 million and $27 million , respectively, related to abandoned and expiring acreage, which is included in exploration and abandonments expense in the accompanying consolidated statements of operations.
Other property and equipment	Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 39
Nonmonetary transactions	Nonmonetary transactions. In connection with nonmonetary transactions, which include exchanges of producing and non-producing assets, the Company must evaluate the transaction to determine appropriate accounting treatment. In general, the basic principle of accounting for nonmonetary transactions is based on the fair values involved, which is the same basis used in monetary transactions and results in the recognition of gains and losses. However, certain nonmonetary transactions meet criteria that require modification of the basic principle that necessitate recording values based on historical book value. The Company determines the treatment of nonmonetary transactions based on the individual facts and circumstances of each transaction. In cases where nonmonetary transactions are recorded at fair value, the Company makes various assumptions. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties, similar to the valuation of the fair value of oil and natural gas assets acquired during a business combination. Any resulting difference between the fair value of the assets involved and their carrying value is recorded as a gain or loss in the consolidated statement of operations.
Goodwill	Goodwill. Goodwill is assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of July 1 of each year. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. The reporting unit’s fair value is the Company’s enterprise value calculated as the combined market capitalization of the Company’s equity plus a control premium, and the fair value of the Company’s long-term debt. If the results of the quantitative test are such that the fair value of the reporting unit is less than the carrying value, goodwill is then reduced by an amount that is equal to the amount by which the carrying value of the reporting unit exceeds the fair value. The Company performed an annual quantitative impairment test during the third quarter of 2019 . The fair value of the reporting unit exceeded the carrying value of net assets at July 1, 2019. As discussed in Note 5 , in August 2019, the Company entered into a definitive agreement to sell its assets in the New Mexico Shelf. The Company classified these assets as held for sale at August 29, 2019. The Company allocated $81 million of goodwill to this disposal group, all of which the Company impaired. This impairment charge was recorded in impairments of goodwill on the consolidated statements of operations for the year ended December 31, 2019 . See Note 8 for additional impairment discussion of this disposal group. In conjunction with the allocation and impairment of goodwill related to the New Mexico Shelf disposal group, the Company performed a quantitative impairment test for the remaining goodwill. No additional impairment was recorded as the fair value of the reporting unit exceeded the carrying value. The Company also performed an impairment test at September 30, 2019 due to declines in the Company’s market capitalization and at December 31, 2019 due to declines in observed control premiums. The estimated fair value of the reporting unit at September 30, 2019 exceeded the carrying value of our net assets. However, during the fourth quarter of 2019, the Company’s estimated fair value declined further resulting in a $201 million impairment charge at December 31, 2019 . As such, the Company recorded total impairment charges of $282 million during the year ended December 31, 2019 . The Company used an average stock price over a determined period to estimate the fair value of the reporting unit at December 31, 2019, which the Company believes removes the impact of short term market fluctuations. In addition, the Company’s control premium was based on the estimated median control premium of transactions involving companies in the Company’s industry. The Company did not recognize an impairment expense during the year ended December 31, 2018. It is reasonably possible that the estimates of our enterprise value may change in the future resulting in the need to impair goodwill. Currently, the primary factor that may negatively affect the Company’s enterprise value is a continued depressed level of the Company’s stock price. Many factors affecting the Company’s stock price are beyond the Company’s control and the Company cannot predict the potential effects on the price of its common stock. Stock markets in general can also experience considerable price and volume fluctuations. In addition, deteriorating industry, market and economic conditions could negatively impact the control premium and the Company’s enterprise value, which could lead to additional impairments of the Company’s goodwill balance.
Equity method investments	Equity method investments. The Company holds membership interests in certain entities and accounts for these investments using the equity method of accounting. • The Company owns a 50 percent membership interest in Beta Holding Company, LLC, a midstream joint venture formed to construct a crude oil gathering system in the Midland Basin. • The Company owns a 20 percent membership interest in Solaris Midstream Holdings, LLC, an entity that owns and operates water gathering, transportation, disposal, recycling and storage infrastructure assets in the Permian Basin. • The Company owns a preferred membership interest in WaterBridge Operating LLC, an entity that operates and manages various water infrastructure assets located in the Permian Basin. The Company includes its equity method investment balance in other assets on the consolidated balance sheets. The Company records its share of equity investment earnings and losses in other income (expense) on the consolidated statements of operations. Equity investment earnings and losses are adjusted to account for any basis difference. The Company recorded equity method investment income of $12 million , $4 million and $7 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company also contributed certain water infrastructure assets and recorded a gain of $297 million and $79 million , which is included in gain on disposition of assets, net on the Company’s consolidated statements of operations for the years ended December 31, 2019 and 2018 , respectively. Until May 2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that owned and operated Oryx I, a crude oil gathering and transportation system in the Delaware Basin (“Oryx I”). In February 2018, Oryx obtained a term loan of $800 million . The proceeds were used in part to fund a cash distribution to its equity holders, of which the Company received a distribution of $157 million . Of this amount, $54 million fully offset the Company’s net investment in Oryx. The net investment of $54 million included $45 million of the Company’s contributions made to Oryx and $9 million of equity income. The remaining distribution of $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations for the year ended December 31, 2018. In May 2019, Oryx completed the sale of 100 percent of its equity interests in Oryx I. The Company received $289 million , net of closing costs, in connection with the sale of Oryx I and recorded a gain in other income (expense) on the Company’s consolidated statement of operations for the year ended December 31, 2019 . In February 2017, the Company closed on the divestiture of its 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the Delaware Basin. See Note 5 for additional information regarding the disposition of ACC.
Regulatory and environmental compliance	Regulatory and environmental compliance. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations and are capitalized. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures that are noncapital in nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revisions until settlement occurs. See Note 11 for additional information.
Litigation contingencies	Litigation contingencies. The Company is a party to proceedings and claims incidental to its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. The amount of any resulting losses may differ from these estimates. An accrual is recorded for a material loss contingency when its occurrence is probable and the amount is reasonably estimable. See Note 11 for additional information.
Income taxes	Income taxes. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. On December 22, 2017, the President of the United States (the “President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” (“TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”) to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allowed companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year. The Company elected to apply SAB 118 and, as such, recorded provisional amounts for the income tax balances reported in its consolidated financial statements at December 31, 2017. At December 31, 2018, the Company completed its accounting for all tax effects of the TCJA and made an adjustment to its provisional amounts related to the deductibility of certain compensation based on available regulatory and interpretive guidance.
Income taxes uncertainties	The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. At December 31, 2019 and 2018, the Company had unrecognized tax benefits primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain. The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense.
Derivative instruments	Derivative instruments. The Company recognizes its derivative instruments, other than commodity derivative contracts that are designated as normal purchase and normal sale contracts, as either assets or liabilities measured at fair value. The Company nets the fair value of the derivative instruments by counterparty in the accompanying consolidated balance sheets when the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated balance sheets.
Asset retirement obligations	Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related oil and natural gas property asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability through accretion expense. Based on certain factors, including commodity prices and costs, the Company may revise its previous estimates of the liability, which would also increase or decrease the related oil and natural gas property asset.
Purchases of common stock	Purchases of common stock. Common stock purchased and held in treasury is recorded at cost. For common stock repurchased and retired, the excess of cost over par value is charged to additional paid-in capital.
Revenue recognition	Revenue recognition. On January 1, 2018, the Company adopted ASC Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”) using the modified retrospective approach. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and does not have a material impact on the Company’s reported net income (loss), cash flows from operations or statement of stockholders’ equity. The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. All revenues are recognized in the geographical region of the Permian Basin. Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers. The Company enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At December 31, 2019 and 2018 , the Company had receivables related to contracts with customers of $584 million and $466 million , respectively. Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in gathering, processing and transportation on the Company’s consolidated statements of operations and are accounted for as costs incurred directly and not netted from the transaction price. Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Company receives natural gas liquids and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in gathering, processing and transportation on the Company’s consolidated statements of operations. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14A, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
General and administrative expense	General and administrative expense.
Stock-based compensation	Stock-based compensation . Stock-based compensation expense is recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their grant date fair values. Stock-based compensation awards vest over a period generally ranging from one to ten years . The Company utilizes the average of the high and low stock prices at each grant date to determine the fair value of restricted stock and the Monte Carlo simulation method to determine the fair value of performance unit awards. The Company recognizes forfeitures on stock-based compensation awards as they occur.
Recently adopted accounting pronouncements	Recently adopted accounting pronouncements. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which requires all leases with a term greater than one year to be recognized on the consolidated balance sheet while maintaining similar classifications for finance and operating leases. Lease expense recognition on the consolidated statements of operations was effectively unchanged. The Company adopted this guidance on January 1, 2019. The Company made policy elections not to capitalize short-term leases for all asset classes and not to separate non-lease components from lease components for all asset classes except for vehicles. The Company also did not elect the package of practical expedients that allowed for certain considerations under the original “Leases (Topic 840)” accounting standard (“Topic 840”) to be carried forward upon adoption of ASU 2016-02. In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient not to evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under Topic 840. The Company enters into land easements on a routine basis as part of its ongoing operations and has many such agreements currently in place; however, the Company did not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company elected this practical expedient, which became effective upon the date of adoption of ASU 2016-02. The Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease. In July 2018, the FASB issued ASU No. 2018-11, “Targeted Improvements,” which provides a transition election not to restate comparative periods for the effects of applying the new lease standard. This transition election permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2019 was zero . The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field equipment and drilling rigs. Upon adoption, the Company recognized $35 million of right-of-use assets, of which $19 million and $16 million relate to the Company’s operating and finance leases, respectively, and $37 million of associated lease liabilities. See Note 11 for additional disclosures of the Company’s leases. In August 2018, the SEC issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity to interim periods. Registrants are required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. In addition, the final rule requires the presentation of dividends per share to be disclosed in the statement of stockholders’ equity. New accounting pronouncements issued but not yet adopted. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“Topic 326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. This guidance is effective for fiscal years beginning after December 15, 2019. The Company has completed the process of determining which financial assets are in scope for this new guidance and has developed an internal model to measure the expected credit losses for those balances as required by the new guidance. Financial assets in scope for the Company include oil and natural gas sales receivables and joint interest receivables. The Company adopted this new guidance on January 1, 2020 and recognized an immaterial non-cash cumulative effect adjustment to retained earnings on our opening consolidated balance sheet at the date of adoption. In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606” (“ASU 2018-18”), which, among other things, clarifies that (i) certain transactions between collaborative arrangement participants should be accounted for as revenue under Topic 606 when the collaborative arrangement participant is a customer in the context of a unit of account, (ii) adds unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 and (iii) requires that in a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, presenting the transaction together with revenue recognized under Topic 606 is precluded if the collaborative arrangement participant is not a customer. ASU 2018-18 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. The amendments in this update should be applied retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. The Company adopted this guidance on January 1, 2020. The adoption did not have a material impact on the Company’s consolidated financial statements. In December 2019, the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”), which simplifies various aspects of the income tax accounting guidance in ASC 740, including requirements related to the following: (i) hybrid tax regimes; (ii) the tax basis step-up in goodwill obtained in a transaction that is not a business combination; (iii) separate financial statements of entities not subject to tax; (iv) the intraperiod tax allocation exception to the incremental approach; (v) ownership changes in investments - changes from a subsidiary to an equity method investment (and vice versa); (vi) interim-period accounting for enacted changes in tax laws; and (vii) the year-to-date loss limitation in interim-period tax accounting. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years and early adoption is permitted. If an entity early adopts these amendments in an interim period, it should reflect any adjustments as of the beginning of the annual period that includes that interim period. In addition, an entity that elects to early adopt ASU 2019-12 is required to adopt all of the amendments in the same period. The Company is currently assessing the effect that ASU 2019-12 will have on its financial position, results of operations and disclosures.

Exploratory well costs (Tables)

Exploratory well costs (Tables)	12 Months Ended
	Dec. 31, 2019
Capitalized Exploratory Well Costs [Abstract]
Company's capitalized exploratory well activity	The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Beginning capitalized exploratory well costs $ 523 $ 182 $ 151 Additions to exploratory well costs pending the determination of proved reserves (a) 271 581 180 Reclassifications due to determination of proved reserves (503 ) (226 ) (147 ) Exploratory well costs charged to expense (6 ) — — Disposition of wells (7 ) (14 ) (2 ) Ending capitalized exploratory well costs $ 278 $ 523 $ 182 (a) Balance at December 31, 2018 includes $82 million of exploratory well costs acquired as part of the RSP Acquisition, as defined in Note 4 .
Aging of capitalized exploratory well costs based on the date drilling was completed	The following table provides an aging at December 31, 2019 and 2018 of capitalized exploratory well costs based on the date drilling was completed: (in millions, except number of projects) December 31, 2019 2018 Capitalized exploratory well costs that have been capitalized for a period of one year or less $ 263 $ 523 Capitalized exploratory well costs that have been capitalized for a period greater than one year 15 — Total capitalized exploratory well costs $ 278 $ 523 Number of projects with exploratory well costs that have been capitalized for a period greater than one year 2 —

RSP acquisition (Tables)

RSP acquisition (Tables)	12 Months Ended
	Dec. 31, 2019
Business Acquisition [Line Items]
Purchase Price Allocation	The following table sets forth the Company’s final purchase price allocation: (in millions) Total purchase price $ 7,549 Fair value of liabilities assumed: Accounts payable – trade $ 48 Accrued drilling costs 79 Current derivative instruments 10 Other current liabilities 116 Long-term debt 1,758 Deferred income taxes 515 Asset retirement obligations 20 Noncurrent derivative instruments 5 Total liabilities assumed $ 2,551 Total purchase price plus liabilities assumed $ 10,100 Fair value of assets acquired: Accounts receivable $ 194 Current derivative instruments 36 Other current assets 21 Proved oil and natural gas properties 4,055 Unproved oil and natural gas properties 3,565 Other property and equipment 5 Noncurrent derivative instruments 2 Implied goodwill 2,222 Total assets acquired $ 10,100
RSP Permian
Business Acquisition [Line Items]
Schedule of Pro Forma Information	The following unaudited pro forma combined condensed financial data for the years ended December 31, 2018 and 2017 was derived from the historical financial statements of the Company giving effect to the RSP Acquisition, as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for RSP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert RSP’s outstanding shares of common stock and equity awards as of the closing date of the RSP Acquisition, (ii) the depletion of RSP’s fair-valued proved oil and gas properties and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of $32 million for the year ended December 31, 2018 and acquisition-related costs incurred by RSP and severance payments to certain RSP employees that totaled $56 million for the year ended December 31, 2018. The pro forma results of operations do not include any cost savings or other synergies that may result from the RSP Acquisition. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the period. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the RSP Acquisition taken place on January 1, 2017 and is not intended to be a projection of future results. (in millions, except per share amounts) Years Ended December 31, 2018 2017 (unaudited) Operating revenues $ 4,798 $ 3,390 Net income $ 2,552 $ 1,197 Earnings per share: Basic net income $ 12.75 $ 6.02 Diluted net income $ 12.73 $ 5.99

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	The Company’s asset retirement obligation transactions during the years ended December 31, 2019 , 2018 and 2017 are summarized in the table below: (in millions) Years Ended December 31, 2019 2018 2017 Asset retirement obligations, beginning of period $ 179 $ 141 $ 130 Liabilities incurred from new wells 7 4 2 Liabilities assumed in acquisitions 4 26 10 Accretion expense 10 10 8 Disposition of wells (66 ) (4 ) (1 ) Liabilities settled upon plugging and abandoning wells (7 ) (7 ) (5 ) Revision of estimates (a) 12 9 (3 ) Asset retirement obligations, end of period $ 139 $ 179 $ 141 (a) The revisions to the Company’s asset retirement obligation estimates for the years ended December 31, 2019 and 2018 were primarily due to increased costs in New Mexico.

Incentive plans (Tables)

Incentive plans (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the Company's restricted stock awards activity	A summary of the Company’s restricted stock award activity for the year ended December 31, 2019 is presented below: Number of Restricted Shares Weighted Average Grant Date Fair Value Per Share Outstanding at December 31, 2018 1,364,699 $ 128.08 Shares granted 776,189 $ 98.83 Shares cancelled / forfeited (147,336 ) $ 113.69 Lapse of restrictions (508,200 ) $ 126.82 Outstanding at December 31, 2019 1,485,352 $ 113.74
Summarizes information about stock-based compensation for the company's restricted stock awards activity under the Plan	The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Fair value for awards granted during the period (a) $ 77 $ 94 $ 60 Fair value for awards vested during the period $ 52 $ 54 $ 49 Stock-based compensation expense from restricted stock $ 63 $ 60 $ 43 Income tax benefit related to restricted stock $ 10 $ 14 $ 11 (a) The weighted average grant date fair value per share amounts were $98.83 , $137.31 and $123.16 for the years ended December 31, 2019 , 2018 and 2017 , respectively.
Summarizes the assumptions to estimate the fair value of performance units granted	The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 Risk-free interest rate 2.45% - 2.47% 2.00% 1.47% Range of volatilities 23.3% - 50.0% 23.5% - 64.0% 24.8% - 60.2%
Summary of the company's performance unit activity	The following table summarizes the performance unit activity for the year ended December 31, 2019 : Number of Units Grant Date Fair Value Performance units: Outstanding at December 31, 2018 218,391 $ 201.97 Units granted (a) 212,947 $ 144.03 Lapse of restrictions (b) (106,901 ) $ 187.31 Outstanding at December 31, 2019 324,437 $ 168.77 (a) Includes 38,952 performance unit awards granted to certain officers in January 2019 that may convert into shares of restricted stock awards at the end of each performance period that will be subject to additional vesting conditions. (b) On December 31, 2019 , the performance period ended for these performance units. Each unit converted into 0.38 shares representing 40,631 shares of common stock issued on January 2, 2020.
Summarizes information about stock-based compensation for the company's performance unit awards activity under the Plan	The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Fair value for awards granted during the period (a) $ 31 $ 24 $ 20 Fair value for awards vested during the period $ 26 $ 68 $ 68 Stock-based compensation expense from performance units $ 22 $ 22 $ 17 Income tax benefit related to performance units $ 5 $ 14 $ 2 (a) The weighted average grant date fair value per unit amounts were $144.03 , $216.03 and $183.48 for the years ended December 31, 2019 , 2018 and 2017 , respectively.
Future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding	The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31, 2019 : (in millions) 2020 $ 61 2021 36 2022 12 2023 2 2024 1 Thereafter 2 Total $ 114

Disclosures about fair value _2

Disclosures about fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Carrying amounts and fair values of the company's financial instruments	The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31, 2019 and 2018 : (in millions) December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Assets: Derivative instruments $ 17 $ 17 $ 695 $ 695 Liabilities: Derivative instruments $ 119 $ 119 $ — $ — Credit facility $ — $ — $ 242 $ 242 $600 million 4.375% senior notes due 2025 (a) $ 595 $ 620 $ 594 $ 591 $1,000 million 3.75% senior notes due 2027 (a) $ 990 $ 1,054 $ 989 $ 939 $1,000 million 4.3% senior notes due 2028 (a) $ 989 $ 1,091 $ 988 $ 980 $800 million 4.875% senior notes due 2047 (a) $ 789 $ 941 $ 789 $ 761 $600 million 4.85% senior notes due 2048 (a) $ 592 $ 697 $ 592 $ 573 (a) The carrying value includes associated deferred loan costs and any discount.
Net basis derivative fair values as reported in the consolidated balance sheets	The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, 2019 and 2018 . The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets. December 31, 2019 Fair Value Measurements Using Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets Current: Commodity derivatives $ — $ 108 $ — $ 108 $ (102 ) $ 6 Noncurrent: Commodity derivatives — 31 — 31 (20 ) 11 Liabilities Current: Commodity derivatives — (214 ) — (214 ) 102 (112 ) Noncurrent: Commodity derivatives — (27 ) — (27 ) 20 (7 ) Net derivative instruments $ — $ (102 ) $ — $ (102 ) $ — $ (102 ) December 31, 2018 Fair Value Measurements Using Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets Current: Commodity derivatives $ — $ 543 $ — $ 543 $ (59 ) $ 484 Noncurrent: Commodity derivatives — 243 — 243 (32 ) 211 Liabilities Current: Commodity derivatives — (59 ) — (59 ) 59 — Noncurrent: Commodity derivatives — (32 ) — (32 ) 32 — Net derivative instruments $ — $ 695 $ — $ 695 $ — $ 695

Derivative financial instrume_2

Derivative financial instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments	The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Gain (loss) on derivatives: Oil derivatives $ (1,003 ) $ 848 $ (172 ) Natural gas derivatives 108 (16 ) 46 Total $ (895 ) $ 832 $ (126 ) The following table represents the Company’s net cash receipts from (payments on) derivatives for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Net cash receipts from (payments on) derivatives: Oil derivatives $ (129 ) $ (213 ) $ 79 Natural gas derivatives 31 (5 ) — Total $ (98 ) $ (218 ) $ 79
Company's outstanding derivative contracts	The following table sets forth the Company’s outstanding derivative contracts at December 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at December 31, 2019 are expected to settle by December 31, 2021. 2020 First Quarter Second Quarter Third Quarter Fourth Quarter Total 2021 Oil Price Swaps – WTI: (a) Volume (MBbl) 14,674 12,494 11,080 10,045 48,293 18,612 Price per Bbl $ 57.13 $ 56.90 $ 56.88 $ 57.00 $ 56.98 $ 54.19 Oil Price Swaps – Brent: (b) Volume (MBbl) 2,578 2,031 1,768 1,503 7,880 — Price per Bbl $ 60.78 $ 60.33 $ 60.29 $ 60.14 $ 60.43 $ — Oil Basis Swaps: (c) Volume (MBbl) 14,951 11,284 10,856 10,120 47,211 18,980 Price per Bbl $ (0.43 ) $ (0.56 ) $ (0.62 ) $ (0.71 ) $ (0.57 ) $ 0.64 Natural Gas Price Swaps – Henry Hub: (d) Volume (BBtu) 35,023 32,314 30,038 28,498 125,873 40,150 Price per MMBtu $ 2.46 $ 2.46 $ 2.47 $ 2.47 $ 2.47 $ 2.52 Natural Gas Basis Swaps – Henry Hub/El Paso Permian: (e) Volume (BBtu) 25,770 23,960 22,080 21,770 93,580 36,500 Price per MMBtu $ (1.06 ) $ (1.07 ) $ (1.07 ) $ (1.07 ) $ (1.07 ) $ (0.66 ) Natural Gas Basis Swaps – Henry Hub/WAHA: (f) Volume (BBtu) 7,280 7,280 7,360 7,360 29,280 10,950 Price per MMBtu $ (1.10 ) $ (1.10 ) $ (1.10 ) $ (1.10 ) $ (1.10 ) $ (0.66 ) (a) These oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price. (b) These oil derivative contracts are settled based on the Brent calendar-month average futures price. (c) The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis. (d) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price. (e) The basis differential price is between NYMEX – Henry Hub and El Paso Permian. (f) The basis differential price is between NYMEX – Henry Hub and WAHA.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Company's debt	The Company’s debt consisted of the following at December 31, 2019 and 2018 : (in millions) December 31, 2019 2018 Credit facility due 2022 $ — $ 242 4.375% unsecured senior notes due 2025 (a) 600 600 3.75% unsecured senior notes due 2027 1,000 1,000 4.3% unsecured senior notes due 2028 1,000 1,000 4.875% unsecured senior notes due 2047 800 800 4.85% unsecured senior notes due 2048 600 600 Unamortized original issue discount (9 ) (10 ) Senior notes issuance costs, net (36 ) (38 ) Less: current portion — — Total long-term debt $ 3,955 $ 4,194 (a) For each of the twelve month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are callable at 103.281% , 102.188% , 101.094% and 100% , respectively.
Principal maturities of debt	Principal maturities of long-term debt outstanding at December 31, 2019 were as follows: (in millions) 2020 $ — 2021 — 2022 — 2023 — 2024 — Thereafter 4,000 Total $ 4,000
Interest expense	The following amounts have been incurred and charged to interest expense for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Cash payments for interest $ 207 $ 118 $ 139 Non-cash interest 6 5 6 Net changes in accruals (9 ) 34 4 Interest costs incurred 204 157 149 Less: capitalized interest (19 ) (8 ) (3 ) Total interest expense $ 185 $ 149 $ 146

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Summary of the company's future commitments	The following table summarizes the Company’s commitments at December 31, 2019 : (in millions) Volume Delivery Commitments (b) Power Commitments (a) Other Commitments Total 2020 $ 8 $ 14 $ 29 $ 51 2021 19 14 38 71 2022 19 14 5 38 2023 19 14 2 35 2024 19 14 2 35 Thereafter 54 44 5 103 Total $ 138 $ 114 $ 81 $ 333 (a) Certain power commitments include a variable price component that is based on the last day settlement price of the NYMEX futures contract for the physical delivery period. (b)
Oil and natural gas delivery commitments	At December 31, 2019 , the Company’s delivery commitments covered the following gross volumes of oil and natural gas: Oil (in MMBbl) (a) Natural Gas (in MMcf) 2020 43 371 2021 51 7,267 2022 53 16,425 2023 51 16,425 2024 47 16,470 Thereafter 114 32,850 Total 359 89,808 (a) Included in the table above is an oil marketing contract with a third-party purchaser that requires the Company to deliver fifty thousand barrels of oil per day.
Schedule of supplemental balance sheet Information for leases	The following table provides supplemental consolidated balance sheet information related to leases at December 31, 2019 : (in millions) Classification December 31, 2019 Assets Operating lease right-of-use assets Other property and equipment, net $ 15 Finance lease right-of-use assets Other property and equipment, net 16 Total lease right-of-use assets (a) $ 31 Liabilities Current: Operating Other current liabilities $ 8 Finance Other current liabilities 7 Noncurrent: Operating Asset retirement obligations and other long-term liabilities 9 Finance Asset retirement obligations and other long-term liabilities 10 Total lease liabilities (a) $ 34 (a) Total lease right-of-use assets and lease liabilities are gross amounts, and a portion of these costs will be reimbursed by other working interest owners.
Components of lease expense	The following table provides the components of lease cost, excluding lease cost related to short-term leases, for the year ended December 31, 2019 : (in millions) Classification December 31, 2019 Operating lease cost General and administrative $ 7 Finance lease cost Depreciation, depletion, and amortization (a) 8 Total lease cost $ 15 (a) Interest on lease liabilities related to finance leases was immaterial during the year ended December 31, 2019.
supplemental cash flow information related to leases	The following table summarizes supplemental cash flow information related to leases for the year ended December 31, 2019 : (in millions) December 31, 2019 Cash paid for amounts included in measurement of lease liabilities: Operating cash flows from operating leases $ 8 Financing cash flows from finance leases $ 7 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 3 Finance leases $ 9
Lease terms and discount rates related to leases	The following table provides lease terms and discount rates related to leases at December 31, 2019 : December 31, 2019 Weighted average remaining lease term (years): Operating leases 3.2 Finance leases 2.8 Weighted average discount rate (a): Operating leases 4.7 % Finance leases 4.2 % (a) The Company uses the rate implicit in the contract, if readily determinable, or its incremental borrowing rate at the commencement date as the discount rate in determining the present value of the lease payments.
Maturity and present value of lease liabilities	The following table provides maturities of lease liabilities at December 31, 2019 : (in millions) Operating Leases Finance Leases 2020 $ 8 $ 7 2021 7 6 2022 2 4 2023 — 1 2024 — — Thereafter 2 — Total lease payments 19 18 Less: interest (2 ) (1 ) Present value of lease liabilities $ 17 $ 17
Future minimum lease commitments under non-cancellable operating leases	Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows: (in millions) 2019 $ 14 2020 12 2021 10 2022 3 2023 — Thereafter 1 Total $ 40

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Company's income tax expense (benefit) attributable to income from continuing operations	The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following for the years ended December 31, 2019 , 2018 and 2017 : (in millions) Years Ended December 31, 2019 2018 2017 Current: U.S. federal $ — $ — $ (6 ) U.S. state — (2 ) 2 Total current income tax benefit — (2 ) (4 ) Deferred: U.S. federal (112 ) 547 (94 ) U.S. state (42 ) 58 23 Total deferred income tax expense (benefit) (154 ) 605 (71 ) Total income tax expense (benefit) $ (154 ) $ 603 $ (75 )
Reconciliation between the income tax expense (benefit) computed by multiplying pretax income (loss) from operations	The reconciliation between the income tax expense (benefit) computed by multiplying pre-tax income (loss) by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) is as follows: (in millions) Years Ended December 31, 2019 2018 2017 Income (loss) at U.S. federal statutory rate $ (180 ) $ 607 $ 308 Non-deductible goodwill 64 — — Enactment date and measurement period adjustments from the TCJA — (7 ) (398 ) State income taxes and enacted tax law changes, net of federal tax effect (13 ) 52 17 Change in estimated effective statutory state income tax rate (21 ) (8 ) — Excess tax benefit due to stock-based compensation — (12 ) (6 ) Research and development credits, net of unrecognized tax benefits (11 ) (41 ) — Other 7 12 4 Income tax expense (benefit) $ (154 ) $ 603 $ (75 ) Effective tax rate 18 % 21 % (9 )%
Temporary differences that give rise to deferred tax assets and tax liabilities	The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows: (in millions) December 31, 2019 2018 Deferred tax assets: Stock-based compensation $ 24 $ 26 Derivative instruments 23 — Asset retirement obligation 31 41 Net operating losses and other carryforwards 590 525 Research and development and other credits 73 61 Other 22 17 Total deferred tax assets 763 670 Less: Valuation allowance (4 ) (3 ) Net deferred tax assets 759 667 Deferred tax liabilities: Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes (2,318 ) (2,270 ) Equity method investments (83 ) — Intangible assets - operating rights (4 ) (4 ) Derivative instruments — (158 ) Other (8 ) (43 ) Total deferred tax liabilities (2,413 ) (2,475 ) Net deferred tax liabilities $ (1,654 ) $ (1,808 )
Changes in the Company's unrecognized tax benefits	The following table sets forth changes in the Company’s unrecognized tax benefits: (in millions) December 31, 2019 December 31, 2018 Balance at beginning of year $ 72 $ — Additions for tax positions acquired — 26 Additions for prior period tax positions — 20 Reductions for prior period tax positions (1 ) — Additions for current tax period positions 11 26 Balance at end of year $ 82 $ 72 Total that, if recognized, would impact the effective income tax rate $ 74 $ 63

Major customers and derivativ_2

Major customers and derivative counterparties (Tables)	12 Months Ended
	Dec. 31, 2019
Major Customer Disclosure [Abstract]
Schedule of Revenue by Major Customers by Reporting Segments	The following purchasers individually accounted for 10 percent or more of the Company’s consolidated oil and natural gas revenues during the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 Plains Marketing and Transportation, Inc. 17 % 18 % 21 % Enterprise Crude Oil LLC 10 % (a) (a) Holly Frontier Refining and Marketing, LLC (a) (a) 10 % (a) Purchaser did not account for 10% or more of total revenue for the period.

Earnings per share (Tables)

Earnings per share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Reconciliation of earnings attributable to common shares, basic and diluted	The following table reconciles the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the years ended December 31, 2019 , 2018 and 2017 , respectively, under the two-class method: (in millions, except per share amounts) Years Ended December 31, 2019 2018 2017 Net income (loss) as reported $ (705 ) $ 2,286 $ 956 Participating basic earnings (a) (1 ) (17 ) (7 ) Basic earnings attributable to common stockholders (706 ) 2,269 949 Reallocation of participating earnings — — — Diluted earnings attributable to common stockholders $ (706 ) $ 2,269 $ 949 (a)
Reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding	The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2019 , 2018 and 2017 : (in thousands) Years Ended December 31, 2019 2018 2017 Weighted average common shares outstanding: Basic 198,984 170,925 147,320 Dilutive common stock options — — 3 Dilutive performance units — 324 633 Diluted 198,984 171,249 147,956
Summary of the performance units that were not included in the computation of diluted net income per share	The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive: (in thousands) Years Ended December 31, 2019 2018 2017 Number of antidilutive common shares: Antidilutive performance units 431 108 81

Other current liabilities (Tabl

Other current liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Components of the company's other current liabilities	The following table provides the components of the Company’s other current liabilities at December 31, 2019 and 2018 : (in millions) December 31, 2019 2018 Other current liabilities: Accrued production costs $ 175 $ 135 Payroll related matters 37 49 Accrued interest 60 70 Settlements due on derivatives 38 — Asset retirement obligations 9 11 Other 44 55 Other current liabilities $ 363 $ 320

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	12 Months Ended
	Dec. 31, 2019
Guarantees [Abstract]
Condensed Consolidating Balance Sheet	The following condensed consolidating balance sheets at December 31, 2019 and 2018 , condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2019 , 2018 and 2017 , present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company. Condensed Consolidating Balance Sheet (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total ASSETS Accounts receivable - related parties $ 17,429 $ — $ — $ (17,429 ) $ — Other current assets 10 1,045 — — 1,055 Oil and natural gas properties, net — 20,874 16 — 20,890 Property and equipment, net — 437 — — 437 Investment in subsidiaries 5,635 — — (5,635 ) — Goodwill — 1,917 — — 1,917 Other long-term assets 22 411 — — 433 Total assets $ 23,096 $ 24,684 $ 16 $ (23,064 ) $ 24,732 LIABILITIES AND EQUITY Accounts payable - related parties $ — $ 17,413 $ 16 $ (17,429 ) $ — Other current liabilities 211 971 — — 1,182 Long-term debt 3,955 — — — 3,955 Other long-term liabilities 1,148 665 — — 1,813 Equity 17,782 5,635 — (5,635 ) 17,782 Total liabilities and equity $ 23,096 $ 24,684 $ 16 $ (23,064 ) $ 24,732 Condensed Consolidating Balance Sheet (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total ASSETS Accounts receivable - related parties $ 18,155 $ — $ — $ (18,155 ) $ — Other current assets 534 875 — — 1,409 Oil and natural gas properties, net — 21,988 17 — 22,005 Property and equipment, net — 308 — — 308 Investment in subsidiaries 5,411 — — (5,411 ) — Goodwill — 2,224 — — 2,224 Other long-term assets 224 124 — — 348 Total assets $ 24,324 $ 25,519 $ 17 $ (23,566 ) $ 26,294 LIABILITIES AND EQUITY Accounts payable - related parties $ — $ 18,138 $ 17 $ (18,155 ) $ — Other current liabilities 70 1,286 — — 1,356 Long-term debt 4,194 — — — 4,194 Other long-term liabilities 1,292 684 — — 1,976 Equity 18,768 5,411 — (5,411 ) 18,768 Total liabilities and equity $ 24,324 $ 25,519 $ 17 $ (23,566 ) $ 26,294
Condensed Consolidating Statement of Operations	Condensed Consolidating Statement of Operations (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Total operating revenues $ — $ 4,591 $ 1 $ — $ 4,592 Total operating costs and expenses (898 ) (4,681 ) — — (5,579 ) Income (loss) from operations (898 ) (90 ) 1 — (987 ) Interest expense (185 ) — — — (185 ) Other, net 224 313 — (224 ) 313 Income (loss) before income taxes (859 ) 223 1 (224 ) (859 ) Income tax benefit 154 — — — 154 Net income (loss) $ (705 ) $ 223 $ 1 $ (224 ) $ (705 ) Condensed Consolidating Statement of Operations (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Total operating revenues $ — $ 4,146 $ 5 $ — $ 4,151 Total operating costs and expenses 829 (2,047 ) (3 ) — (1,221 ) Income from operations 829 2,099 2 — 2,930 Interest expense (149 ) — — — (149 ) Other, net 2,209 108 — (2,209 ) 108 Income before income taxes 2,889 2,207 2 (2,209 ) 2,889 Income tax expense (603 ) — — — (603 ) Net income $ 2,286 $ 2,207 $ 2 $ (2,209 ) $ 2,286 Condensed Consolidating Statement of Operations (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Consolidating Entries Total Total operating revenues $ — $ 2,566 $ 20 $ — $ 2,586 Total operating costs and expenses (129 ) (1,369 ) (17 ) — (1,515 ) Income (loss) from operations (129 ) 1,197 3 — 1,071 Interest expense (145 ) (1 ) — — (146 ) Loss on extinguishment of debt (66 ) — — — (66 ) Other, net 1,221 22 — (1,221 ) 22 Income before income taxes 881 1,218 3 (1,221 ) 881 Income tax benefit 75 — — — 75 Net income $ 956 $ 1,218 $ 3 $ (1,221 ) $ 956
Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Net cash flows provided by operating activities $ 607 $ 2,229 $ — $ — $ 2,836 Net cash flows used in investing activities — (1,993 ) — — (1,993 ) Net cash flows used in financing activities (607 ) (166 ) — — (773 ) Net change in cash and cash equivalents — 70 — — 70 Cash and cash equivalents at beginning of period — — — — — Cash and cash equivalents at end of period $ — $ 70 $ — $ — $ 70 Condensed Consolidating Statement of Cash Flows (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Non-Guarantor Consolidating Entries Total Net cash flows provided by operating activities $ 338 $ 2,220 $ — $ — $ 2,558 Net cash flows used in investing activities — (2,216 ) — — (2,216 ) Net cash flows used in financing activities (338 ) (4 ) — — (342 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — — — — — Cash and cash equivalents at end of period $ — $ — $ — $ — $ — Condensed Consolidating Statement of Cash Flows (in millions) Parent Issuer Subsidiary Guarantors Subsidiary Consolidating Entries Total Net cash flows provided by operating activities $ 145 $ 1,549 $ 1 $ — $ 1,695 Net cash flows used in investing activities — (1,105 ) (614 ) — (1,719 ) Net cash flows provided by (used in) financing activities (145 ) (497 ) 613 — (29 ) Net change in cash and cash equivalents — (53 ) — — (53 ) Cash and cash equivalents at beginning of period — 53 — — 53 Cash and cash equivalents at end of period $ — $ — $ — $ — $ —

Subsequent events (Tables)

Subsequent events (Tables)	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
New commodity derivative contracts	After December 31, 2019 , the Company entered into the following derivative contracts to hedge additional amounts of estimated future production: 2020 First Quarter Second Quarter Third Quarter Fourth Quarter Total 2021 2022 Oil Price Swaps – WTI: (a) Volume (MBbl) — — — — — 365 — Price per Bbl $ — $ — $ — $ — $ — $ 55.24 $ — Oil Basis Swaps: (b) Volume (MBbl) — 1,092 309 61 1,462 1,460 — Price per Bbl $ — $ 1.11 $ 1.05 $ 1.00 $ 1.09 $ 1.23 $ — Natural Gas Price Swaps - Henry Hub: (c) Volume (BBtu) — — — — — 29,200 36,500 Price per MMBtu $ — $ — $ — $ — $ — $ 2.34 $ 2.38 Natural Gas Basis Swaps - Henry Hub/El Paso Permian: (d) Volume (BBtu) — — — — — 14,600 29,200 Price per MMBtu $ — $ — $ — $ — $ — $ (1.08 ) $ (0.72 ) Natural Gas Basis Swaps - Henry Hub/WAHA: (e) Volume (BBtu) — — — — — 7,300 7,300 Price per MMBtu $ — $ — $ — $ — $ — $ (1.30 ) $ (0.85 ) (a) The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis. (c) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price. (d) The basis differential price is between NYMEX – Henry Hub and El Paso Permian. (e) The basis differential price is between NYMEX – Henry Hub and WAHA.

Summary of significant accoun_3

Summary of significant accounting policies (Narrative) (Detail) - USD ($)	1 Months Ended		3 Months Ended	12 Months Ended
	May 31, 2019	Feb. 28, 2018	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Aug. 29, 2019	Jan. 01, 2019	Feb. 28, 2017
Significant Accounting Policies Disclosure [Line Items]
Allowance for doubtful accounts			$ 7,000,000	$ 7,000,000	$ 5,000,000
Depletion expense				1,900,000,000	1,500,000,000	$ 1,100,000,000
Capitalized interest				19,000,000	8,000,000	3,000,000
Impairments of long-lived assets				890,000,000	0	0
Impairment of abandoned and expiring acreage				147,000,000	35,000,000	27,000,000
Other property and equipment, net			437,000,000	437,000,000	308,000,000
Other property and equipment, accumulated depreciation			126,000,000	126,000,000	109,000,000
Depreciation expense on other property and equipment				30,000,000	22,000,000	21,000,000
Impairments of goodwill			201,000,000	282,000,000	0	0
Income (loss) from equity method investments				12,000,000	4,000,000	7,000,000
Gain (loss) on disposition of property plant equipment				170,000,000	800,000,000	678,000,000
Proceeds from equity method investment, distribution, return of capital				0	148,000,000	0
Other income (expense)				313,000,000	108,000,000	22,000,000
Proceeds from sale of productive assets				1,260,000,000	361,000,000	832,000,000
Receivables related to contracts with customers			584,000,000	584,000,000	466,000,000
Fees related to operation of jointly owned oil and natural gas properties				18,000,000	19,000,000	$ 16,000,000
Right of use asset			31,000,000	31,000,000
Operating lease right-of-use assets			15,000,000	15,000,000
Finance lease right-of-use assets			16,000,000	16,000,000
Lease liabilities			$ 34,000,000	$ 34,000,000
Accounting Standards Update 2016-02
Significant Accounting Policies Disclosure [Line Items]
Right of use asset								$ 35,000,000
Operating lease right-of-use assets								19,000,000
Finance lease right-of-use assets								16,000,000
Lease liabilities								37,000,000
Accounting Standards Update, 2018-11
Significant Accounting Policies Disclosure [Line Items]
Cumulative effect of new accounting principle in period of adoption								$ 0
Beta Holding Equity Method Investment
Significant Accounting Policies Disclosure [Line Items]
Equity method investment ownership percentage			50.00%	50.00%
Solaris Midstream Holdings Equity Method Investment
Significant Accounting Policies Disclosure [Line Items]
Equity method investment ownership percentage			20.00%	20.00%
Oryx Southern Delaware Holdings
Significant Accounting Policies Disclosure [Line Items]
Equity method investment ownership percentage	23.75%
Income (loss) from equity method investments		$ 9,000,000
Total distribution from equity method investment		157,000,000
Portion of equity method investment distribution that offset company's net investment		54,000,000
Proceeds from equity method investment, distribution, return of capital		45,000,000
Other income (expense)		103,000,000
Proceeds from sale of productive assets				$ 289,000,000
Oryx Southern Delaware Holdings | Loans Payable
Significant Accounting Policies Disclosure [Line Items]
Face amount of debt		$ 800,000,000
Alpha Crude Connector
Significant Accounting Policies Disclosure [Line Items]
Equity method investment ownership percentage									50.00%
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Significant Accounting Policies Disclosure [Line Items]
Gain (loss) on disposition of property plant equipment				297,000,000	$ 79,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Oryx Southern Delaware Holdings
Significant Accounting Policies Disclosure [Line Items]
Percentage of interest in affiliate sold	100.00%
New Mexico Shelf Divestiture
Significant Accounting Policies Disclosure [Line Items]
Disposal group, including discontinued operation, goodwill							$ 81,000,000
Gain (loss) on disposition of property plant equipment				$ 27,000,000
Minimum
Significant Accounting Policies Disclosure [Line Items]
Estimated economic life of gross operating rights in years, minimum				2 years
Vesting period				1 year
Maximum
Significant Accounting Policies Disclosure [Line Items]
Estimated economic life of gross operating rights in years, minimum				39 years
Vesting period				10 years

Exploratory well costs (capital

Exploratory well costs (capitalized exploratory well activity) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Exploratory Well Costs [Line Items]
Beginning capitalized exploratory well costs	$ 523	$ 182	$ 151
Additions to exploratory well costs pending the determination of proved reserves	271	581	180
Reclassifications due to determination of proved reserves	(503)	(226)	(147)
Exploratory well costs charged to expense	(6)	0	0
Disposition of wells	(7)	(14)	(2)
Ending capitalized exploratory well costs	278	523	$ 182
RSP Permian
Exploratory Well Costs [Line Items]
Beginning capitalized exploratory well costs	$ 82
Ending capitalized exploratory well costs		$ 82

Exploratory well costs (aging o

Exploratory well costs (aging of capitalized exploratory well Costs based on the date of drilling) (Detail) $ in Millions	Dec. 31, 2019USD ($)wellsproject	Dec. 31, 2018USD ($)project	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Capitalized Exploratory Well Costs [Abstract]
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$ 263	$ 523
Capitalized exploratory well costs that have been capitalized for a period greater than one year	15	0
Total capitalized exploratory well costs	$ 278	$ 523	$ 182	$ 151
Number of projects with exploratory well costs that have been capitalized for a period greater than one year | project	2	0
Gross exploratory wells | wells	3

RSP acquisition (Narrative) (De

RSP acquisition (Narrative) (Detail) $ / shares in Units, a in Thousands, $ in Millions	Jul. 19, 2018USD ($)a$ / shares$ / MMBTU$ / bblshares	Dec. 31, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Acquisition-related costs			$ 1	$ 39	$ 3
Increase in treasury stock			15	64	23
Operating revenues			4,592	4,151	2,586
Income (loss) from operations			(987)	2,930	1,071
Oil
Business Acquisition [Line Items]
Operating revenues			4,126	3,443	2,092
Natural Gas
Business Acquisition [Line Items]
Operating revenues			$ 466	708	$ 494
RSP Permian
Business Acquisition [Line Items]
Net acreage | a	92
Acquisition share conversion rate	32.00%
Shares issued in acquisition | shares	51,000,000
Share price for acquisition consideration (in dollars pershare) | $ / shares	$ 148.27
Consideration paid	$ 7,549
Acquisition-related costs				32
Acquisition-related and severance costs				$ 56
Shares received for withholding taxes | shares	670,369
Increase in treasury stock	$ 32
Asset retirement obligations acquired	20
Environmental liabilities acquired, current	$ 10
Operating revenues		$ 506
Income (loss) from operations		$ 274
RSP Permian | Oil | Commodity Price 2018
Business Acquisition [Line Items]
Oil and gas property, measurement input (in usd per barrel or MMBtu)) | $ / bbl	66.59
RSP Permian | Oil | Commodity Price 2022
Business Acquisition [Line Items]
Oil and gas property, measurement input (in usd per barrel or MMBtu)) | $ / bbl	63.41
RSP Permian | Natural Gas | Commodity Price 2018
Business Acquisition [Line Items]
Oil and gas property, measurement input (in usd per barrel or MMBtu)) | $ / MMBTU	2.80
RSP Permian | Natural Gas | Commodity Price 2022
Business Acquisition [Line Items]
Oil and gas property, measurement input (in usd per barrel or MMBtu)) | $ / MMBTU	3.09

RSP acquisition (purchase price

RSP acquisition (purchase price allocation) (Details) - USD ($) $ in Millions	Jul. 19, 2018	Dec. 31, 2019	Dec. 31, 2018
Fair value of assets acquired:
Implied goodwill		$ 1,917	$ 2,224
RSP Permian
Business Acquisition [Line Items]
Total purchase price	$ 7,549
Fair value of liabilities assumed:
Accounts payable – trade	48
Accrued drilling costs	79
Current derivative instruments	10
Other current liabilities	116
Long-term debt	1,758
Deferred tax liability recognized	515
Asset retirement obligations	20
Noncurrent derivative instruments	5
Total liabilities assumed	2,551
Fair value of assets acquired:
Accounts receivable	194
Current derivative instruments	36
Other current assets	21
Proved oil and natural gas properties	4,055
Unproved oil and natural gas properties	3,565
Other property and equipment	5
Noncurrent derivative instruments	2
Implied goodwill	2,222
Total assets acquired	$ 10,100

RSP acquisition (Schedule of pr

RSP acquisition (Schedule of pro forma information) (Details) - RSP Permian - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Operating revenues	$ 4,798	$ 3,390
Net income	$ 2,552	$ 1,197
Earnings per share:
Basic net income (in dollars per share)	$ 12.75	$ 6.02
Diluted net income (in dollars per share)	$ 12.73	$ 5.99

Acquisitions, divestitures an_2

Acquisitions, divestitures and nonmonetary transactions (Narrative) (Detail) a in Thousands, $ in Millions	1 Months Ended		12 Months Ended
	Nov. 30, 2019USD ($)	Jul. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)shares	Aug. 29, 2019USD ($)	Feb. 28, 2018a	Feb. 28, 2017USD ($)	Dec. 31, 2016USD ($)
Business Acquisition [Line Items]
Pre-tax gain (loss)			$ 170	$ 800	$ 678
Issuance of common stock for business combinations			0	7,549	291
February 2018 Acquisition Divestiture
Business Acquisition [Line Items]
Pre-tax gain (loss)				575
Net acreage | a							21
Fair value of acquired assets				755
Book value of divested assets				180
Proved oil and natural gas properties				245
Unproved oil and natural gas properties				480
Other assets				30
February 2018 Acquisition Divestiture | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Exchange
Business Acquisition [Line Items]
Net acreage | a							34
Southern Delaware Basin
Business Acquisition [Line Items]
Net proceeds from divestiture				280
Pre-tax gain (loss)				$ 134
Net acreage | a				20
Nonmonetary Transactions
Business Acquisition [Line Items]
Disposal group, including discontinued operation, goodwill			23
Pre-tax gain (loss) on nonmonetary transactions			(104)	$ 15	26
Northern Delaware Basin
Business Acquisition [Line Items]
Total cash consideration paid for acquisition					$ 160
Funds held in escrow									$ 43
Shares of common stock issued in connection with acquisition | shares					2,200,000
Issuance of common stock for business combinations					$ 291
Alpha Crude Connector
Business Acquisition [Line Items]
Pre-tax gain (loss)					$ 655
Percentage of divested interest					100.00%
Deposits on dispositions of oil and natural gas properties					$ 801
Total equity method investment								$ 129
Midland Basin
Business Acquisition [Line Items]
Total cash consideration paid for acquisition		$ 595
New Mexico Shelf Divestiture
Business Acquisition [Line Items]
Impairment of long-lived assets to be disposed			3
Net proceeds from divestiture	$ 837
Pre-tax gain (loss)			$ 27
Disposal group, including discontinued operation, goodwill						$ 81

Asset retirement obligations (s

Asset retirement obligations (schedule of asset retirement obligation transactions) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 179	$ 141	$ 130
Liabilities incurred from new wells	7	4	2
Liabilities assumed in acquisitions	4	26	10
Accretion expense	10	10	8
Disposition of wells	(66)	(4)	(1)
Liabilities settled upon plugging and abandoning wells	(7)	(7)	(5)
Revision of estimates	12	9	(3)
Asset retirement obligations, end of period	$ 139	$ 179	$ 141

Incentive plans (Narrative) (De

Incentive plans (Narrative) (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 16, 2019	May 15, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Approved and authorized awards (in shares)					15,000,000	10,500,000
Awards available for future grant ( in shares)		5,000,000
Restricted Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Share-based compensation equity instruments other than options (in shares)		776,189
Performance Shares
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period	3 years	3 years
Share-based compensation equity instruments other than options (in shares)	212,947	212,947
Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period		1 year
Minimum | Restricted Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period		1 year
Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period		10 years
Maximum | Restricted Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period		10 years
401 (k) defined contribution plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined contribution plan employer's contribution match percentage		100.00%	100.00%	100.00%
Defined contribution plan, employee contribution		10.00%	10.00%	10.00%
Defined contribution plan, employers contribution		$ 15	$ 12	$ 10
Officer | Performance Shares
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Share-based compensation equity instruments other than options (in shares)	38,952
Three Year Vesting Period | Officer | Performance Shares
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period	3 years
Share-based compensation equity instruments other than options (in shares)	19,476
Five Year Vesting Period | Officer | Performance Shares
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Vesting period	5 years
Share-based compensation equity instruments other than options (in shares)	19,476
Award vesting rights	20.00%

Incentive plans (schedule of re

Incentive plans (schedule of restricted stock awards activity) (Detail) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of Restricted Shares
Outstanding at beginning of period (in shares)	1,364,699
Shares granted (in shares)	776,189
Shares cancelled / forfeited (in shares)	(147,336)
Lapse of restrictions (in shares)	(508,200)
Outstanding at end of period (in shares)	1,485,352	1,364,699
Weighted Average Grant Date Fair Value Per Share
Weighted average grant date fair value, outstanding at beginning of year (in dollars per share)	$ 128.08
Shares granted - weighted average grant date fair value per share (in dollars per share)	98.83	$ 137.31	$ 123.16
Shares cancelled / forfeited - weighted average grant date fair value per share (in dollars per share)	113.69
Lapse of restrictions - weighted average grant date fair value per share (in dollars per share)	126.82
Weighted average grant date fair value, outstanding at end of year (in dollars per share)	$ 113.74	$ 128.08

Incentive plans (summary inform

Incentive plans (summary information for stock-based compensation for restricted stock awards) (Detail) - Restricted Stock - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value for awards granted during the period	$ 77	$ 94	$ 60
Fair value for awards vested during the period	52	54	49
Stock-based compensation expense from restricted stock	63	60	43
Income tax benefit related to restricted stock	$ 10	$ 14	$ 11
Weighted average grant date fair value per share (in dollars per share)	$ 98.83	$ 137.31	$ 123.16

Incentive plans (summary of ass

Incentive plans (summary of assumptions to estimate fair value of performance unit awards) (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate		2.00%	1.47%
Volatility assumption - minimum	23.30%	23.50%	24.80%
Volatility assumption - maximum	50.00%	64.00%	60.20%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	2.45%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	2.47%

Incentive Plans (schedule of pe

Incentive Plans (schedule of performance unit awards activity) (Detail) - Performance Shares - $ / shares	Jan. 02, 2020	Jan. 31, 2019	Dec. 31, 2019
Number of Units
Performance units outstanding at beginning of period (in shares)		218,391	218,391
Units granted (in shares)		212,947	212,947
Lapse of restrictions (in shares)			(106,901)
Performance units outstanding at end of period (in shares)			324,437
Weighted Average Grant Date Fair Value Per Share
Weighted average grant date fair value, outstanding at beginning of year (in dollars per share)		$ 201.97	$ 201.97
Units granted (in dollars per share)			144.03
Shares vested - grant date fair value - performance units (in dollars per share)			187.31
Weighted average grant date fair value, outstanding at end of year (in dollars per share)			$ 168.77
Officer
Number of Units
Units granted (in shares)		38,952
Subsequent Event
Weighted Average Grant Date Fair Value Per Share
Percentage of shares earned for each vested award	38.00%
Shares issued on conversion (in shares)	40,631

Incentive plans (summary info_2

Incentive plans (summary information for stock-based compensation for performance units) (Detail) - Performance Shares - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value for awards granted during the period	$ 31	$ 24	$ 20
Fair value for awards vested during the period	26	68	68
Stock-based compensation expense from performance units	22	22	17
Income tax benefit related to performance units	$ 5	$ 14	$ 2
Shares granted - weighted average grant date fair value per share (in dollars per share)	$ 144.03	$ 216.03	$ 183.48

Incentive plans (summary for fu

Incentive plans (summary for future stock-based compensation expense) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	$ 85	$ 82	$ 60
2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	61
2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	36
2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	12
2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	2
2024
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	1
Thereafter
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	2
Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	$ 114

Disclosures about fair value _3

Disclosures about fair value measurements (carrying amounts and fair values of the company's financial instruments) (Detail) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Jul. 02, 2018	Sep. 30, 2017
Fair Value Measurement [Domain] | 4.375% senior notes due 2025
Liabilities:
Face amount of debt	$ 600,000,000
Interest Rate	4.375%
Fair Value Measurement [Domain] | 3.75% senior notes due 2027
Liabilities:
Face amount of debt	$ 1,000,000,000
Interest Rate	3.75%
Fair Value Measurement [Domain] | 4.3% senior notes due 2028
Liabilities:
Face amount of debt	$ 1,000,000,000
Interest Rate	4.30%
Fair Value Measurement [Domain] | 4.875% senior notes due 2047
Liabilities:
Face amount of debt	$ 800,000,000
Interest Rate	4.875%
Fair Value Measurement [Domain] | 4.85% senior notes due 2048
Liabilities:
Face amount of debt	$ 600,000,000
Interest Rate	4.85%
Credit facility	$ 0	$ 242,000,000
3.75% senior notes due 2027
Liabilities:
Face amount of debt				$ 1,000,000,000
Interest Rate				3.75%
4.3% senior notes due 2028
Liabilities:
Face amount of debt			$ 1,000,000,000
Interest Rate			4.30%
4.875% senior notes due 2047
Liabilities:
Face amount of debt				$ 800,000,000
Interest Rate				4.875%
4.85% senior notes due 2048
Liabilities:
Face amount of debt			$ 600,000,000
Interest Rate			4.85%
Reported Value Measurement
Assets:
Derivative instruments	17,000,000	695,000,000
Liabilities:
Derivative instruments	119,000,000	0
Credit facility	0	242,000,000
Reported Value Measurement | 4.375% senior notes due 2025
Liabilities:
Debt instrument, fair value	595,000,000	594,000,000
Reported Value Measurement | 3.75% senior notes due 2027
Liabilities:
Debt instrument, fair value	990,000,000	989,000,000
Reported Value Measurement | 4.3% senior notes due 2028
Liabilities:
Debt instrument, fair value	989,000,000	988,000,000
Reported Value Measurement | 4.875% senior notes due 2047
Liabilities:
Debt instrument, fair value	789,000,000	789,000,000
Reported Value Measurement | 4.85% senior notes due 2048
Liabilities:
Debt instrument, fair value	592,000,000	592,000,000
Estimate of Fair Value Measurement
Assets:
Derivative instruments	17,000,000	695,000,000
Liabilities:
Derivative instruments	119,000,000	0
Credit facility	0	242,000,000
Estimate of Fair Value Measurement | 4.375% senior notes due 2025
Liabilities:
Debt instrument, fair value	620,000,000	591,000,000
Estimate of Fair Value Measurement | 3.75% senior notes due 2027
Liabilities:
Debt instrument, fair value	1,054,000,000	939,000,000
Estimate of Fair Value Measurement | 4.3% senior notes due 2028
Liabilities:
Debt instrument, fair value	1,091,000,000	980,000,000
Estimate of Fair Value Measurement | 4.875% senior notes due 2047
Liabilities:
Debt instrument, fair value	941,000,000	761,000,000
Estimate of Fair Value Measurement | 4.85% senior notes due 2048
Liabilities:
Debt instrument, fair value	$ 697,000,000	$ 573,000,000

Disclosures about fair value _4

Disclosures about fair value measurements (company's assets and liabilities measured at fair value on a recurring basis) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Liabilities
Net derivative instruments	$ (102)	$ 695
Commodity Derivative | Derivative Asset Current
Assets
Commodity derivatives	108	543
Gross Amounts Offset in the Consolidated Balance Sheet	(102)	(59)
Net Fair Value Presented in the Consolidated Balance Sheet	6	484
Commodity Derivative | Derivative Asset Noncurrent
Assets
Commodity derivatives	31	243
Gross Amounts Offset in the Consolidated Balance Sheet	(20)	(32)
Net Fair Value Presented in the Consolidated Balance Sheet	11	211
Commodity Derivative | Derivative Liability Current
Liabilities
Commodity derivatives	(214)	(59)
Gross Amounts Offset in the Consolidated Balance Sheet	102	59
Net Fair Value Presented in the Consolidated Balance Sheet	(112)	0
Commodity Derivative | Derivative Liability Noncurrent
Liabilities
Commodity derivatives	(27)	(32)
Gross Amounts Offset in the Consolidated Balance Sheet	20	32
Net Fair Value Presented in the Consolidated Balance Sheet	(7)	0
Fair Value, Inputs, Level 1
Liabilities
Net derivative instruments	0	0
Fair Value, Inputs, Level 1 | Commodity Derivative | Derivative Asset Current
Assets
Commodity derivatives	0	0
Fair Value, Inputs, Level 1 | Commodity Derivative | Derivative Asset Noncurrent
Assets
Commodity derivatives	0	0
Fair Value, Inputs, Level 1 | Commodity Derivative | Derivative Liability Current
Liabilities
Commodity derivatives	0	0
Fair Value, Inputs, Level 1 | Commodity Derivative | Derivative Liability Noncurrent
Liabilities
Commodity derivatives	0	0
Fair Value, Inputs, Level 2
Liabilities
Net derivative instruments	(102)	695
Fair Value, Inputs, Level 2 | Commodity Derivative | Derivative Asset Current
Assets
Commodity derivatives	108	543
Fair Value, Inputs, Level 2 | Commodity Derivative | Derivative Asset Noncurrent
Assets
Commodity derivatives	31	243
Fair Value, Inputs, Level 2 | Commodity Derivative | Derivative Liability Current
Liabilities
Commodity derivatives	(214)	(59)
Fair Value, Inputs, Level 2 | Commodity Derivative | Derivative Liability Noncurrent
Liabilities
Commodity derivatives	(27)	(32)
Fair Value, Inputs, Level 3
Liabilities
Net derivative instruments	0	0
Fair Value, Inputs, Level 3 | Commodity Derivative | Derivative Asset Current
Assets
Commodity derivatives	0	0
Fair Value, Inputs, Level 3 | Commodity Derivative | Derivative Asset Noncurrent
Assets
Commodity derivatives	0	0
Fair Value, Inputs, Level 3 | Commodity Derivative | Derivative Liability Current
Liabilities
Commodity derivatives	0	0
Fair Value, Inputs, Level 3 | Commodity Derivative | Derivative Liability Noncurrent
Liabilities
Commodity derivatives	$ 0	$ 0

Disclosures about fair value _5

Disclosures about fair value measurements (Narrative) (Details)

Jun. 30, 2019USD ($)$ / Mcf$ / bbl

Nov. 30, 2019USD ($)

Sep. 30, 2019USD ($)

Jun. 30, 2019USD ($)

Dec. 31, 2026$ / Mcf$ / bbl

Dec. 31, 2023$ / bbl

Dec. 31, 2022$ / bbl

Dec. 31, 2021$ / bbl

Dec. 31, 2020$ / Mcf$ / bbl

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Impairment of long-lived assets held-for-use | $

$ 890,000,000

$ 0

$ 0

Fair value, management estimate of inflation rate

2.00%

Annual discount rate

10.00%

Yeso Field

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Impairment of long-lived assets held-for-use | $

$ 20,000,000

$ 868,000,000

Long-lived assets held-for-use, fair value disclosure | $

$ 968,000,000

$ 968,000,000

New Mexico Shelf Divestiture

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proceeds from divestiture of businesses | $

$ 837,000,000

June 2019 Estimate | Valuation Technique, Undiscounted Cash Flow

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Management estimates of future oil price (in dollars per unit

58.32

Management estimates of future natural gas price (in dollars per unit) | $ / Mcf

2.38

June 2019 Estimate | Valuation Technique, Discounted Cash Flow

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Management estimates of future oil price (in dollars per unit

58.32

Management estimates of future natural gas price (in dollars per unit) | $ / Mcf

2.38

June 2019 Estimate | Scenario, Forecast | Valuation Technique, Undiscounted Cash Flow

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Management estimates of future oil price (in dollars per unit

54.47

53.58

Management estimates of future natural gas price (in dollars per unit) | $ / Mcf

2.99

June 2019 Estimate | Scenario, Forecast | Valuation Technique, Discounted Cash Flow

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Management estimates of future oil price (in dollars per unit

62.06

Management estimates of future natural gas price (in dollars per unit) | $ / Mcf

3

December 2019 Estimate | Scenario, Forecast | Valuation Technique, Undiscounted Cash Flow

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Management estimates of future oil price (in dollars per unit

52.57

51.31

58.83

Management estimates of future natural gas price (in dollars per unit) | $ / Mcf

2.55

2.29

December 2019 Estimate | Scenario, Forecast | Valuation Technique, Discounted Cash Flow

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Management estimates of future oil price (in dollars per unit

59.01

54.38

58.83

Management estimates of future natural gas price (in dollars per unit)

2.63

2.29

Derivative financial instrume_3

Derivative financial instruments (gains and losses reported in earnings related to commodity derivative instruments) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
(Gain) loss on derivatives	$ (895)	$ 832	$ (126)
Net cash receipts from (payments on) derivatives	(98)	(218)	79
Oil Commodity Derivative
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
(Gain) loss on derivatives	(1,003)	848	(172)
Net cash receipts from (payments on) derivatives	(129)	(213)	79
Natural Gas Commodity Derivative
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
(Gain) loss on derivatives	108	(16)	46
Net cash receipts from (payments on) derivatives	$ 31	$ (5)	$ 0

Derivative financial instrume_4

Derivative financial instruments (outstanding commodity derivative contracts) (Detail) bbl in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl
Oil Basis Swaps 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	47,211
Price (in dollars per unit) | $ / bbl	(0.57)
Oil Basis Swaps Q1 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	14,951
Price (in dollars per unit) | $ / bbl	(0.43)
Oil Basis Swaps Q2 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	11,284
Price (in dollars per unit) | $ / bbl	(0.56)
Oil Basis Swaps Q3 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	10,856
Price (in dollars per unit) | $ / bbl	(0.62)
Oil Basis Swaps Q4 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	10,120
Price (in dollars per unit) | $ / bbl	(0.71)
Oil Basis Swaps 2021
Derivative [Line Items]
Volume (in Mbbls) | bbl	18,980
Price (in dollars per unit) | $ / bbl	0.64
WTI | Oil Price Swaps 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	48,293
Price (in dollars per unit) | $ / bbl	56.98
WTI | Oil Price Swaps Q1 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	14,674
Price (in dollars per unit) | $ / bbl	57.13
WTI | Oil Price Swaps Q2 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	12,494
Price (in dollars per unit) | $ / bbl	56.90
WTI | Oil Price Swaps Q3 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	11,080
Price (in dollars per unit) | $ / bbl	56.88
WTI | Oil Price Swaps Q4 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	10,045
Price (in dollars per unit) | $ / bbl	57
WTI | Oil Price Swaps 2021
Derivative [Line Items]
Volume (in Mbbls) | bbl	18,612
Price (in dollars per unit) | $ / bbl	54.19
Brent | Oil Price Swaps 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	7,880
Price (in dollars per unit) | $ / bbl	60.43
Brent | Oil Price Swaps Q1 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	2,578
Price (in dollars per unit) | $ / bbl	60.78
Brent | Oil Price Swaps Q2 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	2,031
Price (in dollars per unit) | $ / bbl	60.33
Brent | Oil Price Swaps Q3 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	1,768
Price (in dollars per unit) | $ / bbl	60.29
Brent | Oil Price Swaps Q4 2020
Derivative [Line Items]
Volume (in Mbbls) | bbl	1,503
Price (in dollars per unit) | $ / bbl	60.14
Brent | Oil Price Swaps 2021
Derivative [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
Henry Hub | Natural Gas Price Swaps 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.47
Energy (in BBtu) | MMBTU	125,873
Henry Hub | Natural Gas Price Swaps Q1 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.46
Energy (in BBtu) | MMBTU	35,023
Henry Hub | Natural Gas Price Swaps Q2 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.46
Energy (in BBtu) | MMBTU	32,314
Henry Hub | Natural Gas Price Swaps Q3 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.47
Energy (in BBtu) | MMBTU	30,038
Henry Hub | Natural Gas Price Swaps Q4 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.47
Energy (in BBtu) | MMBTU	28,498
Henry Hub | Natural Gas Price Swaps 2021
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.52
Energy (in BBtu) | MMBTU	40,150
EI Paso Permian | Natural Gas Basis Swaps 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.07)
Energy (in BBtu) | MMBTU	93,580
EI Paso Permian | Natural Gas Basis Swaps Q1 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.06)
Energy (in BBtu) | MMBTU	25,770
EI Paso Permian | Natural Gas Basis Swaps Q2 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.07)
Energy (in BBtu) | MMBTU	23,960
EI Paso Permian | Natural Gas Basis Swaps Q3 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.07)
Energy (in BBtu) | MMBTU	22,080
EI Paso Permian | Natural Gas Basis Swaps Q4 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.07)
Energy (in BBtu) | MMBTU	21,770
EI Paso Permian | Natural Gas Basis Swaps 2021
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(0.66)
Energy (in BBtu) | MMBTU	36,500
WAHA | Natural Gas Basis Swaps 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.10)
Energy (in BBtu) | MMBTU	29,280
WAHA | Natural Gas Basis Swaps Q1 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.10)
Energy (in BBtu) | MMBTU	7,280
WAHA | Natural Gas Basis Swaps Q2 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.10)
Energy (in BBtu) | MMBTU	7,280
WAHA | Natural Gas Basis Swaps Q3 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.10)
Energy (in BBtu) | MMBTU	7,360
WAHA | Natural Gas Basis Swaps Q4 2020
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.10)
Energy (in BBtu) | MMBTU	7,360
WAHA | Natural Gas Basis Swaps 2021
Derivative [Line Items]
Price (in dollars per unit) | $ / MMBTU	(0.66)
Energy (in BBtu) | MMBTU	10,950

Debt (summary of long-term debt

Debt (summary of long-term debt) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Credit facility due 2022	$ 0	$ 242
Unamortized original issue discount	(9)	(10)
Senior notes issuance costs, net	(36)	(38)
Less: current portion	0	0
Total long-term debt	3,955	4,194
4.375% senior notes due 2025
Debt Instrument [Line Items]
Unsecured senior notes	$ 600	600
4.375% senior notes due 2025 | January 15, 2020
Debt Instrument [Line Items]
Callable price	103.281%
4.375% senior notes due 2025 | January 15, 2021
Debt Instrument [Line Items]
Callable price	102.188%
4.375% senior notes due 2025 | January 15, 2022
Debt Instrument [Line Items]
Callable price	101.094%
4.375% senior notes due 2025 | January 15, 2023
Debt Instrument [Line Items]
Callable price	100.00%
3.75% senior notes due 2027
Debt Instrument [Line Items]
Unsecured senior notes	$ 1,000	1,000
4.3% senior notes due 2028
Debt Instrument [Line Items]
Unsecured senior notes	1,000	1,000
4.875% senior notes due 2047
Debt Instrument [Line Items]
Unsecured senior notes	800	800
4.85% senior notes due 2048
Debt Instrument [Line Items]
Unsecured senior notes	$ 600	$ 600

Debt (Narrative) (Detail)

Debt (Narrative) (Detail) - USD ($)	Jul. 02, 2018	Sep. 30, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Line Items]
Loss on extinguishment of debt			$ 0	$ 0	$ (66,000,000)
Make-whole premium			$ 0	83,000,000	63,000,000
Credit Facility
Debt Disclosure [Line Items]
Line of credit maturity date			May 9, 2022
Aggregate lender commitments			$ 2,000,000,000
Commitment fee percentage			0.25%
Debt related commitment fees			$ 4,000,000	$ 5,000,000	6,000,000
Unused lender commitments			$ 2,000,000,000
RSP Credit Facility
Debt Disclosure [Line Items]
Interest paid on senior notes	$ 1,000,000
Outstanding principal amount satisfied and discharged	540,000,000
Prime Rate
Debt Disclosure [Line Items]
Line of credit facility, interest rate at period end			4.80%
Alternate Base Rate | Credit Facility
Debt Disclosure [Line Items]
Line of credit facility, interest rate at period end			0.50%
Additional percentage added to federal funds effective rate for ABR loans			0.50%
Additional percentage added to LIBOR rate for ABR loans			1.00%
London Interbank Offered Rate (LIBOR) | Credit Facility
Debt Disclosure [Line Items]
Line of credit facility, interest rate at period end			1.50%
4.3% and 4.85% notes
Debt Disclosure [Line Items]
Unsecured senior notes	1,600,000,000
Proceeds from debt, net of issuance costs	1,579,000,000
4.3% senior notes due 2028
Debt Disclosure [Line Items]
Unsecured senior notes	$ 1,000,000,000
Interest rate	4.30%
Debt issuance price, percentage of par	99.66%
4.85% senior notes due 2048
Debt Disclosure [Line Items]
Unsecured senior notes	$ 600,000,000
Interest rate	4.85%
Debt issuance price, percentage of par	99.74%
6.625% RSP Notes Due 2022
Debt Disclosure [Line Items]
Interest rate	6.625%
Outstanding principal amount redeemed	$ 700,000,000
Make-whole premium	$ 35,000,000
5.25% RSP Notes Due 2025
Debt Disclosure [Line Items]
Interest rate	5.25%
Outstanding principal amount redeemed	$ 450,000,000
Make-whole premium	33,000,000
RSP Notes
Debt Disclosure [Line Items]
Outstanding principal amount redeemed	1,200,000,000
Interest paid on senior notes	$ 14,000,000
3.75% and 4.875% notes
Debt Disclosure [Line Items]
Unsecured senior notes		$ 1,800,000,000
Proceeds from debt, net of issuance costs		1,777,000,000
3.75% senior notes due 2027
Debt Disclosure [Line Items]
Unsecured senior notes		$ 1,000,000,000
Interest rate		3.75%
Debt issuance price, percentage of par		99.636%
4.875% senior notes due 2047
Debt Disclosure [Line Items]
Unsecured senior notes		$ 800,000,000
Interest rate		4.875%
Debt issuance price, percentage of par		99.749%
5.5% unsecured senior notes due 2022
Debt Disclosure [Line Items]
Interest rate		5.50%
Aggregate principal amount of notes offered for tender		$ 600,000,000
5.5% unsecured senior notes due 2023
Debt Disclosure [Line Items]
Interest rate		5.50%
Aggregate principal amount of notes offered for tender		$ 1,550,000,000
5.5% unsecured senior notes
Debt Disclosure [Line Items]
Aggregate principal amount of 5.5% Notes tenders received		$ 1,232,000,000
Percentage of notes tendered		57.30%
Percent of par tendered		102.934%
Percent of par redeemed		102.75%
Senior Notes
Debt Disclosure [Line Items]
Loss on extinguishment of debt					$ 65,000,000

Debt (principal maturities of d

Debt (principal maturities of debt) (Detail) $ in Millions	Dec. 31, 2019USD ($)
Debt Disclosure [Abstract]
2020	$ 0
2021	0
2022	0
2023	0
2024	0
Thereafter	4,000
Total	$ 4,000

Debt (summary of interest expen

Debt (summary of interest expense) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Cash payments for interest	$ 207	$ 118	$ 139
Non-cash interest	6	5	6
Net changes in accruals	(9)	34	4
Interest costs incurred	204	157	149
Less: capitalized interest	(19)	(8)	(3)
Total interest expense	$ 185	$ 149	$ 146

Commitments and contingencies_2

Commitments and contingencies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Annual officers' salaries	$ 10
Regulatory and environmental liabilities	10	$ 26
Environmental remediation expense	13	23	$ 9
Undiscounted lease payments	15
Estimated lease incentives	5
Gross lease cost related to short-term leases	307
Short-term lease costs capitalized	$ 207
Operating leases, lease payments		$ 13	$ 10

Commitments and contingencies_3

Commitments and contingencies (Future commitments) (Details) $ in Millions	Dec. 31, 2019USD ($)
Long-term Purchase Commitment [Line Items]
2020	$ 51
2021	71
2022	38
2023	35
2024	35
Thereafter	103
Total	333
Volume Delivery Commitments
Long-term Purchase Commitment [Line Items]
2020	8
2021	19
2022	19
2023	19
2024	19
Thereafter	54
Total	138
Power Commitments
Long-term Purchase Commitment [Line Items]
2020	14
2021	14
2022	14
2023	14
2024	14
Thereafter	44
Total	114
Other Commitments
Long-term Purchase Commitment [Line Items]
2020	29
2021	38
2022	5
2023	2
2024	2
Thereafter	5
Total	$ 81

Commitments and contingencies_4

Commitments and contingencies (Oil and natural gas delivery commitments) (Details) Mcf in Thousands, bbl in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)bbl / dMcfbbl	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Long-term Purchase Commitment [Line Items]
Provisional change in deferred tax assets and liabilities | $	$ 0	$ (7)	$ (398)
Oil
Long-term Purchase Commitment [Line Items]
2020 | bbl	43
2021 | bbl	51
2022 | bbl	53
2023 | bbl	51
2024 | bbl	47
Thereafter | bbl	114
Total | bbl	359
Minimum daily delivery commitment | bbl / d	50,000,000
Natural Gas
Long-term Purchase Commitment [Line Items]
2020 | Mcf	371
2021 | Mcf	7,267
2022 | Mcf	16,425
2023 | Mcf	16,425
2024 | Mcf	16,470
Thereafter | Mcf	32,850
Total | Mcf	89,808

Commitments and contingencies_5

Commitments and contingencies (Supplemental balance sheet information related to leases) (Details) $ in Millions	Dec. 31, 2019USD ($)
Assets
Operating lease right-of-use assets	$ 15
Finance lease right-of-use assets	16
Total lease right-of-use assets	31
Current:
Operating	8
Finance	7
Noncurrent:
Operating	9
Finance	10
Total lease liabilities	$ 34

Commitments and contingencies_6

Commitments and contingencies (Components of lease expense) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating lease cost	$ 7
Finance lease cost	8
Total lease cost	$ 15

Commitments and contingencies_7

Commitments and contingencies (Supplemental cash flow information related to leases) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$ 8
Financing cash flows from finance leases	7
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	3
Finance leases	$ 9

Commitments and contingencies_8

Commitments and contingencies (Lease terms and discount rates related to leases) (Details)	Dec. 31, 2019
Weighted average remaining lease term (years):
Operating leases	3 years 2 months 12 days
Finance leases	2 years 9 months 18 days
Weighted average discount rate:
Operating leases	4.70%
Finance leases	4.20%

Commitments and contingencies_9

Commitments and contingencies (Maturity of lease liabilities) (Details) $ in Millions	Dec. 31, 2019USD ($)
Operating Lease Liabilities, Payments, Due, Rolling Maturity [Abstract]
2020	$ 8
2021	7
2022	2
2023	0
2024	0
Thereafter	2
Total lease payments	19
Less: interest	(2)
Present value of lease liabilities	17
Finance Lease Liabilities, Payments, Rolling Maturity [Abstract]
2020	7
2021	6
2022	4
2023	1
2024	0
Thereafter	0
Total lease payments	18
Less: interest	(1)
Present value of lease liabilities	$ 17

Commitments and contingencie_10

Commitments and contingencies (Future minimum lease commitments under non-cancellable operating leases) (Details) $ in Millions	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 14
2020	12
2021	10
2022	3
2023	0
Thereafter	1
Total	$ 40

Income taxes (Narrative) (Detai

Income taxes (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jul. 19, 2018
Income Tax Disclosure [Line Items]
Provisional change in deferred tax assets and liabilities	$ 0	$ (7)	$ (398)
Change in state enacted tax rate	(6)
Change in estimated effective statutory state income tax	(21)	(8)	0
Excess tax benefit (deficiency)	0	12	$ 6
Deferred tax liabilities, net	1,654	1,808
Valuation allowance	4	$ 3
RSP Permian
Income Tax Disclosure [Line Items]
Deferred tax liability recognized				$ 515
Internal Revenue Service (IRS)
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	2,600
Tax Year 2034 | Internal Revenue Service (IRS)
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	1,500
Tax Year 2036 | New Mexico Tax Authority
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 749

Income taxes (Income Tax Expens

Income taxes (Income Tax Expense (Benefit) Attributable To Income (Loss) From Continuing Operations) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
U.S. federal	$ 0	$ 0	$ (6)
U.S. state	0	(2)	2
Total current income tax benefit	0	(2)	(4)
Deferred:
U.S. federal	(112)	547	(94)
U.S. state	(42)	58	23
Total deferred income tax expense (benefit)	(154)	605	(71)
Income tax expense (benefit)	$ (154)	$ 603	$ (75)

Income taxes (Reconciliation Be

Income taxes (Reconciliation Between The Income Tax Expense (Benefit) And The Reported Amounts Of Income Tax Expense (Benefit)) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income (loss) at U.S. federal statutory rate	$ (180)	$ 607	$ 308
Non-deductible goodwill	64	0	0
Enactment date and measurement period adjustments from the TCJA	0	(7)	(398)
State income taxes and enacted tax law changes, net of federal tax effect	(13)	52	17
Change in estimated effective statutory state income tax rate	(21)	(8)	0
Excess tax benefit due to stock-based compensation	0	(12)	(6)
Research and development credits, net of unrecognized tax benefits	(11)	(41)	0
Other	7	12	4
Income tax expense (benefit)	$ (154)	$ 603	$ (75)
Effective tax rate	18.00%	21.00%	(9.00%)

Income taxes (Deferred Tax Asse

Income taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Stock-based compensation	$ 24	$ 26
Derivative instruments	23	0
Asset retirement obligation	31	41
Net operating losses and other carryforwards	590	525
Research and development and other credits	73	61
Other	22	17
Total deferred tax assets	763	670
Less: Valuation allowance	(4)	(3)
Net deferred tax assets	759	667
Deferred tax liabilities:
Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes	(2,318)	(2,270)
Equity method investments	(83)	0
Intangible assets - operating rights	(4)	(4)
Derivative instruments	0	(158)
Other	(8)	(43)
Total deferred tax liabilities	(2,413)	(2,475)
Net deferred tax liabilities	$ (1,654)	$ (1,808)

Income taxes (Changes in the Co

Income taxes (Changes in the Company's unrecognized tax benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 72	$ 0
Additions for tax positions acquired	0	26
Additions for prior period tax positions	0	20
Reductions for prior period tax positions	(1)	0
Additions for current tax period positions	11	26
Balance at end of year	82	72
Total that, if recognized, would impact the effective income tax rate	$ 74	$ 63

Major customers and derivativ_3

Major customers and derivative counterparties (Detail) - Revenue from Contract with Customer [Member]	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Plains Marketing and Transportation, Inc.
Revenue, Major Customer [Line Items]
Major customer percentage	17.00%	18.00%	21.00%
Enterprise Crude Oil LLC
Revenue, Major Customer [Line Items]
Major customer percentage	10.00%
Holly Frontier Refining and Marketing, LLC
Revenue, Major Customer [Line Items]
Major customer percentage			10.00%

Related party transactions (Sch

Related party transactions (Schedule of Related Party Transactions) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Director
Related Party Transaction [Line Items]
Amounts paid	$ 7	$ 8	$ 7
Affiliated Entity
Related Party Transaction [Line Items]
Payments made to related parties	40
Payments received	$ 3
General Partner and Owns | Director
Related Party Transaction [Line Items]
Ownership interest in partnership	3.50%

Earnings per share (Reconciliat

Earnings per share (Reconciliation of Earnings Attributable to Common Shares Basic And Diluted) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Net income (loss) as reported	$ (705)	$ 2,286	$ 956
Participating basic earnings (a)	(1)	(17)	(7)
Basic earnings attributable to common stockholders	(706)	2,269	949
Reallocation of participating earnings	0	0	0
Diluted earnings attributable to common stockholders	$ (706)	$ 2,269	$ 949

Earnings Per share (Reconcili_2

Earnings Per share (Reconciliation of The Weighted Average Common Shares Outstanding) (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items]
Basic (in shares)	198,984	170,925	147,320
Diluted (in shares)	198,984	171,249	147,956
Employee Stock Option
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items]
Dilutive shares (in shares)	0	0	3
Performance Shares
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items]
Dilutive shares (in shares)	0	324	633

Earnings per share (Summary of

Earnings per share (Summary of The Common Stock Options and Restricted Stock) (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance Shares
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive performance units (in shares)	431	108	81

Stockholders' equity (Details)

Stockholders' equity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Purchases of common stock under share repurchase program	$ 250,000,000
Dividends, common stock	$ 100,000,000	$ 0	$ 0
Dividend declared (in dollars per share)	$ 0.50
Share Repurchase Program
Class of Stock [Line Items]
Authorized for repurchase	$ 1,500,000,000
Number of shares repurchased and retired	3,300,370
Purchases of common stock under share repurchase program	$ 250,000,000

Other current liabilities (Sche

Other current liabilities (Schedule of Other Current Liabilities) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other current liabilities:
Accrued production costs	$ 175	$ 135
Payroll related matters	37	49
Accrued interest	60	70
Settlements due on derivatives	38	0
Asset retirement obligations	9	11
Other	44	55
Other current liabilities	$ 363	$ 320

Subsidiary guarantors (Condense

Subsidiary guarantors (Condensed Consolidating Balance Sheet) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Assets
Accounts receivable - related parties	$ 0	$ 0
Other current assets	1,055	1,409
Oil and natural gas properties, net	20,890	22,005
Property and equipment, net	437	308
Investment in subsidiaries	0	0
Goodwill	1,917	2,224
Other long-term assets	433	348
Total assets	24,732	26,294
LIABILITIES AND EQUITY
Accounts payable - related parties	0	0
Other current liabilities	1,182	1,356
Long-term debt	3,955	4,194
Other long-term liabilities	1,813	1,976
Equity	17,782	18,768	$ 8,915	$ 7,631
Total liabilities and stockholders’ equity	24,732	26,294
Consolidating Entries
Assets
Accounts receivable - related parties	(17,429)	(18,155)
Other current assets	0	0
Oil and natural gas properties, net	0	0
Property and equipment, net	0	0
Investment in subsidiaries	(5,635)	(5,411)
Goodwill	0	0
Other long-term assets	0	0
Total assets	(23,064)	(23,566)
LIABILITIES AND EQUITY
Accounts payable - related parties	(17,429)	(18,155)
Other current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Equity	(5,635)	(5,411)
Total liabilities and stockholders’ equity	(23,064)	(23,566)
Parent Company | Reportable Legal Entities
Assets
Accounts receivable - related parties	17,429	18,155
Other current assets	10	534
Oil and natural gas properties, net	0	0
Property and equipment, net	0	0
Investment in subsidiaries	5,635	5,411
Goodwill	0	0
Other long-term assets	22	224
Total assets	23,096	24,324
LIABILITIES AND EQUITY
Accounts payable - related parties	0	0
Other current liabilities	211	70
Long-term debt	3,955	4,194
Other long-term liabilities	1,148	1,292
Equity	17,782	18,768
Total liabilities and stockholders’ equity	23,096	24,324
Guarantor Subsidiaries | Reportable Legal Entities
Assets
Accounts receivable - related parties	0	0
Other current assets	1,045	875
Oil and natural gas properties, net	20,874	21,988
Property and equipment, net	437	308
Investment in subsidiaries	0	0
Goodwill	1,917	2,224
Other long-term assets	411	124
Total assets	24,684	25,519
LIABILITIES AND EQUITY
Accounts payable - related parties	17,413	18,138
Other current liabilities	971	1,286
Long-term debt	0	0
Other long-term liabilities	665	684
Equity	5,635	5,411
Total liabilities and stockholders’ equity	24,684	25,519
Non-Guarantor Subsidiaries | Reportable Legal Entities
Assets
Accounts receivable - related parties	0	0
Other current assets	0	0
Oil and natural gas properties, net	16	17
Property and equipment, net	0	0
Investment in subsidiaries	0	0
Goodwill	0	0
Other long-term assets	0	0
Total assets	16	17
LIABILITIES AND EQUITY
Accounts payable - related parties	16	17
Other current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Equity	0	0
Total liabilities and stockholders’ equity	$ 16	$ 17

Subsidiary guarantors (Conden_2

Subsidiary guarantors (Condensed Consolidating Statement of Operations) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Total operating revenues	$ 4,592	$ 4,151	$ 2,586
Total operating costs and expenses	(5,579)	(1,221)	(1,515)
Income (loss) from operations	(987)	2,930	1,071
Interest expense	(185)	(149)	(146)
Loss on extinguishment of debt	0	0	(66)
Other, net	313	108	22
Income (loss) before income taxes	(859)	2,889	881
Income tax (expense) benefit	154	(603)	75
Net income (loss)	(705)	2,286	956
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Total operating revenues	0	0	0
Total operating costs and expenses	0	0	0
Income (loss) from operations	0	0	0
Interest expense	0	0	0
Loss on extinguishment of debt			0
Other, net	(224)	(2,209)	(1,221)
Income (loss) before income taxes	(224)	(2,209)	(1,221)
Income tax (expense) benefit	0	0	0
Net income (loss)	(224)	(2,209)	(1,221)
Parent Company | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Total operating revenues	0	0	0
Total operating costs and expenses	(898)	829	(129)
Income (loss) from operations	(898)	829	(129)
Interest expense	(185)	(149)	(145)
Loss on extinguishment of debt			(66)
Other, net	224	2,209	1,221
Income (loss) before income taxes	(859)	2,889	881
Income tax (expense) benefit	154	(603)	75
Net income (loss)	(705)	2,286	956
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Total operating revenues	4,591	4,146	2,566
Total operating costs and expenses	(4,681)	(2,047)	(1,369)
Income (loss) from operations	(90)	2,099	1,197
Interest expense	0	0	(1)
Loss on extinguishment of debt			0
Other, net	313	108	22
Income (loss) before income taxes	223	2,207	1,218
Income tax (expense) benefit	0	0	0
Net income (loss)	223	2,207	1,218
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Total operating revenues	1	5	20
Total operating costs and expenses	0	(3)	(17)
Income (loss) from operations	1	2	3
Interest expense	0	0	0
Loss on extinguishment of debt			0
Other, net	0	0	0
Income (loss) before income taxes	1	2	3
Income tax (expense) benefit	0	0	0
Net income (loss)	$ 1	$ 2	$ 3

Subsidiary guarantors (Conden_3

Subsidiary guarantors (Condensed Consolidating Statement of Cash Flows) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Net cash flows provided by operating activities	$ 2,836	$ 2,558	$ 1,695
Net cash flows used in investing activities	(1,993)	(2,216)	(1,719)
Net cash provided by (used in) financing activities	(773)	(342)	(29)
Net increase (decrease) in cash and cash equivalents	70	0	(53)
Cash and cash equivalents at beginning of period	0	0	53
Cash and cash equivalents at end of period	70	0	0
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash flows provided by operating activities	0	0	0
Net cash flows used in investing activities	0	0	0
Net cash provided by (used in) financing activities	0	0	0
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Parent Company | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash flows provided by operating activities	607	338	145
Net cash flows used in investing activities	0	0	0
Net cash provided by (used in) financing activities	(607)	(338)	(145)
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash flows provided by operating activities	2,229	2,220	1,549
Net cash flows used in investing activities	(1,993)	(2,216)	(1,105)
Net cash provided by (used in) financing activities	(166)	(4)	(497)
Net increase (decrease) in cash and cash equivalents	70	0	(53)
Cash and cash equivalents at beginning of period	0	0	53
Cash and cash equivalents at end of period	70	0	0
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash flows provided by operating activities	0	0	1
Net cash flows used in investing activities	0	0	(614)
Net cash provided by (used in) financing activities	0	0	613
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	$ 0	$ 0	$ 0

Subsequent events (Narrative) (

Subsequent events (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Millions	Feb. 18, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Dividend declared (in dollars per share)		$ 0.50
Subsequent Event
Subsequent Event [Line Items]
Dividend declared (in dollars per share)	$ 0.20
Dividends payable	$ 39

Subsequent events (New Commodit

Subsequent events (New Commodity Derivative Contracts) (Detail) bbl in Thousands, MMBTU in Thousands	Jan. 01, 2020MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl
Oil Basis Swaps 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		47,211
Price (in dollars per unit) | $ / bbl		(0.57)
Oil Basis Swaps Q1 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		14,951
Price (in dollars per unit) | $ / bbl		(0.43)
Oil Basis Swaps Q2 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		11,284
Price (in dollars per unit) | $ / bbl		(0.56)
Oil Basis Swaps Q3 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		10,856
Price (in dollars per unit) | $ / bbl		(0.62)
Oil Basis Swaps Q4 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		10,120
Price (in dollars per unit) | $ / bbl		(0.71)
Oil Basis Swaps 2021
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		18,980
Price (in dollars per unit) | $ / bbl		0.64
Subsequent Event | Oil Basis Swaps 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	1,462
Price (in dollars per unit) | $ / bbl	1.09
Subsequent Event | Oil Basis Swaps Q1 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
Subsequent Event | Oil Basis Swaps Q2 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	1,092
Price (in dollars per unit) | $ / bbl	1.11
Subsequent Event | Oil Basis Swaps Q3 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	309
Price (in dollars per unit) | $ / bbl	1.05
Subsequent Event | Oil Basis Swaps Q4 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	61
Price (in dollars per unit) | $ / bbl	1
Subsequent Event | Oil Basis Swaps 2021
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	1,460
Price (in dollars per unit) | $ / bbl	1.23
Subsequent Event | Oil Basis Swaps 2022
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
WTI | Oil Price Swaps 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		48,293
Price (in dollars per unit) | $ / bbl		56.98
WTI | Oil Price Swaps Q1 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		14,674
Price (in dollars per unit) | $ / bbl		57.13
WTI | Oil Price Swaps Q2 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		12,494
Price (in dollars per unit) | $ / bbl		56.90
WTI | Oil Price Swaps Q3 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		11,080
Price (in dollars per unit) | $ / bbl		56.88
WTI | Oil Price Swaps Q4 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		10,045
Price (in dollars per unit) | $ / bbl		57
WTI | Oil Price Swaps 2021
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl		18,612
Price (in dollars per unit) | $ / bbl		54.19
WTI | Subsequent Event | Oil Price Swaps 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
WTI | Subsequent Event | Oil Price Swaps Q1 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
WTI | Subsequent Event | Oil Price Swaps Q2 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
WTI | Subsequent Event | Oil Price Swaps Q3 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
WTI | Subsequent Event | Oil Price Swaps Q4 2020
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
WTI | Subsequent Event | Oil Price Swaps 2021
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	365
Price (in dollars per unit) | $ / bbl	55.24
WTI | Subsequent Event | Oil Price Swaps 2022
Subsequent Event [Line Items]
Volume (in Mbbls) | bbl	0
Price (in dollars per unit) | $ / bbl	0
Henry Hub | Natural Gas Price Swaps 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		2.47
Energy (in BBtu) | MMBTU		125,873
Henry Hub | Natural Gas Price Swaps Q1 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		2.46
Energy (in BBtu) | MMBTU		35,023
Henry Hub | Natural Gas Price Swaps Q2 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		2.46
Energy (in BBtu) | MMBTU		32,314
Henry Hub | Natural Gas Price Swaps Q3 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		2.47
Energy (in BBtu) | MMBTU		30,038
Henry Hub | Natural Gas Price Swaps Q4 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		2.47
Energy (in BBtu) | MMBTU		28,498
Henry Hub | Natural Gas Price Swaps 2021
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		2.52
Energy (in BBtu) | MMBTU		40,150
Henry Hub | Subsequent Event | Natural Gas Price Swaps 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
Henry Hub | Subsequent Event | Natural Gas Price Swaps Q1 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
Henry Hub | Subsequent Event | Natural Gas Price Swaps Q2 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
Henry Hub | Subsequent Event | Natural Gas Price Swaps Q3 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
Henry Hub | Subsequent Event | Natural Gas Price Swaps Q4 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
Henry Hub | Subsequent Event | Natural Gas Price Swaps 2021
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.34
Energy (in BBtu) | MMBTU	29,200
Henry Hub | Subsequent Event | Natural Gas Price Swaps 2022
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	2.38
Energy (in BBtu) | MMBTU	36,500
EI Paso Permian | Natural Gas Basis Swaps 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.07)
Energy (in BBtu) | MMBTU		93,580
EI Paso Permian | Natural Gas Basis Swaps Q1 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.06)
Energy (in BBtu) | MMBTU		25,770
EI Paso Permian | Natural Gas Basis Swaps Q2 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.07)
Energy (in BBtu) | MMBTU		23,960
EI Paso Permian | Natural Gas Basis Swaps Q3 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.07)
Energy (in BBtu) | MMBTU		22,080
EI Paso Permian | Natural Gas Basis Swaps Q4 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.07)
Energy (in BBtu) | MMBTU		21,770
EI Paso Permian | Natural Gas Basis Swaps 2021
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(0.66)
Energy (in BBtu) | MMBTU		36,500
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps Q1 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps Q2 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps Q3 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps Q4 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps 2021
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.08)
Energy (in BBtu) | MMBTU	14,600
EI Paso Permian | Subsequent Event | Natural Gas Basis Swaps 2022
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	(0.72)
Energy (in BBtu) | MMBTU	29,200
WAHA | Natural Gas Basis Swaps 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.10)
Energy (in BBtu) | MMBTU		29,280
WAHA | Natural Gas Basis Swaps Q1 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.10)
Energy (in BBtu) | MMBTU		7,280
WAHA | Natural Gas Basis Swaps Q2 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.10)
Energy (in BBtu) | MMBTU		7,280
WAHA | Natural Gas Basis Swaps Q3 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.10)
Energy (in BBtu) | MMBTU		7,360
WAHA | Natural Gas Basis Swaps Q4 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(1.10)
Energy (in BBtu) | MMBTU		7,360
WAHA | Natural Gas Basis Swaps 2021
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU		(0.66)
Energy (in BBtu) | MMBTU		10,950
WAHA | Subsequent Event | Natural Gas Basis Swaps 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
WAHA | Subsequent Event | Natural Gas Basis Swaps Q1 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
WAHA | Subsequent Event | Natural Gas Basis Swaps Q2 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
WAHA | Subsequent Event | Natural Gas Basis Swaps Q3 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
WAHA | Subsequent Event | Natural Gas Basis Swaps Q4 2020
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	0
Energy (in BBtu) | MMBTU	0
WAHA | Subsequent Event | Natural Gas Basis Swaps 2021
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	(1.30)
Energy (in BBtu) | MMBTU	7,300
WAHA | Subsequent Event | Natural Gas Basis Swaps 2022
Subsequent Event [Line Items]
Price (in dollars per unit) | $ / MMBTU	(0.85)
Energy (in BBtu) | MMBTU	7,300