WPX Energy (WPX) 10-Q 31 Oct 19 2019 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Oct. 30, 2019
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	1-35322
Entity Registrant Name	WPX Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	45-1836028
Entity Address, Address Line One	3500 One Williams Center
Entity Address, City or Town	Tulsa,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74172-0172
City Area Code	855
Local Phone Number	979-2012
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	WPX
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		416,740,907
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001518832
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Amendment Flag	false

Consolidated Balance Sheet (Una

Consolidated Balance Sheet (Unaudited) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Current assets:
Cash and Cash Equivalents, at Carrying Value		$ 13	$ 3
Accounts receivable, net of allowance		553	405
Derivative assets, current		169	174
Inventories		46	48
Assets classified as held for sale		0	79
Other		35	30
Total current assets		816	739
Long-term Investments		51	167
Properties and equipment (successful efforts method of accounting)		10,985	9,949
Less—accumulated depreciation, depletion and amortization		(3,411)	(2,683)
Properties and equipment, net		7,574	7,266
Derivative assets, noncurrent		56	4
Other noncurrent assets		123	27
Total assets		8,620	8,203
Current liabilities:
Accounts payable		686	514
Accrued and other current liabilities		209	178
Derivative liabilities, current		35	23
Total current liabilities		930	715
Deferred income taxes		307	201
Long-term debt, net	[1]	2,201	2,485
Derivative liabilities, noncurrent		7	14
Other noncurrent liabilities		532	487
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding)		0	0
Common stock (2 billion shares authorized at $0.01 par value; 418.2 million and 420.6 million shares issued and outstanding at September 30, 2019 and December 31, 2018)		4	4
Additional paid-in-capital		7,698	7,734
Accumulated deficit		(3,059)	(3,437)
Total stockholders’ equity		4,643	4,301
Total liabilities and equity		$ 8,620	$ 8,203
[1]	Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Consolidated Balance Sheet (U_2

Consolidated Balance Sheet (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued and outstanding	418,200,000	420,600,000

Consolidated Statement of Opera

Consolidated Statement of Operations (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues:
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		$ 175	$ (139)	$ 46	$ (362)
Other Income		1	1	2	1
Total revenues		795	484	1,849	1,288
Costs and expenses:
Depreciation, depletion and amortization		241	193	681	551
Lease and facility operating		96	68	276	182
Taxes other than income		46	45	128	116
Exploration (Note 4)		22	18	70	54
General and administrative (including equity-based compensation of $9 million, $8 million, $25 million and $25 million for the respective periods)		51	44	146	131
Other—net		12	1	17	5
Total costs and expenses		553	458	1,575	1,259
Operating income (loss)		242	26	274	29
Interest expense		(38)	(38)	(119)	(123)
Gain (Loss) on Extinguishment of Debt		(47)	0	(47)	(71)
Gains on equity method investment transactions		0	0	373	0
Investment income (loss) and other		4	(2)	7	(2)
Income (loss) from continuing operations before income taxes		161	(14)	488	(167)
Provision (benefit) for income taxes		39	(8)	109	(56)
Income (loss) from continuing operations		122	(6)	379	(111)
Income (loss) from discontinued operations		(1)	(1)	(1)	(92)
Net income (loss)		121	(7)	378	(203)
Preferred Stock Dividends, Income Statement Impact		0	0	0	8
Net income (loss) available to WPX Energy, Inc. common stockholders		121	(7)	378	(211)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share		122	(6)	379	(119)
Income (loss) from discontinued operations		$ (1)	$ (1)	$ (1)	$ (92)
Income (Loss) from Continuing Operations, Per Basic Share		$ 0.29	$ (0.01)	$ 0.90	$ (0.29)
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Basic Share		0	0	0	(0.23)
Earnings Per Share, Basic		$ 0.29	$ (0.01)	$ 0.90	$ (0.52)
Weighted Average Number of Shares Outstanding, Basic		420.8	414	421.4	404.3
Income (Loss) from Continuing Operations, Per Diluted Share		$ 0.29	$ (0.01)	$ 0.89	$ (0.29)
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Diluted Share		0	0	0	(0.23)
Earnings Per Share, Diluted		$ 0.29	$ (0.01)	$ 0.89	$ (0.52)
Weighted Average Number of Shares Outstanding, Diluted	[1]	421.8	414	423	404.3
Oil and Condensate [Member]
Revenues:
Revenue from Customers		$ 539	$ 503	$ 1,499	$ 1,331
Natural Gas, Production [Member]
Revenues:
Revenue from Customers		16	18	57	51
Natural Gas Liquids [Member]
Revenues:
Revenue from Customers		26	33	90	99
Oil and Gas [Member]
Revenues:
Revenue from Customers		581	554	1,646	1,481
Oil and Gas, Refining and Marketing [Member]
Revenues:
Revenue from Customers		38	68	155	168
Costs and expenses:
Cost of Goods and Services Sold		36	63	126	156
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Costs and expenses:
Cost of Goods and Services Sold		$ 49	$ 26	$ 131	$ 64
[1]	Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders, or (ii) application of the treasury stock method to certain nonvested restricted stock units and awards. The excluded amounts are as follows: Three months Nine months 2019 2018 2019 2018 (Millions) Weighted-average nonvested restricted stock units and awards — 3.5 — 3.1 Weighted-average stock options — 0.2 — 0.2 Nonvested restricted stock units and awards antidilutive under the treasury stock method 4.5 — 4.5 —

Consolidated Statement of Ope_2

Consolidated Statement of Operations (parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Non-cash equity-based compensation expense	$ 9	$ 8	$ 25	$ 25

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity (Unaudited) - USD ($) $ in Millions	Total	Preferred Stock	Common Stock	Additional Paid-In- Capital	Accumulated Deficit
Beginning Balance at Dec. 31, 2017	$ 4,127	$ 232	$ 4	$ 7,479	$ (3,588)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(203)				(203)
Stock-based compensation, net of tax impact	23			23
Conversion of preferred stock to common stock		(232)		232
Dividends on preferred stock	8			8
Ending Balance at Sep. 30, 2018	3,939	0	4	7,726	(3,791)
Beginning Balance at Jun. 30, 2018	3,935	232	4	7,483	(3,784)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(7)				(7)
Stock-based compensation, net of tax impact	11			11
Conversion of preferred stock to common stock		(232)		232
Dividends on preferred stock	0			0
Ending Balance at Sep. 30, 2018	3,939	0	4	7,726	(3,791)
Beginning Balance at Dec. 31, 2018	4,301	0	4	7,734	(3,437)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	378				378
Stock-based compensation, net of tax impact	12			12
Equity transaction costs	(5)			(5)
Repurchases of common stock	43			43
Ending Balance at Sep. 30, 2019	4,643	0	4	7,698	(3,059)
Beginning Balance at Jun. 30, 2019	4,561	0	4	7,737	(3,180)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	121				121
Stock-based compensation, net of tax impact	9			9
Equity transaction costs	(5)			(5)
Repurchases of common stock	43			43
Ending Balance at Sep. 30, 2019	$ 4,643	$ 0	$ 4	$ 7,698	$ (3,059)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018
Operating Activities(a)
Net income (loss)		$ 378	$ (203)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation Depletion And Amortization Including Discontinued Portion		681	559
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations		106	(84)
Provision For Impairment Of Properties And Equipment Including Certain Exploration Expenses And Equity Method Investment		62	53
Gains related to equity method investment transactions		373	0
Net (gain) loss on derivatives		(46)	362
Net settlements related to derivatives		3	(218)
Amortization of stock-based awards		26	26
Gain (Loss) on Extinguishment of Debt		(47)	(71)
Net (gain) loss on sales of assets including discontinued operations		0	150
Cash provided by (used in) operating assets and liabilities:
Accounts receivable		(193)	(61)
Inventories		1	(15)
Other current assets		(2)	5
Accounts payable		225	71
Federal income taxes receivable		38	0
Accrued and other current liabilities		(40)	(48)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations		(22)	(37)
Other, including changes in other noncurrent assets and liabilities		15	21
Net cash provided by operating activities(a)	[1]	906	652
Investing Activities(a)
Capital Expenditures	[2]	(1,090)	(1,013)
Proceeds from sales of assets		589	682
Purchase of or contributions to investments		(18)	(72)
Proceeds from Equity Method Investment, Distribution, Return of Capital		11	0
Payments for (Proceeds from) Other Investing Activities		(1)	0
Net cash provided by (used in) investing activities(a)	[1]	(507)	(403)
Financing Activities
Proceeds from common stock		1	9
Dividends paid on preferred stock		0	(11)
Payments for Repurchase of Common Stock		43	0
Borrowings on credit facility		1,281	726
Payments on credit facility		(1,611)	(638)
Proceeds from long-term debt		593	494
Payments for retirement of long-term debt		594	986
Taxes paid for shares withheld		(16)	(13)
Payments for debt issuance costs and credit facility amendment fees		2	10
Proceeds from (Payments for) Other Financing Activities		6	29
Net cash provided by (used in) financing activities		(385)	(400)
Net decrease in cash and cash equivalents and restricted cash		14	(151)
Cash, cash equivalents and restricted cash at beginning of period		18	201
Cash and cash equivalents and restricted cash at end of period		32	50
Increase to properties and equipment		(1,030)	(1,074)
Changes In Related Accounts Payable		$ (60)	$ 61
[1]	(a) Amounts reflect continuing and discontinued operations unless otherwise noted.
[2]	(b) Increase to properties and equipment (1,030) (1074) Changes in related accounts payable and accounts receivable (60) 61 Capital expenditures (1,090) (1013)

Basis of Presentation and Descr

Basis of Presentation and Description of Business	9 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Basis of Presentation and Description of Business	Description of Business and Basis of Presentation Description of Business Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from other third-parties in our operating areas in conjunction with the management of various commodity related contracts such as transportation. We have sold certain operations which are reported as discontinued operations and are discussed in Note 2 of Notes to Consolidated Financial Statements. The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.” Basis of Presentation The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2018 in the Company's Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2019, results of operations for the three and nine months ended September 30, 2019 and 2018, changes in equity for the three and nine months ended September 30, 2019 and 2018, and cash flows for the nine months ended September 30, 2019 and 2018. The Company has no element of comprehensive income (loss) other than net income (loss). The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States. Discontinued Operations See Note 2 for a discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Recently Adopted Accounting Standards The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases , effective January 1, 2019. The standard requires the recognition of right-of-use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right-of-use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess: • whether existing contracts are or contain leases; • lease classification for any expired or existing leases; • initial direct costs for any existing lease; and • whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease. See Note 9 for additional information related to our contracts that are or contain leases. We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019 . This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period. Accounting Standards Not Yet Adopted In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses . This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This ASU will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this ASU will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of material credit losses. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.

Discontinued Operations (Notes)

Discontinued Operations (Notes)	9 Months Ended
	Sep. 30, 2019
Discontinued operations [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Discontinued OperationsIn first-quarter 2018, we sold our properties in the San Juan Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. The current remaining commitment is approximately $277 million. We believed and continue to believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and the purchaser, and the declining size of the obligations subject to the guarantee over time. As part of the divestiture, we determined the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018. Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years associated with our exit from the Powder River Basin. Summarized Results of Discontinued Operations The following table presents the results of our discontinued operations for the nine months ended September 30, 2018. For the three and nine months ended September 30, 2019 and the three months ended September 30, 2018, our discontinued operations activity was minimal and therefore is not included in the table below. Nine months 2018 (Millions) Total revenues $ 75 Costs and expenses: Depreciation, depletion and amortization $ 8 Lease and facility operating 7 Gathering, processing and transportation 12 Taxes other than income 5 General and administrative 1 Exploration 3 Accretion for transportation and gathering obligations retained 5 Other—net 4 Total costs and expenses 45 Operating income 30 Loss on sale of assets (151) Loss from discontinued operations before income taxes (121) Income tax benefit (29) Loss from discontinued operations $ (92) Cash Flows Attributable to Discontinued Operations Cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $22 million and $37 million for the nine months ended September 30, 2019 and 2018, respectively. In addition, cash flows related to San Juan Gallup were $44 million of cash provided by operating activities, excluding income taxes and changes in working capital items, and $29 million of cash capital expenditures within investing activities for the nine months ended September 30, 2018.

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share from Continuing Operations	9 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share from Continuing Operations	Earnings (Loss) Per Common Share from Continuing Operations The following table summarizes the calculation of earnings per share. Three months Nine months 2019 2018 2019 2018 (Millions, except per-share amounts) Income (loss) from continuing operations $ 122 $ (6) $ 379 $ (111) Less: Dividends on preferred stock — — — 8 Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share $ 122 $ (6) $ 379 $ (119) Basic weighted-average shares 420.8 414.0 421.4 404.3 Effect of dilutive securities(a) 1.0 — 1.6 — Diluted weighted-average shares 421.8 414.0 423.0 404.3 Earnings (loss) per common share from continuing operations: Basic $ 0.29 $ (0.01) $ 0.90 $ (0.29) Diluted $ 0.29 $ (0.01) $ 0.89 $ (0.29) __________ (a) Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders, or (ii) application of the treasury stock method to certain nonvested restricted stock units and awards. The excluded amounts are as follows: Three months Nine months 2019 2018 2019 2018 (Millions) Weighted-average nonvested restricted stock units and awards — 3.5 — 3.1 Weighted-average stock options — 0.2 — 0.2 Nonvested restricted stock units and awards antidilutive under the treasury stock method 4.5 — 4.5 —

Asset Sales and Exploration Exp

Asset Sales and Exploration Expense	9 Months Ended
	Sep. 30, 2019
Extractive Industries [Abstract]
Asset Sales, Exploration Expenses And Other Accruals [Text Block]	Asset Sale, Equity Method Investment Transactions, Exploration Expenses and Other Asset Sale During the first quarter of 2019, we closed on the sale of certain non-core properties, primarily proved, in the Delaware Basin which were held for sale at December 31, 2018. We received approximately $83 million in proceeds. No gain or loss was recorded on this transaction. Equity Method Investment Transactions During the first quarter of 2019, we closed on the sale of our 20 percent equity interest in the Whitewater natural gas pipeline. The net book value of this equity method investment at the time of disposition was approximately $15 million. As a result of this transaction, we recorded a $126 million gain. During the second quarter of 2019, we received a distribution of approximately $357 million related to our 25 percent equity interest in the Oryx pipeline partnership after the underlying assets were sold. This transaction is subject to post-closing adjustments. The net book value of this equity method investment was approximately $110 million as of the closing date. As a result of this transaction, we recorded a gain of $247 million. Exploration Expenses The following table presents a summary of exploration expenses. Three months Nine months 2019 2018 2019 2018 (Millions) Unproved leasehold property amortization $ 20 $ 18 $ 64 $ 51 Geologic and geophysical costs 2 — 6 3 Total exploration expenses $ 22 $ 18 $ 70 $ 54 Other In third-quarter 2019, we recorded an $11 million charge included in Other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin. The offer is still pending.

Inventories

Inventories	9 Months Ended
	Sep. 30, 2019
Inventory Disclosure [Abstract]
Inventories	Inventories The following table presents a summary of our inventories as of the dates indicated. September 30, December 31, (Millions) Material, supplies and other $ 42 $ 46 Commodity production in transit or storage 4 2 Total inventories $ 46 $ 48

Debt and Banking Arrangements

Debt and Banking Arrangements	9 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Debt and Banking Arrangements	Debt and Banking Arrangements The following table presents a summary of our debt as of the dates indicated. September 30, December 31, (Millions) Credit facility agreement $ — $ 330 6.000% Senior Notes due 2022 73 529 8.250% Senior Notes due 2023 406 500 5.250% Senior Notes due 2024 650 650 5.750% Senior Notes due 2026 500 500 5.250% Senior Notes due 2027 600 — Total long-term debt $ 2,229 $ 2,509 Less: Debt issuance costs on long-term debt(a) 28 24 Total long-term debt, net(a) $ 2,201 $ 2,485 __________ (a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. Credit Facility As of September 30, 2019, we had no borrowings outstanding and $37 million of letters of credit issued under the Credit Facility and we were in compliance with our financial covenants with full access to the Credit Facility. On April 22, 2019, the Company entered into a Third Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, the Swingline Lender and each of the issuing banks party thereto (the "Credit Facility"). The Credit Facility, as amended, gives the Company the option, if certain conditions are met, to elect during any Collateral Trigger Period that scheduled redeterminations of the Borrowing Base be made annually on April 1 instead of semi-annually. Additionally in April 2019, the Borrowing Base was increased to $2.1 billion and will remain in effect until the next Redetermination Date as described above. At this time, the Credit Facility Agreement is limited by the total commitments which remained at $1.5 billion. See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information on covenants related to our Credit Facility. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended. Senior Notes On September 24, 2019, we completed a debt offering of $600 million of 5.250% Senior Notes due in 2027 (the “2027 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on April 15 and October 15 of each year commencing on April 15, 2020. The 2027 Notes will mature on October 15, 2027 with the option, prior to October 15, 2022, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, at any time on or after October 15, 2022, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2027 Notes was approximately $592.5 million and approximately $2 million of debt issuance costs were capitalized. The net proceeds from this offering were used to fund the purchase of $550 million aggregate principal amount of our 2022 Notes and 2023 Notes through cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $47 million, which includes approximately $44 million of premium and approximately $3 million write-off of previously capitalized costs. See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional discussion related to our senior notes.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	9 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes The following table presents the provision (benefit) for income taxes from continuing operations. Three months Nine months 2019 2018 2019 2018 (Millions) Current: Federal $ — $ — $ — $ — State 1 (1) 2 (1) 1 (1) 2 (1) Deferred: Federal 33 (6) 96 (43) State 5 (1) 11 (12) 38 (7) 107 (55) Total provision (benefit) $ 39 $ (8) $ 109 $ (56) The effective income tax rate for the three months ended September 30, 2019, differs from the federal statutory rate of 21 percent due to the effect of state income taxes. The effective income tax rate for the three months ended September 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of state income taxes. The effective income tax rate for the nine months ended September 30, 2019, differs slightly from the federal statutory rate of 21 percent due to the effect of state income taxes and equity-based compensation, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gains from the 2019 transactions involving equity interests in partnerships. The effective income tax rate for the nine months ended September 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of an adjustment to state deferred taxes as a result of a decrease in the blended state income tax rate due to changes in state apportionment factors resulting from the divestment of our San Juan Basin assets. We have recorded valuation allowances against deferred tax assets attributable primarily to certain state net operating loss (“NOL”) carryovers. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. We have not recorded a valuation allowance against our federal NOL carryover, but a valuation allowance could be required in future periods if the federal NOL carryover increases or circumstances change. The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three-year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of September 30, 2019, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015 (“RKI”). Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the acquisition. Pursuant to our tax sharing agreement with The Williams Companies, Inc. (“Williams”), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre-spin-off period for which we continue to have exposure to audit adjustments as part of Williams. In 2017, the IRS proposed an adjustment related to our business for which a payment to Williams could be required. We, along with Williams, have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS. As of September 30, 2019, the Company has approximately $9 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. Currently, we do not expect ultimate resolution of our uncertain tax position during the next 12 months.

Contingent Liabilities

Contingent Liabilities	9 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities	Contingent Liabilities and Commitments Contingent Liabilities Royalty litigation Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to many of our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. Environmental matters The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance. Matters related to Williams’ former power business In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications. Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. In February, 2019, settlement agreements with the Kansas and Missouri class claimants were executed, and on August 5, 2019, after the final fairness hearing, the court approved the settlement and entered final judgment. In the Wisconsin class action, defendants' motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs' motion to remand the case to the originally filed district court. In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court, and the MDL Court has now remanded the case to the United States District Court for the District of Kansas. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time. Other Indemnifications Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements. The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in such litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. As of September 30, 2019, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made. In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it. Summary As of September 30, 2019 and December 31, 2018, the Company had accrued approximately $11 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year. Commitments During 2019, primarily in the second quarter, we contracted for additional oil and natural gas transportation capacity to other locations in attempts to avoid location constraints and obtain more favorable pricing differentials. This capacity is associated with projects for which the counterparties have not yet begun construction. Related minimum commitments, when construction is complete and facilities are in service, total approximately $880 million over a five to ten year period with annual demand payments, beginning in 2020, ranging from approximately $19 million to $118 million.

Leases

Leases	9 Months Ended
	Sep. 30, 2019
Leases [Abstract]
Leases of Lessee Disclosure [Text Block]	Leases Our contracts that are leases or contain leases primarily relate to drilling rigs, compression units and office space. Leases are recorded on the balance sheet when the lease term exceeds one year and we direct the use of an identified asset while receiving substantially all of the economic benefit of the asset. Right-of-use assets are included in other noncurrent assets on the Consolidated Balance Sheet. Lease liabilities are included in accrued and other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheet. We have elected to include both lease and non-lease components for all significant asset classes as a single lease component for measurement purposes. Leases with an initial term of 12 months or less are not recorded on the balance sheet and lease expense for these leases is recognized as incurred. We have elected to include lease costs associated with lease terms of one month or less in our short-term lease disclosure below. We use judgments and assumptions to determine our discount rate and whether a contract contains a lease. The discount rate used to determine the lease payment liability is based on our estimated incremental borrowing rate. Certain of our leases include rental payments adjusted periodically for inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. From time to time we may enter into lease contracts that commence in future periods. Lease contracts that will commence subsequent to September 30, 2019 are not significant. The following tables include quantitative disclosures related to our leases. Nine months ended September 30, 2019 (Millions) Lease Costs: Leases recorded on the Consolidated Balance Sheet: Operating lease cost—drilling rigs(a) $ 31 Operating lease cost—other(a) 14 Variable lease cost—drilling rigs(a) 4 Variable lease cost—other(a) 3 Short-term leases: Drilling rigs(b) 30 Other(b) 89 Total lease cost $ 171 Other Information: Cash paid for amount included in the measurement of lease liabilities: Operating cash flows used for operating leases(a) $ 14 Investing cash flows used for operating leases(a) $ 31 Right-of-use assets obtained in exchange for new operating lease liabilities $ 44 Weighted-average remaining lease term (in years) 1.59 years Weighted-average discount rate—operating leases 5 % __________ (a) Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners. (b) Includes variable lease costs on short-term leases. The following tables include quantitative disclosures related to our leases as of September 30, 2019. Drilling Rigs Real Estate, Compression and Other Total Undiscounted Cash Flows (Millions) Maturity of Lease Liabilities: October 2019 through December 2019 $ 11 $ 5 $ 16 2020 44 18 62 2021 5 10 15 2022 — 1 1 2023 — — — Thereafter — — — $ 94 Current lease liabilities $ 43 $ 17 $ 60 Noncurrent lease liabilities 16 15 31 Total lease liabilities $ 59 $ 32 $ 91 Difference between undiscounted cash flows and discounted cash flows $ 3 Total right-of-use assets on Consolidated Balance Sheet $ 91

Stockholders' Equity

Stockholders' Equity	9 Months Ended
	Sep. 30, 2019
Equity [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Stockholders' Equity Share Repurchase Program On August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over a 24 month period. Under the share repurchase program, we may repurchase shares at management’s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume, general market conditions, legal requirements, general business conditions and corporate considerations determined by WPX’s management, such as liquidity and capital needs. This share repurchase program may be modified, suspended or terminated at any time by our Board of Directors. As of September 30, 2019, we have repurchased approximately 4.2 million shares under the program at an average price of $10.23. Transaction Costs In September and October 2019, we entered into strategic relationships with two third parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. WPX will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds. WPX holds a controlling financial interest in these partnerships. Accordingly, we will consolidate the financial results of these entities and will present the portion attributable to the third parties as a noncontrolling interest in our consolidated financial statements. We incurred approximately $5 million of costs associated with the formation of the partnerships which are recognized as a reduction of additional paid-in-capital within stockholders’ equity attributable to WPX.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The following table presents, by level within the fair value hierarchy, certain assets and liabilities at fair value on a recurring basis for disclosure. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. September 30, 2019 December 31, 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 225 $ — $ 225 $ — $ 175 $ 3 $ 178 Energy derivative liabilities $ — $ 42 $ — $ 42 $ — $ 37 $ — $ 37 Total debt(a) $ — $ 2,317 $ — $ 2,317 $ — $ 2,414 $ — $ 2,414 __________ (a) The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of September 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings. Energy derivatives include commodity-based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts may include forwards, swaps, options or swaptions. These are carried at fair value on the Consolidated Balance Sheets. Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions. The determination of fair value for our derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our derivative liabilities does not consider noncash collateral credit enhancements. Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as calls and collars that are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold calls or swaptions establish a maximum price we will receive for the volumes under contract and are financially settled. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a quarterly basis. Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million and $3 million included in Level 3 as of September 30, 2019 and December 31, 2018, respectively. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended September 30, 2019 and 2018. There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

Derivatives and Concentration o

Derivatives and Concentration of Credit Risk	9 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Derivatives and Concentration of Credit Risk	Derivatives and Concentration of Credit Risk Energy Commodity Derivatives Risk Management Activities We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of crude oil, natural gas and natural gas liquids attributable to commodity price risk. We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaption. Derivatives related to production The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2019. Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Crude Oil Crude Oil Oct - Dec 2019 Fixed Price Swaps WTI (83,000) $ 56.72 Crude Oil Oct - Dec 2019 Basis Swaps Midland/Cushing (22,000) $ (1.37) Crude Oil Oct - Dec 2019 Basis Swaps Nymex CMA Roll (13,261) $ 0.11 Crude Oil Oct - Dec 2019 Basis Swaps Magellan East Houston (2,000) $ 4.63 Crude Oil Oct - Dec 2019 Basis Swaps Magellan East Houston/Midland (9,000) $ 6.02 Crude Oil Oct - Dec 2019 Basis Swaps Argus LLS/Midland (2,000) $ 8.60 Crude Oil Oct - Dec 2019 Basis Swaps Magellan East Houston/Argus LLS (2,000) $ 0.75 Crude Oil Oct - Dec 2019 Basis Swaps Clearbrook (8,000) $ (3.23) Crude Oil Oct - Dec 2019 Fixed Price Calls WTI (5,000) $ 54.08 Crude Oil Oct - Dec 2019 Fixed Price Collars WTI (8,000) $50.00 - $60.19 Crude Oil 2020 Fixed Price Swaps WTI (45,000) $ 57.10 Crude Oil 2020 Basis Swaps Midland/Cushing (7,486) $ (1.31) Crude Oil 2020 Basis Swaps Brent/WTI Spread (5,000) $ 8.36 Crude Oil 2020 Fixed Price Collars WTI (20,000) $53.33 - $63.48 Crude Oil 2021 Basis Swaps Brent/WTI Spread (1,000) $ 8.00 Crude Oil 2022 Basis Swaps Brent/WTI Spread (1,000) $ 7.75 Natural Gas Natural Gas Oct - Dec 2019 Fixed Price Swaps Henry Hub (110) $ 3.07 Natural Gas Oct - Dec 2019 Basis Swaps Permian (25) $ (0.39) Natural Gas Oct - Dec 2019 Basis Swaps Waha (35) $ 0.81 Natural Gas Oct - Dec 2019 Basis Swaps Houston Ship Channel (30) $ (0.09) Natural Gas 2020 Basis Swaps Waha (60) $ (0.79) Natural Gas 2021 Basis Swaps Waha (70) $ (0.59) Natural Gas 2022 Basis Swaps Waha (70) $ (0.57) Natural Gas 2023 Basis Swaps Waha (70) $ (0.51) __________ (a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls or swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. (b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. (c) The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu. Fair values and gains (losses) Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. Net gain (loss) on derivatives on the Consolidated Statements of Operations includes net settlements to be received of $4 million and $3 million for the three and nine months ended September 30, 2019, respectively, and net settlements to be paid of $85 million and $218 million for the three and nine months ended September 30, 2018, respectively. The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows. Offsetting of derivative assets and liabilities The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Net Amount September 30, 2019 (Millions) Derivative assets with right of offset or master netting agreements $ 225 $ (39) $ 186 Derivative liabilities with right of offset or master netting agreements $ (42) $ 39 $ (3) December 31, 2018 Derivative assets with right of offset or master netting agreements $ 178 $ (37) $ 141 Derivative liabilities with right of offset or master netting agreements $ (37) $ 37 $ — __________ (a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts. Credit-risk-related features Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. As of September 30, 2019, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $3 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. Assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, the additional collateral that we would have been required to post at September 30, 2019 was $3 million. Concentration of Credit Risk Cash equivalents Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. 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. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Derivative assets and liabilities We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties. We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2019 and 2018, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. Our gross and net credit exposure from our derivative contracts were $225 million and $186 million, respectively, as of September 30, 2019. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade. Our seven largest net counterparty positions represent approximately 86 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities. One of our senior officers is on the board of directors of NGL Energy Partners, LP (“NGL Energy”). In the normal course of business, we sell crude oil to NGL Energy. For the first nine months of 2019, sales to NGL Energy were approximately 13 percent of our total consolidated revenues adjusted for loss on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent approximately 1 percent of operating expenses. Other Collateral support for our commodity agreements could include margin deposits, letters of credit, surety bonds and guarantees of payment by credit worthy parties.

Accounting Policies (Policies)

Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Recently Adopted Accounting Standards The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases , effective January 1, 2019. The standard requires the recognition of right-of-use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right-of-use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess: • whether existing contracts are or contain leases; • lease classification for any expired or existing leases; • initial direct costs for any existing lease; and • whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease. See Note 9 for additional information related to our contracts that are or contain leases. We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019 . This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period.
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	Accounting Standards Not Yet Adopted In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses . This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This ASU will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this ASU will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of material credit losses. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.

Discontinued Operation (Tables)

Discontinued Operation (Tables)	9 Months Ended
	Sep. 30, 2019
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]	The following table presents the results of our discontinued operations for the nine months ended September 30, 2018. For the three and nine months ended September 30, 2019 and the three months ended September 30, 2018, our discontinued operations activity was minimal and therefore is not included in the table below. Nine months 2018 (Millions) Total revenues $ 75 Costs and expenses: Depreciation, depletion and amortization $ 8 Lease and facility operating 7 Gathering, processing and transportation 12 Taxes other than income 5 General and administrative 1 Exploration 3 Accretion for transportation and gathering obligations retained 5 Other—net 4 Total costs and expenses 45 Operating income 30 Loss on sale of assets (151) Loss from discontinued operations before income taxes (121) Income tax benefit (29) Loss from discontinued operations $ (92)

Earnings (Loss) Per Common Sh_2

Earnings (Loss) Per Common Share from Continuing Operations (Tables)	9 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share from Continuing Operations	The following table summarizes the calculation of earnings per share. Three months Nine months 2019 2018 2019 2018 (Millions, except per-share amounts) Income (loss) from continuing operations $ 122 $ (6) $ 379 $ (111) Less: Dividends on preferred stock — — — 8 Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share $ 122 $ (6) $ 379 $ (119) Basic weighted-average shares 420.8 414.0 421.4 404.3 Effect of dilutive securities(a) 1.0 — 1.6 — Diluted weighted-average shares 421.8 414.0 423.0 404.3 Earnings (loss) per common share from continuing operations: Basic $ 0.29 $ (0.01) $ 0.90 $ (0.29) Diluted $ 0.29 $ (0.01) $ 0.89 $ (0.29) __________ (a) Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders, or (ii) application of the treasury stock method to certain nonvested restricted stock units and awards. The excluded amounts are as follows: Three months Nine months 2019 2018 2019 2018 (Millions) Weighted-average nonvested restricted stock units and awards — 3.5 — 3.1 Weighted-average stock options — 0.2 — 0.2 Nonvested restricted stock units and awards antidilutive under the treasury stock method 4.5 — 4.5 —

Exploration Expense (Tables)

Exploration Expense (Tables)	9 Months Ended
	Sep. 30, 2019
Extractive Industries [Abstract]
Exploration Expenses	The following table presents a summary of exploration expenses. Three months Nine months 2019 2018 2019 2018 (Millions) Unproved leasehold property amortization $ 20 $ 18 $ 64 $ 51 Geologic and geophysical costs 2 — 6 3 Total exploration expenses $ 22 $ 18 $ 70 $ 54

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Sep. 30, 2019
Inventory Disclosure [Abstract]
Inventories	The following table presents a summary of our inventories as of the dates indicated. September 30, December 31, (Millions) Material, supplies and other $ 42 $ 46 Commodity production in transit or storage 4 2 Total inventories $ 46 $ 48

Debt and Banking Arrangements (

Debt and Banking Arrangements (Tables)	9 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Debt	The following table presents a summary of our debt as of the dates indicated. September 30, December 31, (Millions) Credit facility agreement $ — $ 330 6.000% Senior Notes due 2022 73 529 8.250% Senior Notes due 2023 406 500 5.250% Senior Notes due 2024 650 650 5.750% Senior Notes due 2026 500 500 5.250% Senior Notes due 2027 600 — Total long-term debt $ 2,229 $ 2,509 Less: Debt issuance costs on long-term debt(a) 28 24 Total long-term debt, net(a) $ 2,201 $ 2,485 __________ (a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes from Continuing Operations	The following table presents the provision (benefit) for income taxes from continuing operations. Three months Nine months 2019 2018 2019 2018 (Millions) Current: Federal $ — $ — $ — $ — State 1 (1) 2 (1) 1 (1) 2 (1) Deferred: Federal 33 (6) 96 (43) State 5 (1) 11 (12) 38 (7) 107 (55) Total provision (benefit) $ 39 $ (8) $ 109 $ (56)

Leases (Tables)

Leases (Tables)	9 Months Ended
	Sep. 30, 2019
Leases [Abstract]
Lease, Cost [Table Text Block]	The following tables include quantitative disclosures related to our leases. Nine months ended September 30, 2019 (Millions) Lease Costs: Leases recorded on the Consolidated Balance Sheet: Operating lease cost—drilling rigs(a) $ 31 Operating lease cost—other(a) 14 Variable lease cost—drilling rigs(a) 4 Variable lease cost—other(a) 3 Short-term leases: Drilling rigs(b) 30 Other(b) 89 Total lease cost $ 171 Other Information: Cash paid for amount included in the measurement of lease liabilities: Operating cash flows used for operating leases(a) $ 14 Investing cash flows used for operating leases(a) $ 31 Right-of-use assets obtained in exchange for new operating lease liabilities $ 44 Weighted-average remaining lease term (in years) 1.59 years Weighted-average discount rate—operating leases 5 % __________ (a) Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners. (b) Includes variable lease costs on short-term leases.
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	The following tables include quantitative disclosures related to our leases as of September 30, 2019. Drilling Rigs Real Estate, Compression and Other Total Undiscounted Cash Flows (Millions) Maturity of Lease Liabilities: October 2019 through December 2019 $ 11 $ 5 $ 16 2020 44 18 62 2021 5 10 15 2022 — 1 1 2023 — — — Thereafter — — — $ 94 Current lease liabilities $ 43 $ 17 $ 60 Noncurrent lease liabilities 16 15 31 Total lease liabilities $ 59 $ 32 $ 91 Difference between undiscounted cash flows and discounted cash flows $ 3 Total right-of-use assets on Consolidated Balance Sheet $ 91

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents, by level within the fair value hierarchy, certain assets and liabilities at fair value on a recurring basis for disclosure. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. September 30, 2019 December 31, 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 225 $ — $ 225 $ — $ 175 $ 3 $ 178 Energy derivative liabilities $ — $ 42 $ — $ 42 $ — $ 37 $ — $ 37 Total debt(a) $ — $ 2,317 $ — $ 2,317 $ — $ 2,414 $ — $ 2,414 __________ (a) The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of September 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

Derivatives and Concentration_2

Derivatives and Concentration of Credit Risk (Tables)	9 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Derivative Volume that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production	The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2019. Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Crude Oil Crude Oil Oct - Dec 2019 Fixed Price Swaps WTI (83,000) $ 56.72 Crude Oil Oct - Dec 2019 Basis Swaps Midland/Cushing (22,000) $ (1.37) Crude Oil Oct - Dec 2019 Basis Swaps Nymex CMA Roll (13,261) $ 0.11 Crude Oil Oct - Dec 2019 Basis Swaps Magellan East Houston (2,000) $ 4.63 Crude Oil Oct - Dec 2019 Basis Swaps Magellan East Houston/Midland (9,000) $ 6.02 Crude Oil Oct - Dec 2019 Basis Swaps Argus LLS/Midland (2,000) $ 8.60 Crude Oil Oct - Dec 2019 Basis Swaps Magellan East Houston/Argus LLS (2,000) $ 0.75 Crude Oil Oct - Dec 2019 Basis Swaps Clearbrook (8,000) $ (3.23) Crude Oil Oct - Dec 2019 Fixed Price Calls WTI (5,000) $ 54.08 Crude Oil Oct - Dec 2019 Fixed Price Collars WTI (8,000) $50.00 - $60.19 Crude Oil 2020 Fixed Price Swaps WTI (45,000) $ 57.10 Crude Oil 2020 Basis Swaps Midland/Cushing (7,486) $ (1.31) Crude Oil 2020 Basis Swaps Brent/WTI Spread (5,000) $ 8.36 Crude Oil 2020 Fixed Price Collars WTI (20,000) $53.33 - $63.48 Crude Oil 2021 Basis Swaps Brent/WTI Spread (1,000) $ 8.00 Crude Oil 2022 Basis Swaps Brent/WTI Spread (1,000) $ 7.75 Natural Gas Natural Gas Oct - Dec 2019 Fixed Price Swaps Henry Hub (110) $ 3.07 Natural Gas Oct - Dec 2019 Basis Swaps Permian (25) $ (0.39) Natural Gas Oct - Dec 2019 Basis Swaps Waha (35) $ 0.81 Natural Gas Oct - Dec 2019 Basis Swaps Houston Ship Channel (30) $ (0.09) Natural Gas 2020 Basis Swaps Waha (60) $ (0.79) Natural Gas 2021 Basis Swaps Waha (70) $ (0.59) Natural Gas 2022 Basis Swaps Waha (70) $ (0.57) Natural Gas 2023 Basis Swaps Waha (70) $ (0.51) __________ (a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls or swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. (b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. (c) The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.
Gross And Net Derivative Assets and Liabilities	The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Net Amount September 30, 2019 (Millions) Derivative assets with right of offset or master netting agreements $ 225 $ (39) $ 186 Derivative liabilities with right of offset or master netting agreements $ (42) $ 39 $ (3) December 31, 2018 Derivative assets with right of offset or master netting agreements $ 178 $ (37) $ 141 Derivative liabilities with right of offset or master netting agreements $ (37) $ 37 $ — __________ (a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Basis of Presentation and Des_2

Basis of Presentation and Description of Business- Additional Information (Details) - USD ($) $ in Millions	Sep. 30, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Right-of-Use Asset	$ 91
Operating Lease, Liability, Noncurrent	31
Operating Lease, Liability, Current	$ 60
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Right-of-Use Asset		$ 90
Operating Lease, Liability, Noncurrent		46
Operating Lease, Liability, Current		$ 44

Discontinued Operation (Details

Discontinued Operation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue				$ 75
Disposal Group, Including Discontinued Operation, Depreciation and Amortization				8
Disposal Group, Including Discontinued Operation, Lease Operating Expense				7
Disposal Group Including Discontinued Operation Gathering and Transportation Expense				12
Disposal Group, Including Discontinued Operation Taxes other than income				5
Disposal Group, Including Discontinued Operation, General and Administrative Expense				1
Disposal Group Including Discontinued Operation Exploration Expense				3
Accretion Expense				5
Disposal Group, Including Discontinued Operation, Other Expense				4
Disposal Group, Including Discontinued Operation, Operating Expense				45
Disposal Group, Including Discontinued Operation, Operating Income (Loss)				30
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax				(151)
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax				(121)
Discontinued Operation, Tax Effect of Discontinued Operation				(29)
Loss from discontinued operations	$ (1)	$ (1)	$ (1)	$ (92)

Discontinued Operations Cash Fl

Discontinued Operations Cash Flow (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	$ (22)	$ (37)
Powder River Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	$ (22)	(37)
San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities		44
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities		$ 29

Discontinued Operations-Additio

Discontinued Operations-Additional Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2019	Mar. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax	$ (151)
San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax	$ 147
Gathering and Treating [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation		$ 277	$ 309
Guarantee Type, Other [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation			9
Cash [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration			$ 667

Earnings (Loss) Per Common Sh_3

Earnings (Loss) Per Common Share from Continuing Operations (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share, Basic, by Common Class [Line Items]
Income (loss) from continuing operations		$ 122	$ (6)	$ 379	$ (111)
Preferred Stock Dividends, Income Statement Impact		0	0	0	8
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share		$ 122	$ (6)	$ 379	$ (119)
Weighted Average Number of Shares Outstanding, Basic		420.8	414	421.4	404.3
Weighted Average Number of Shares Outstanding, Diluted	[1]	421.8	414	423	404.3
Income (Loss) from Continuing Operations, Per Basic Share		$ 0.29	$ (0.01)	$ 0.90	$ (0.29)
Income (Loss) from Continuing Operations, Per Diluted Share		$ 0.29	$ (0.01)	$ 0.89	$ (0.29)
Restricted Stock [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		1		1.6
Employee Stock Option [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		0	0.2	0	0.2
Restricted Stock [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		0	3.5	0	3.1
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		4.5	0	4.5	0
[1]	Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders, or (ii) application of the treasury stock method to certain nonvested restricted stock units and awards. The excluded amounts are as follows: Three months Nine months 2019 2018 2019 2018 (Millions) Weighted-average nonvested restricted stock units and awards — 3.5 — 3.1 Weighted-average stock options — 0.2 — 0.2 Nonvested restricted stock units and awards antidilutive under the treasury stock method 4.5 — 4.5 —

Asset Sales and Other-Additiona

Asset Sales and Other-Additional Information (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from Sale of Other Assets, Investing Activities			$ 83
Gain (Loss) on Disposition of Proved Property			$ 0
Gains on equity method investment transactions	$ 0			$ 0	$ 373	$ 0
Long-term Investments	51				51		$ 167
Other—net	12			$ 1	$ 17	$ 5
Pending [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Other—net	$ 11
Whitewater [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Equity Method Investment, Ownership Percentage			20.00%
Gains on equity method investment transactions			$ 126
Long-term Investments			$ 15
Oryx [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from Sale of Other Assets, Investing Activities		$ 357
Equity Method Investment, Ownership Percentage		25.00%
Gains on equity method investment transactions		$ 247
Long-term Investments		$ 110

Exploration Expense (Details)

Exploration Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property amortization	$ 20	$ 18	$ 64	$ 51
Geologic and geophysical costs	2	0	6	3
Total exploration expenses	$ 22	$ 18	$ 70	$ 54

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Inventory [Line Items]
Materials, Supplies, and Other	$ 42	$ 46
Commodity production in transit or storage	4	2
Inventory, Total	$ 46	$ 48

Debt and Banking Arrangements_2

Debt and Banking Arrangements (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term Debt		$ 2,229	$ 2,509
Total long-term debt		2,229	2,509
Less: Debt issuance costs on long-term debt(a)	[1]	28	24
Long-term debt, net	[1]	2,201	2,485
Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt		0	330
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term Debt		73	529
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Long-term Debt		406	500
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term Debt		650	650
5.750% Senior Notes due 2026
Debt Instrument [Line Items]
Long-term Debt		500	500
5.250% Senior Notes due 2027
Debt Instrument [Line Items]
Long-term Debt		$ 600	$ 0
[1]	Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Debt and Banking Arrangements -

Debt and Banking Arrangements - Debt - Additional information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Debt Instrument [Line Items]
Letters of credit issued	$ 37		$ 37
Long-term Debt	2,229		2,229		$ 2,509
Debt Issuance Costs, Gross	3		3
Debt Instrument, Unamortized Premium			44
Gain (Loss) on Extinguishment of Debt	(47)	$ 0	(47)	$ (71)
Debt Instrument, Repurchase Amount	550		550
Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt	0		0		330
Line of Credit Facility, Maximum Borrowing Capacity during Collateral Period	2,100		2,100
Credit facility agreement	1,500		1,500
5.250% Senior Notes due 2027
Debt Instrument [Line Items]
Long-term Debt	600		600		$ 0
Debt Instrument, Face Amount	600		600
Proceeds from Issuance of Debt			592.5
Debt Issuance Costs, Gross	$ 2		$ 2

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Current:
Federal	$ 0	$ 0	$ 0	$ 0
State	1	(1)	2	(1)
Total current	1	(1)	2	(1)
Deferred:
Federal	33	(6)	96	(43)
State	5	(1)	11	(12)
Total deferred	38	(7)	107	(55)
Total provision (benefit)	$ 39	$ (8)	$ 109	$ (56)

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes - Additional Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%
Unrecognized Tax Benefits	$ 9
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 7

Contingent Liabilities - Additi

Contingent Liabilities - Additional Information (Detail) - USD ($) $ in Millions	Jan. 01, 2020	Sep. 30, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Loss contingencies associated with royalty litigation		$ 11	$ 11
Oil and gas transportation [Member]
Loss Contingencies [Line Items]
Contractual Obligation		$ 880
Oil and gas transportation [Member] | Minimum [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Contractual Obligation, Future Demand Payments Due	$ 19
Oil and gas transportation [Member] | Maximum [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Contractual Obligation, Future Demand Payments Due	$ 118

Lease Costs (Details)

Lease Costs (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 171
Operating cash flows used for operating leases(a)	14	[1]
Investing cash flows used for operating leases(a)	31	[1]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 44
Operating Lease, Weighted Average Remaining Lease Term	1 year 7 months 2 days
Operating Lease, Weighted Average Discount Rate, Percent	5.00%
Upstream Equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 31	[1]
Variable Lease, Cost	4	[1]
Short-term Lease, Cost	30	[2]
Other Energy Equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	14	[1]
Variable Lease, Cost	3	[1]
Short-term Lease, Cost	$ 89	[2]
[1]	Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners.
[2]	Includes variable lease costs on short-term leases.

Leases (Details)

Leases (Details) $ in Millions	Sep. 30, 2019USD ($)
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months	$ 16
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two	62
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three	15
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four	1
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due, Total	94
Operating Lease, Liability, Current	60
Operating Lease, Liability, Noncurrent	31
Operating Lease, Liability, Total	91
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	3
Operating Lease, Right-of-Use Asset	91
Upstream Equipment [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months	11
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two	44
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three	5
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four	0
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five	0
Operating Lease, Liability, Current	43
Operating Lease, Liability, Noncurrent	16
Operating Lease, Liability, Total	59
Other Machinery and Equipment [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months	5
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two	18
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three	10
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four	1
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five	0
Operating Lease, Liability, Current	17
Operating Lease, Liability, Noncurrent	15
Operating Lease, Liability, Total	$ 32

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019USD ($)$ / sharesshares	Sep. 30, 2019USD ($)
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount	$ 400	$ 400
Stock Repurchased During Period, Shares | shares	4,200,000
Stock Repurchase, Average Price Per Share | $ / shares	$ 10.23
Equity transaction costs	$ (5)	$ (5)
Minimum [Member]
Class of Stock [Line Items]
Noncontrolling Interest, future contribution percentage	80.00%	80.00%
Maximum [Member]
Class of Stock [Line Items]
Noncontrolling Interest, future contribution percentage	85.00%	85.00%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 225	$ 178
Derivative Liability, Fair Value, Gross Liability		42	37
Long-term debt, Fair Value	[1]	2,317	2,414
Long-term Debt		2,229	2,509
Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		225	178
Derivative Liability, Fair Value, Gross Liability		42	37
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	0	0
Level 1 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Derivative Liability, Fair Value, Gross Liability		0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	2,317	2,414
Level 2 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		225	175
Derivative Liability, Fair Value, Gross Liability		42	37
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	0	0
Level 3 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	3
Derivative Liability, Fair Value, Gross Liability		0	0
Derivative Asset			$ 3
Maximum [Member] | Level 3 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		$ 1
[1]	The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of September 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

Derivatives related to producti

Derivatives related to production (Detail) - Short [Member] - Derivatives related to production BTU / d in Thousands	9 Months Ended
	Sep. 30, 2019bbl / dBTU / d$ / bbl$ / MMBtu	[2]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	22,000	[1]
Underlying, Derivative	(1.37)	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Nymex CMA Roll [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	13,261	[1]
Underlying, Derivative Energy Measure	0.11	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Magellan East Houston [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	2,000	[1]
Underlying, Derivative Energy Measure	4.63	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Magellan East Houston-Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	9,000	[1]
Underlying, Derivative Energy Measure	6.02	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Argus LLS-Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	2,000	[1]
Underlying, Derivative Energy Measure	8.60	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Magellan East Houston-Argus LLS [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	2,000	[1]
Underlying, Derivative Energy Measure	0.75	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Clearbrook [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	8,000	[1]
Underlying, Derivative	(3.23)	[3]
Crude Oil | 2019 [Member] | Price Risk Derivative [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	83,000	[1]
Underlying, Derivative Energy Measure	56.72	[3]
Crude Oil | 2019 [Member] | Call Option [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	5,000	[1]
Underlying, Derivative Energy Measure	54.08	[3]
Crude Oil | 2019 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	8,000	[1]
Crude Oil | 2020 [Member] | Basis Swap [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	7,486	[1]
Underlying, Derivative	(1.31)	[3]
Crude Oil | 2020 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	5,000	[1]
Underlying, Derivative Energy Measure	8.36	[3]
Crude Oil | 2020 [Member] | Price Risk Derivative [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	45,000	[1]
Underlying, Derivative Energy Measure	57.10	[3]
Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	20,000	[1]
Crude Oil | 2021 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000	[1]
Underlying, Derivative Energy Measure	8	[3]
Crude Oil | 2022 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000	[1]
Underlying, Derivative Energy Measure	7.75	[3]
Natural Gas [Member] | 2019 [Member] | Basis Swap [Member] | Permian [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	25	[1]
Underlying, Derivative | $ / MMBtu	(0.39)	[3]
Natural Gas [Member] | 2019 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	35	[1]
Underlying, Derivative Energy Measure | $ / MMBtu	0.81	[3]
Natural Gas [Member] | 2019 [Member] | Basis Swap [Member] | Houston Ship [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	30	[1]
Underlying, Derivative | $ / MMBtu	(0.09)	[3]
Natural Gas [Member] | 2019 [Member] | Price Risk Derivative [Member] | Henry Hub
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	110	[1]
Underlying, Derivative Energy Measure | $ / MMBtu	3.07	[3]
Natural Gas [Member] | 2020 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	60	[1]
Underlying, Derivative | $ / MMBtu	(0.79)	[3]
Natural Gas [Member] | 2021 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	70	[1]
Underlying, Derivative | $ / MMBtu	(0.59)	[3]
Natural Gas [Member] | 2022 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	70	[1]
Underlying, Derivative | $ / MMBtu	(0.57)	[3]
Natural Gas [Member] | 2023 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	70	[1]
Underlying, Derivative | $ / MMBtu	(0.51)	[3]
Minimum [Member] | Crude Oil | 2019 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	50	[3]
Minimum [Member] | Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	53.33	[3]
Maximum [Member] | Crude Oil | 2019 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	60.19	[3]
Maximum [Member] | Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	63.48	[3]
[1]	Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
[2]	Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls or swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread.
[3]	The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.

Fair values and gains (losses)

Fair values and gains (losses) (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	$ 4		$ 3
Derivative, Cost of Hedge		$ 85		$ 218

Offsetting of derivative assets

Offsetting of derivative assets and liabilities (Detail) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Gross And Net Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 225	$ 178
Derivative Asset, Fair Value, Gross Liability	[1]	(39)	(37)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		186	141
Derivative Liability, Fair Value, Gross Liability		(42)	(37)
Derivative Liability, Fair Value, Gross Asset	[1]	39	37
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ (3)	$ 0
[1]	With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Credit-risk-related features (D

Credit-risk-related features (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0
Net derivative liability position	3
Derivative Liability, Fair Value of Collateral	3
Maximum [Member]
Derivative [Line Items]
Reduction in derivative liabilties	$ 1

Concentration of credit risk (D

Concentration of credit risk (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Credit Exposure From Derivatives [Line Items]
Gross credit exposure from derivatives, Gross Total	$ 225
Net credit exposure from derivatives	$ 186
Number Of Largest Net Counter Party Positions Investment Grade	7
Percentage Of Net Credit Exposure From Derivatives	86.00%
NGL Energy Partners [Member] | Sales Revenue, Net [Member]
Credit Exposure From Derivatives [Line Items]
Concentration Risk, Percentage	13.00%
NGL Energy Partners [Member] | Operating Expense [Member]
Credit Exposure From Derivatives [Line Items]
Concentration Risk, Percentage	1.00%