WPX Energy (WPX) 10-Q 7 May 20 2020 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2020	May 06, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2020
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		559,402,942
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001518832
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Amendment Flag	false

Consolidated Balance Sheet (Una

Consolidated Balance Sheet (Unaudited) - USD ($) $ in Millions		Mar. 31, 2020	Dec. 31, 2019
Current assets:
Cash and Cash Equivalents, at Carrying Value		$ 61	$ 60
Accounts receivable, net of allowance		447	450
Derivative assets, current		868	57
Inventories		30	41
Other		39	39
Total current assets		1,445	647
Long-term Investments		45	48
Properties and equipment (successful efforts method of accounting)		10,064	11,244
Less—accumulated depreciation, depletion and amortization		(1,588)	(3,654)
Properties and equipment, net		8,476	7,590
Derivative assets, noncurrent		8	10
Other noncurrent assets		122	118
Total assets		10,096	8,413
Current liabilities:
Accounts payable		618	556
Accrued and other current liabilities		220	251
Derivative liabilities, current		24	91
Total current liabilities		862	898
Deferred Income Tax Liabilities, Net		243	290
Long-term debt, net	[1]	3,200	2,202
Derivative liabilities, noncurrent		3	0
Other noncurrent liabilities		697	508
Preferred units of consolidated partnership		11	0
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; 559.4 million and 416.8 million shares issued and outstanding at March 31, 2020 and December 31, 2019)		6	4
Additional paid-in-capital		8,643	7,692
Accumulated deficit		(3,569)	(3,181)
Total stockholders’ equity		5,080	4,515
Total liabilities and equity		$ 10,096	$ 8,413
[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	Mar. 31, 2020	Dec. 31, 2019
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	559,400,000	416,800,000

Consolidated Statement of Opera

Consolidated Statement of Operations (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Revenues:
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 869	$ (207)
Other Income	3	0
Total revenues	1,398	359
Costs and expenses:
Depreciation, depletion and amortization	259	219
Lease and facility operating	101	86
Taxes other than income	42	39
Exploration (Note 4)	67	24
General and administrative (including equity-based compensation of $9 million and $8 million for the respective periods)	51	47
Impairment of Oil and Gas Properties	967	0
Acquisition Costs, Period Cost	27	0
Other—net	14	2
Total costs and expenses	1,624	508
Operating income (loss)	(226)	(149)
Interest expense	(48)	(41)
Gain on equity method investment transaction	0	126
Income (Loss) from Equity Method Investments	3	2
Investment income (loss) and other	4	0
Income (loss) from continuing operations before income taxes	(267)	(62)
Provision (benefit) for income taxes	(61)	(14)
Income (loss) from continuing operations	(206)	(48)
Income (loss) from discontinued operations	(180)	0
Net loss	(386)	(48)
Net Income (Loss) Attributable to Noncontrolling Interest	2	0
Net loss attributable to WPX Energy, Inc.	(388)	(48)
Amounts attributable to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations attributable to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share	(208)	(48)
Income (loss) from discontinued operations	$ (180)	$ 0
Income (Loss) from Continuing Operations, Per Basic and Diluted Share	$ (0.46)	$ (0.11)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic and Diluted Share	(0.39)	0
Earnings Per Share, Basic and Diluted, Total	$ (0.85)	$ (0.11)
Weighted Average Number of Shares Outstanding, Basic and Diluted	458,000,000	421,000,000
Oil and Condensate [Member]
Revenues:
Revenue from Customers	$ 465	$ 449
Natural Gas, Production [Member]
Revenues:
Revenue from Customers	13	25
Natural Gas Liquids [Member]
Revenues:
Revenue from Customers	24	33
Oil and Gas [Member]
Revenues:
Revenue from Customers	502	507
Oil and Gas, Refining and Marketing [Member]
Revenues:
Revenue from Customers	24	59
Costs and expenses:
Cost of Goods and Services Sold	34	49
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Costs and expenses:
Cost of Goods and Services Sold	$ 62	$ 42

Consolidated Statement of Ope_2

Consolidated Statement of Operations (parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Non-cash equity-based compensation expense	$ 9	$ 8

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, 2018	$ 4,301	$ 0	$ 4	$ 7,734	$ (3,437)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(48)				(48)
Stock-based compensation, net of tax impact	(5)			(5)
Ending Balance at Mar. 31, 2019	4,248	0	4	7,729	(3,485)
Beginning Balance at Dec. 31, 2019	4,515	0	4	7,692	(3,181)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(388)				(388)
Stock-based compensation, net of tax impact	3			3
Issuance of common stock related to an acquisition	994		2	992
Repurchases of common stock	44			44
Ending Balance at Mar. 31, 2020	$ 5,080	$ 0	$ 6	$ 8,643	$ (3,569)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2020	Mar. 31, 2019
Operating Activities(a)
Net loss		$ (386)	$ (48)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation Depletion And Amortization Including Discontinued Portion		259	219
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations		(47)	(13)
Provision For Impairment Of Properties And Equipment Including Certain Exploration Expenses		1,032	20
Gains related to equity method investment transactions		0	126
Net (gain) loss on derivatives		(869)	207
Net settlements related to derivatives		117	9
Amortization of stock-based awards		10	8
Cash provided by (used in) operating assets and liabilities:
Accounts receivable		107	(137)
Inventories		14	(4)
Other current assets		6	(6)
Accounts payable		(97)	197
Federal income taxes receivable		(19)	0
Accrued and other current liabilities		(66)	(37)
Liabilities related to discontinued operations		178	(8)
Other, including changes in other noncurrent assets and liabilities		17	(9)
Net cash provided by operating activities(a)	[1]	256	272
Investing Activities(a)
Capital Expenditures	[2]	302	451
Proceeds from sales of assets		0	228
Payments to Acquire Businesses, Net of Cash Acquired		(915)	0
Purchase of or contributions to investments		0	(18)
Proceeds from Equity Method Investment, Distribution, Return of Capital		4	4
Net cash provided by (used in) investing activities(a)	[1]	(1,225)	(237)
Financing Activities
Proceeds from common stock		1	1
Payments for Repurchase of Common Stock		44	0
Borrowings on credit facility		413	609
Payments on credit facility		(299)	(625)
Proceeds from long-term debt		889	0
Taxes paid for shares withheld		(8)	(15)
Payments for debt issuance costs and credit facility amendment fees		3	0
Contributions from noncontrolling interests in consolidated partnerships		18	0
Proceeds from (Payments for) Other Financing Activities		5	1
Net cash provided by (used in) financing activities		972	(29)
Net decrease in cash and cash equivalents and restricted cash		3	6
Cash, cash equivalents and restricted cash at beginning of period		80	18
Cash and cash equivalents and restricted cash at end of period		83	24
Partnership [Member]
Investing Activities(a)
Capital Expenditures	[3]	$ 12	$ 0
[1]	(a) Amounts reflect continuing and discontinued operations unless otherwise noted.
[2]	(b) Incurred capital expenditures were $313 million and $425 million for the respective periods. The difference between incurred and cash capital expenditures is due to
[3]	(c) Incurred capital expenditures were $13 million for 2020. The difference between incurred and cash capital expenditures is due to changes in related accounts payable

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Property, Plant and Equipment, Additions	$ 313	$ 425
Partnership [Member]
Property, Plant and Equipment, Additions	$ 13

Basis of Presentation and Descr

Basis of Presentation and Description of Business	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure	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. In March 2020, we closed on the acquisition of Felix Energy II (“Felix”). Our operations include Felix activity after the close date. See Note 2 of Notes to Consolidated Financial Statements. The consolidated businesses represented herein as WPX Energy, Inc. are 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, 2019 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 March 31, 2020, results of operations for the three months ended March 31, 2020 and 2019, changes in equity for the three months ended March 31, 2020 and 2019, and cash flows for the three months ended March 31, 2020 and 2019. 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 3 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 In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 and requires entities to recognize an estimated credit loss expected over the life of an exposure through an allowance, which is re-measured at each reporting date. This ASU requires entities to consider a broader range of information when estimating expected credit losses, including current information and reasonable forecasts, which may result in the earlier recognition of losses. We applied this ASU effective January 1, 2020 using a modified retrospective approach. The adoption of this ASU did not have a material impact on the Company’s consolidated financial statements. 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 are no longer required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies are required to disclose additional information about significant unobservable inputs for Level 3 measurements. The adoption of this ASU effective January 1, 2020 did not have a significant impact on the Company's consolidated financial statements. Accounting Standards Not Yet Adopted In December 2019, the FASB issued ASU 2019-12, Income Taxe s (Topic 740): Simplifying the Accounting for Income Taxes. This ASU simplifies various aspects related to accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and clarifying and amending existing guidance to improve consistent application. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods,

Acquisition

Acquisition	3 Months Ended
	Mar. 31, 2020
Business Combinations [Abstract]
Acquisition	Felix Acquisition On December 15, 2019, we entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Felix Investments Holdings II, LLC (“Felix Parent”) to acquire all of the issued and outstanding membership interests of Felix (collectively, the “Felix Acquisition”), for consideration of approximately $2.5 billion (the “Unadjusted Purchase Price”), consisting of $900 million in cash (the “Unadjusted Cash Purchase Price”), and 152,963,671 unregistered shares of our common stock (the “Unadjusted Equity Consideration”) determined by dividing $1.6 billion by $10.46, the volume weighted average per share price of the Company for the ten consecutive trading days ending on December 13, 2019. The Unadjusted Purchase Price is subject to certain customary closing adjustments set forth in the Purchase Agreement. If certain closing adjustments are positive, the Unadjusted Cash Purchase Price is adjusted and if certain closing adjustments are negative, the Unadjusted Equity Consideration is adjusted. We completed the Felix Acquisition on March 6, 2020 (the “Acquisition Date”). The estimated fair value of the consideration was $1.933 billion, consisting of the estimated fair value of the 152,963,671 shares of WPX common stock and approximately $939 million in cash. The cash consideration was subject to closing adjustments and was increased due to interim operations and working capital items. The closing adjustments are subject to change as closing estimates are finalized. During first-quarter 2020, we incurred approximately $27 million of acquisition-related costs, primarily related to legal and advisory fees which are reflected on a separate line item on the Consolidated Statements of Operations. WPX funded the cash consideration with proceeds from a debt offering in January 2020 along with available cash on hand and borrowings under our revolving credit facility. See Note 7 for further discussion on the financing of this transaction. All of Felix's properties are located in the Delaware Basin and include approximately 58,000 net acres with six productive benches, with core operations located in Loving, Reeves, Ward and Winkler counties in Texas. As of closing, proved developed reserves were approximately 106 MMBoe. The following table presents the unaudited pro forma financial results for the three months ended March 31, 2020 and 2019 as if the Felix Acquisition and related financings had been completed January 1, 2019. In addition, the three months ended March 31, 2020 have been adjusted to exclude $27 million of acquisition-related costs. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Felix Acquisition occurred on the date assumed or for the periods presented, nor is such information indicative of the Company's expected future results of operations. Three months 2020 2019 (Millions) Revenues $ 1,564 $ 489 Net loss from continuing operations attributable to WPX Energy, Inc. $ (138) $ (26) The Felix Acquisition qualified as a business combination, and as a result, we must estimate the fair value of the underlying shares distributed as consideration, the assets acquired and the liabilities assumed as of the Acquisition Date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. We will use a combination of market data and discounted cash flow models in determining the fair value of the oil and gas properties. The discounted cash flow models include estimates and assumptions representative of the economic conditions that existed at the Acquisition Date, such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs. The initial accounting for the Felix Acquisition is preliminary and adjustments to provisional amounts for properties and equipment, certain accrued receivables and liabilities and related deferred taxes, if any, or recognition of additional assets acquired or liabilities assumed may occur as additional information is obtained about facts and circumstances that existed at the Acquisition Date. In addition, the consideration is subject to change due to post-closing adjustments to the estimates at the time of closing. Such adjustments could result in the recognition of goodwill which would be subject to impairment review. We used a share price of $6.50 for our preliminary fair value of WPX common stock. The following table summarizes the consideration paid for the Felix Acquisition and the preliminary estimates of fair value of the assets acquired and liabilities assumed as of the Acquisition Date. We used several different pricing scenarios for future commodity prices and a range of risk-adjusted discount rates from 10 percent to 25 percent, which are subject to change. These amounts will be finalized as soon as possible, but no later than March 6, 2021. Preliminary Purchase Price Allocation (Millions) Consideration: Cash $ 939 Fair value of WPX common stock 994 Total consideration $ 1,933 Fair value of liabilities assumed: Accounts payable $ 141 Accrued liabilities 7 Asset retirement obligation 6 Total liabilities assumed $ 154 Fair value of assets acquired: Cash and cash equivalents $ 24 Accounts receivable, net 85 Derivative assets, current 121 Other current and noncurrent assets 5 Properties and equipment 1,852 Total assets acquired $ 2,087 Net fair value of assets and liabilities $ 1,933

Discontinued Operations (Notes)

Discontinued Operations (Notes)	3 Months Ended
	Mar. 31, 2020
Discontinued operations [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Discontinued Operations In first-quarter 2018, we sold our properties in the San Juan Gallup oil play. The purchaser assumed approximately $309 million of gathering and processing commitments that conclude in 2026; however, WPX left in place a performance guarantee with the gatherer with respect to these commitments. At the time of sale, we believed that any future performance under this guarantee obligation was unlikely. In first-quarter 2020, we were notified that the purchaser would not remit full payment of the deficiency due to the gatherer for the recently ended contract year. As a result, we recorded a $22 million accrual for the probable net amount of our portion of the deficiency payment. The remaining commitment for future contract years through 2026 is approximately $231 million. We have accrued an additional $162 million, included in other noncurrent liabilities, related to our estimated potential exposure based on a probability-based cash flow for the remainder of the contract term. Our discontinued operations also include accretion on certain transportation and gathering obligations retained and recognized in prior years associated with our exit from the Powder River Basin. Cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $6 million and $8 million for the three months ended March 31, 2020 and 2019, respectively. See Note 9 for further discussion of indemnifications related to previously sold operations.

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share from Continuing Operations	3 Months Ended
	Mar. 31, 2020
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 2020 2019 (Millions, except per-share amounts) Loss from continuing operations attributable to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share $ (208) $ (48) Basic weighted-average shares 458.0 421.0 Effect of dilutive securities(a) — — Diluted weighted-average shares 458.0 421.0 Loss per common share from continuing operations: Basic $ (0.46) $ (0.11) Diluted $ (0.46) $ (0.11) __________ (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. 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 2020 2019 (Millions) Weighted-average nonvested restricted stock units and awards 2.2 2.6 Nonvested restricted stock units and awards antidilutive under the treasury stock method 3.7 2.5

Asset Sales and Exploration Exp

Asset Sales and Exploration Expense	3 Months Ended
	Mar. 31, 2020
Extractive Industries [Abstract]
Impairment, Exploration Expenses And Other Accruals [Text Block]	Impairment, Equity Method Investment Transaction, Exploration Expenses and Other Impairment of proved properties As a result of the significant decline in forward crude prices, primarily driven by the current economic environment resulting from the COVID-19 pandemic during the first quarter of 2020, we performed impairment assessments of our proved properties in the Delaware and Williston Basins. As a result, we recorded a $967 million impairment of proved properties in the Williston Basin during the first quarter of 2020. Our impairment analyses and assessment included undiscounted and discounted future cash flows, as applicable, which considered information obtained from drilling, other activities and reserve quantities (see Note 12). Equity Method Investment Transaction 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. Exploration Expenses The following table presents a summary of exploration expenses. Three months 2020 2019 (Millions) Unproved leasehold property impairment and amortization $ 65 $ 23 Geologic and geophysical costs 2 1 Total exploration expenses $ 67 $ 24 Included in unproved leasehold property impairment and amortization for the three months ended March 31, 2020, is an impairment of $49 million for unproved leasehold costs in in the Williston Basin associated with the impairment of the proved properties noted above. Other Commodity management expense for the first quarter of 2020 includes a lower-of-cost or market adjustment related to long-term line fill, included in other noncurrent assets, of approximately $8 million.

Inventories

Inventories	3 Months Ended
	Mar. 31, 2020
Inventory Disclosure [Abstract]
Inventories	Inventories The following table presents a summary of our inventories as of the dates indicated. March 31, December 31, (Millions) Material, supplies and other $ 22 $ 36 Commodity production in transit or storage 8 5 Total inventories $ 30 $ 41

Debt and Banking Arrangements

Debt and Banking Arrangements	3 Months Ended
	Mar. 31, 2020
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. March 31, December 31, (Millions) Credit facility agreement $ 114 $ — 6.000% Senior Notes due 2022 73 73 8.250% Senior Notes due 2023 406 406 5.250% Senior Notes due 2024 647 650 5.750% Senior Notes due 2026 500 500 5.250% Senior Notes due 2027 600 600 4.500% Senior Notes due 2030 900 — Total debt $ 3,240 $ 2,229 Less: Current portion of long-term debt, net(a) — — Total long-term debt $ 3,240 $ 2,229 Less: Debt issuance costs on long-term debt(a) 40 27 Total long-term debt, net(a) $ 3,200 $ 2,202 __________ (a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. Credit Facility As of March 31, 2020, we had $114 million borrowings outstanding and $23 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. In April 2020, our annual redetermination confirmed our Borrowing Base of $2.1 billion and total commitments of $1.5 billion that will remain in effect until the next Redetermination Date, which is expected to be in October 2020. See our Annual Report on Form 10-K for the year ended December 31, 2019 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 January 10, 2020, we completed a debt offering of $900 million aggregate principal amount of 4.50% Senior Notes due 2030 (the “2030 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. The 2030 Notes bear interest at a rate of 4.50% per annum and were priced at 100.0% of par. Interest is payable on the notes semiannually in arrears on January 15 and July 15 of each year commencing on July 15, 2020. The 2030 Notes will mature on January 15, 2030. At any time prior to January 15, 2023, the Company may, on one or more occasions and subject to certain conditions described in the Indenture, redeem up to 35% of the aggregate principal amount of the Notes at a redemption price equal to 104.5% of the principal amount of the Notes redeemed with an amount of cash not greater than the net proceeds that the Company raises in certain equity offerings, as described in the Indenture. The Company also has the option, at any time prior to January 15, 2025, on one or more occasions, to redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus a specified “make whole” premium as described in the Indenture. At any time on or after January 15, 2025, the Company may, on one or more occasions, redeem the Notes, in whole or in part, at the applicable redemption prices set forth in the Indenture. The Indenture contains covenants that, among other things, restrict the Company’s ability to grant liens on its assets and merge, consolidate or transfer or lease all or substantially all of its assets, subject to certain qualifications and exceptions. The net proceeds from the offering of the 2030 Notes was approximately $886 million and approximately $14 million of debt issuance costs were capitalized. The net proceeds from this offering were used to fund a portion of the Felix Acquisition. See our Annual Report on Form 10-K for the year ended December 31, 2019 for additional discussion related to our other senior notes.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	3 Months Ended
	Mar. 31, 2020
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 2020 2019 (Millions) Current: Federal $ (19) $ — State — (1) (19) (1) Deferred: Federal (30) (12) State (12) (1) (42) (13) Total provision (benefit) $ (61) $ (14) On March 27, 2020, the President of the United States signed into law the Coronavirus Aid, Relief, and Economic Security Act, H.R. 748 (“CARES Act”). The CARES Act includes modifications to the Internal Revenue Code (“IRC”) intended to provide economic relief to those impacted by the COVID-19 pandemic such as allowing taxpayers to accelerate the remaining balance of alternative minimum tax (“AMT”) credit carryforwards. Because the income tax effects of changes in tax laws are recognized in the period when enacted, the Company has recorded a current receivable of $38 million as of March 31, 2020 for AMT credit refunds expected to be collected in 2020. However, our AMT credit carryforwards are subject to change based on the results of the 2011 Williams audit as discussed below and may impact our refunds already received. The effective income tax rate for the three months ended March 31, 2020, differs from the federal statutory rate of 21 percent due to the effect of equity-based compensation and valuation allowances placed on estimated 2020 federal and state net operating loss (“NOL”) carryovers, partially offset by state income taxes. The effective income tax rate for the three months ended March 31, 2019, differs from the federal statutory rate of 21 percent due to the effect of state income taxes, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the capital gain from the 2019 sale of an equity interest in a partnership. We have recorded valuation allowances against deferred tax assets attributable to federal and state 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. Additional valuation allowances against our NOL carryovers may be required in future periods if additional losses are incurred or other circumstances change. The ability of WPX to utilize NOL carryovers to reduce future federal taxable income could be subject to limitations under the IRC. 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 March 31, 2020, 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. The IRS has proposed an adjustment related to our business for which a payment to Williams could be required. We have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the AMT credit carryforward 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 refunds of AMT credit carryforwards have been received, the Company may have to remit cash to the IRS. Through March 31, 2020, we have received $50 million related to these AMT credit carryforwards. As of March 31, 2020, the Company has approximately $9 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $5 million. Currently, we do not expect ultimate resolution of our uncertain tax position during the next 12 months.

Contingent Liabilities

Contingent Liabilities	3 Months Ended
	Mar. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities	Contingent Liabilities and Commitments Contingent Liabilities Federal gas royalties 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 subsequently 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 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 putative class action, the case was remanded to its originally filed court of the Western District of Wisconsin for trial. 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. In May 2019, the MDL Court remanded the case back to Kansas District Court. On December 30, 2019, Defendants petitioned the United States Court of Appeals for the Tenth Circuit to consider their motion for appeal of their motion to reconsider the denial of their motion for summary judgement and the Tenth Circuit granted the petition. 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 in existence at the time of disposition. The current owner/operator of properties we divested in the Powder River Basin filed for bankruptcy during the fourth quarter of 2019, and it is uncertain to what extent the current owner/operator will perform its obligations with respect to such properties. Prior to our disposition of such properties, payments under the surface use agreements were approximately $6 million annually and our recorded asset retirement obligation under GAAP related to the plugging and abandoning of wells was approximately $46 million. 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 litigation have asserted claims regarding, among other things, the method by which we accounted for transportation costs when calculating royalty payments. In 2017, we settled one of these claims. In February 2019, a royalty-interest owner in Garfield County, filed a putative class action in the District Court of Colorado, Garfield County (State Case), alleging that we breached certain oil and gas leases and overriding royalty agreements by deducting gathering and fuel costs associated with the transportation and processing of gas from royalty and overriding royalty payments since 2011. The royalty-interest owner seeks to represent a class of owners that have interests in leases stating that we can deduct the cost of transporting gas from the well to point of sale. The same royalty-interest owner also filed a putative class action in the United States District Court of Colorado (Federal Case), seeking to represent a class of all royalty owners except tribal and governmental owners, alleging that we breached express and implied duties set forth in oil and gas leases and overriding royalty agreements by underpaying royalties and overriding royalties since July 2011 by failing to "enhance" the value of gas through processing, by deducting unreasonably high transportation costs for residue gas, by failing to prudently market residue gas and NGLs and by failing to pay royalties on the highest obtainable price. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate a reasonable estimated range of exposure related to these claims. In connection with the sale of our San Juan Basin assets in the first quarter of 2018, we left in place and remained subject to a performance guarantee with respect to various gathering and processing commitments. See Note 3 for a discussion of accruals we have recorded in connection with this performance guarantee. 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 March 31, 2020 and December 31, 2019, the Company had accrued approximately $7 million and $10 million, respectively, for loss contingencies associated with royalty litigation and other contingencies, excluding the performance guarantee. 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 the first quarter of 2020, a counterparty completed construction for a project in the Delaware Basin, which is associated with our commitment to use crude transportation capacity totaling approximately $102 million over a 7 year term beginning in 2020. In addition, the anticipated in-service date of certain crude transportation assets for which the counterparty

Leases

Leases	3 Months Ended
	Mar. 31, 2020
Leases [Abstract]
Leases of Lessee Disclosure [Text Block]	LeasesOur 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. During the first quarter of 2020, we added right of use assets of approximately $29 million in exchange for new operating lease liabilities primarily related to a new rig agreement.

Stockholders' Equity

Stockholders' Equity	3 Months Ended
	Mar. 31, 2020
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 March 31, 2020, we have repurchased approximately 16.1 million shares under the program at an average price of $6.30 per share including 10.4 million shares this quarter at an average price of $4.18 per share. Felix Acquisition On March 6, 2020, we issued 152,963,671 shares of our common stock as part of the consideration for our acquisition of Felix. In addition, we added two new board members to our Board of Directors. See Note 2 for additional discussion of the Felix Acquisition.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Recurring The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. 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. March 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 876 $ — $ 876 $ — $ 67 $ — $ 67 Energy derivative liabilities $ — $ 27 $ — $ 27 $ — $ 91 $ — $ 91 Total debt(a) $ — $ 1,962 $ — $ 1,962 $ — $ 2,400 $ — $ 2,400 __________ (a) The carrying value of total debt, excluding debt issuance costs, was $3,240 million and $2,229 million as of March 31, 2020 and December 31, 2019, 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, costless collars or swaptions and 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 2024. 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 no instruments included in Level 3 as of March 31, 2020 and less than $1 million as of December 31, 2019. 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 March 31, 2020 and 2019. 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. Nonrecurring As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. The events towards the end of the first quarter, including the significant declines in crude oil prices for 2020, were potential indicators of impairment. Therefore, we performed an assessment of our proved properties at the end of the first quarter. Our assessment utilized several estimates of future cash flows including scenarios at forecasted prices and at forward market prices. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. Our assessment identified the Williston properties with a carrying value in excess of estimated undiscounted cash flows and as a result, we recorded impairment charges to reduce the net book value of the Williston proved and unproved properties to a probability-weighted estimated fair value totaling approximately $1.0 billion measured on a nonrecurring basis within Level 3 of the fair value hierarchy. This included proved reserves quantities of more than 147 million barrels of oil equivalent, forecasted weighted-average prices averaging approximately $50.84 per Bbl for crude (adjusted for locational differences), forward market weighted-average prices averaging approximately $38.72 per Bbl and an after-tax discount rates ranging from 10 percent to 15 percent commensurate with the proved developed, proved undeveloped and probable reserves. Additional declines in forecasted prices from March 31, 2020 could result in additional impairment assessments in in future quarters on our long-lived assets.

Derivatives and Concentration o

Derivatives and Concentration of Credit Risk	3 Months Ended
	Mar. 31, 2020
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 March 31, 2020. Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Crude Oil Crude Oil Apr - Dec 2020 Fixed Price Swaps WTI (95,787) $ 56.17 Crude Oil Apr - Dec 2020 Basis Swaps Midland/Cushing (35,782) $ 0.50 Crude Oil Apr - Dec 2020 Basis Swaps Nymex CMA Roll (8,909) $ 0.57 Crude Oil Apr - Dec 2020 Basis Swaps Brent/WTI Spread (5,000) $ 8.36 Crude Oil Apr - Dec 2020 Fixed Price Collars WTI (20,000) $53.33 - $63.48 Crude Oil 2021 Fixed Price Swaptions WTI (20,000) $ 57.02 Crude Oil 2021 Basis Swaps Brent/WTI Spread (1,000) $ 8.00 Crude Oil 2021 Basis Swaps Midland/Cushing (15,000) $ 0.64 Crude Oil 2022 Basis Swaps Brent/WTI Spread (1,000) $ 7.75 Natural Gas Natural Gas Apr - Dec 2020 Basis Swaps Waha (100) $ (1.14) Natural Gas 2021 Fixed Price Swaps Henry Hub (90) $ 2.49 Natural Gas 2021 Basis Swaps Waha (80) $ (0.65) Natural Gas 2021 Fixed Price Swaptions Henry Hub (50) $ 2.57 Natural Gas 2022 Basis Swaps Waha (70) $ (0.57) Natural Gas 2023 Basis Swaps Waha (70) $ (0.51) Natural Gas 2024 Basis Swaps Waha (40) $ (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 $117 million and $9 million for the three and three months ended March 31, 2020 and 2019, 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 March 31, 2020 (Millions) Derivative assets with right of offset or master netting agreements $ 876 $ (24) $ 852 Derivative liabilities with right of offset or master netting agreements $ (27) $ 24 $ (3) December 31, 2019 Derivative assets with right of offset or master netting agreements $ 67 $ (45) $ 22 Derivative liabilities with right of offset or master netting agreements $ (91) $ 45 $ (46) __________ (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 March 31, 2020, 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 March 31, 2020 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 credit losses. We estimate the allowance for credit losses based on historic write offs, existing and reasonable forecasted economic conditions, the financial conditions and available credit ratings 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 credit losses 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 derivative 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 2020 and 2019, 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 $876 million and $852 million, respectively, as of March 31, 2020. 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 six 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 three months of 2020, sales to NGL Energy were approximately 12 percent of our total consolidated revenues adjusted for gain (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)	3 Months Ended
	Mar. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Recently Adopted Accounting Standards In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 and requires entities to recognize an estimated credit loss expected over the life of an exposure through an allowance, which is re-measured at each reporting date. This ASU requires entities to consider a broader range of information when estimating expected credit losses, including current information and reasonable forecasts, which may result in the earlier recognition of losses. We applied this ASU effective January 1, 2020 using a modified retrospective approach. The adoption of this ASU did not have a material impact on the Company’s consolidated financial statements. 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 are no longer required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies are required to disclose additional information about significant unobservable inputs for Level 3 measurements. The adoption of this ASU effective January 1, 2020 did not have a significant impact on the Company's consolidated financial statements.
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	Accounting Standards Not Yet Adopted In December 2019, the FASB issued ASU 2019-12, Income Taxe s (Topic 740): Simplifying the Accounting for Income Taxes. This ASU simplifies various aspects related to accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and clarifying and amending existing guidance to improve consistent application. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods,

Acquisition (Tables)

Acquisition (Tables)	3 Months Ended
	Mar. 31, 2020
Business Combinations [Abstract]
Business Acquisition, Pro Forma Information [Table Text Block]	The following table presents the unaudited pro forma financial results for the three months ended March 31, 2020 and 2019 as if the Felix Acquisition and related financings had been completed January 1, 2019. In addition, the three months ended March 31, 2020 have been adjusted to exclude $27 million of acquisition-related costs. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Felix Acquisition occurred on the date assumed or for the periods presented, nor is such information indicative of the Company's expected future results of operations. Three months 2020 2019 (Millions) Revenues $ 1,564 $ 489 Net loss from continuing operations attributable to WPX Energy, Inc. $ (138) $ (26)
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the consideration paid for the Felix Acquisition and the preliminary estimates of fair value of the assets acquired and liabilities assumed as of the Acquisition Date. We used several different pricing scenarios for future commodity prices and a range of risk-adjusted discount rates from 10 percent to 25 percent, which are subject to change. These amounts will be finalized as soon as possible, but no later than March 6, 2021. Preliminary Purchase Price Allocation (Millions) Consideration: Cash $ 939 Fair value of WPX common stock 994 Total consideration $ 1,933 Fair value of liabilities assumed: Accounts payable $ 141 Accrued liabilities 7 Asset retirement obligation 6 Total liabilities assumed $ 154 Fair value of assets acquired: Cash and cash equivalents $ 24 Accounts receivable, net 85 Derivative assets, current 121 Other current and noncurrent assets 5 Properties and equipment 1,852 Total assets acquired $ 2,087 Net fair value of assets and liabilities $ 1,933

Earnings (Loss) Per Common Sh_2

Earnings (Loss) Per Common Share from Continuing Operations (Tables)	3 Months Ended
	Mar. 31, 2020
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share from Continuing Operations	The following table summarizes the calculation of earnings per share. Three months 2020 2019 (Millions, except per-share amounts) Loss from continuing operations attributable to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share $ (208) $ (48) Basic weighted-average shares 458.0 421.0 Effect of dilutive securities(a) — — Diluted weighted-average shares 458.0 421.0 Loss per common share from continuing operations: Basic $ (0.46) $ (0.11) Diluted $ (0.46) $ (0.11) __________ (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. 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 2020 2019 (Millions) Weighted-average nonvested restricted stock units and awards 2.2 2.6 Nonvested restricted stock units and awards antidilutive under the treasury stock method 3.7 2.5

Exploration Expense (Tables)

Exploration Expense (Tables)	3 Months Ended
	Mar. 31, 2020
Extractive Industries [Abstract]
Exploration Expenses	The following table presents a summary of exploration expenses. Three months 2020 2019 (Millions) Unproved leasehold property impairment and amortization $ 65 $ 23 Geologic and geophysical costs 2 1 Total exploration expenses $ 67 $ 24

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Mar. 31, 2020
Inventory Disclosure [Abstract]
Inventories	The following table presents a summary of our inventories as of the dates indicated. March 31, December 31, (Millions) Material, supplies and other $ 22 $ 36 Commodity production in transit or storage 8 5 Total inventories $ 30 $ 41

Debt and Banking Arrangements (

Debt and Banking Arrangements (Tables)	3 Months Ended
	Mar. 31, 2020
Debt Disclosure [Abstract]
Debt	The following table presents a summary of our debt as of the dates indicated. March 31, December 31, (Millions) Credit facility agreement $ 114 $ — 6.000% Senior Notes due 2022 73 73 8.250% Senior Notes due 2023 406 406 5.250% Senior Notes due 2024 647 650 5.750% Senior Notes due 2026 500 500 5.250% Senior Notes due 2027 600 600 4.500% Senior Notes due 2030 900 — Total debt $ 3,240 $ 2,229 Less: Current portion of long-term debt, net(a) — — Total long-term debt $ 3,240 $ 2,229 Less: Debt issuance costs on long-term debt(a) 40 27 Total long-term debt, net(a) $ 3,200 $ 2,202 __________ (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)	3 Months Ended
	Mar. 31, 2020
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 2020 2019 (Millions) Current: Federal $ (19) $ — State — (1) (19) (1) Deferred: Federal (30) (12) State (12) (1) (42) (13) Total provision (benefit) $ (61) $ (14)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2020
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, our assets and liabilities that are measured at fair value on a recurring basis. 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. March 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 876 $ — $ 876 $ — $ 67 $ — $ 67 Energy derivative liabilities $ — $ 27 $ — $ 27 $ — $ 91 $ — $ 91 Total debt(a) $ — $ 1,962 $ — $ 1,962 $ — $ 2,400 $ — $ 2,400 __________ (a) The carrying value of total debt, excluding debt issuance costs, was $3,240 million and $2,229 million as of March 31, 2020 and December 31, 2019, 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)	3 Months Ended
	Mar. 31, 2020
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 March 31, 2020. Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Crude Oil Crude Oil Apr - Dec 2020 Fixed Price Swaps WTI (95,787) $ 56.17 Crude Oil Apr - Dec 2020 Basis Swaps Midland/Cushing (35,782) $ 0.50 Crude Oil Apr - Dec 2020 Basis Swaps Nymex CMA Roll (8,909) $ 0.57 Crude Oil Apr - Dec 2020 Basis Swaps Brent/WTI Spread (5,000) $ 8.36 Crude Oil Apr - Dec 2020 Fixed Price Collars WTI (20,000) $53.33 - $63.48 Crude Oil 2021 Fixed Price Swaptions WTI (20,000) $ 57.02 Crude Oil 2021 Basis Swaps Brent/WTI Spread (1,000) $ 8.00 Crude Oil 2021 Basis Swaps Midland/Cushing (15,000) $ 0.64 Crude Oil 2022 Basis Swaps Brent/WTI Spread (1,000) $ 7.75 Natural Gas Natural Gas Apr - Dec 2020 Basis Swaps Waha (100) $ (1.14) Natural Gas 2021 Fixed Price Swaps Henry Hub (90) $ 2.49 Natural Gas 2021 Basis Swaps Waha (80) $ (0.65) Natural Gas 2021 Fixed Price Swaptions Henry Hub (50) $ 2.57 Natural Gas 2022 Basis Swaps Waha (70) $ (0.57) Natural Gas 2023 Basis Swaps Waha (70) $ (0.51) Natural Gas 2024 Basis Swaps Waha (40) $ (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 March 31, 2020 (Millions) Derivative assets with right of offset or master netting agreements $ 876 $ (24) $ 852 Derivative liabilities with right of offset or master netting agreements $ (27) $ 24 $ (3) December 31, 2019 Derivative assets with right of offset or master netting agreements $ 67 $ (45) $ 22 Derivative liabilities with right of offset or master netting agreements $ (91) $ 45 $ (46) __________ (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.

Acquisition Purchase Price Allo

Acquisition Purchase Price Allocation (Details) - Felix [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Cash	$ 939	$ 900
Fair value of WPX common stock	994	1,600
Total consideration	1,933	$ 2,500
Accounts payable	141
Accrued liabilities	7
Asset retirement obligation	6
Total liabilities assumed	154
Cash and cash equivalents	24
Accounts receivable, net	85
Derivative assets, current	121
Other current and noncurrent assets	5
Properties and equipment	1,852
Total assets acquired	2,087
Net fair value of assets and liabilities	$ 1,933

Acquisition Pro forma (Details)

Acquisition Pro forma (Details) - Felix [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue	$ 1,564	$ 489
Business Acquisition, Pro Forma Net Income (Loss)	$ (138)	$ (26)

Acquisition Additional Informat

Acquisition Additional Information (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)aMMBoe$ / sharesshares	Dec. 31, 2019USD ($)	Mar. 31, 2019USD ($)
Business Acquisition [Line Items]
Acquisition Costs, Period Cost	$ 27		$ 0
Felix [Member]
Business Acquisition [Line Items]
Total consideration	1,933	$ 2,500
Cash	$ 939	900
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	152,963,671
Fair value of WPX common stock	$ 994	$ 1,600
Business Acquisition, Share Price | $ / shares	$ 10.46
Oil and Gas, Developed Acreage, Net | a	58,000
Number of productive benches	6
Felix [Member] | Oil [Member]
Business Acquisition [Line Items]
Proved Developed Reserves (Energy) | MMBoe	106
Felix [Member] | Common Class A [Member]
Business Acquisition [Line Items]
Business Acquisition, Share Price | $ / shares	$ 6.50

Discontinued Operations-Additio

Discontinued Operations-Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Sep. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities related to discontinued operations	$ 178	$ (8)
Powder River Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities related to discontinued operations	(6)	$ (8)
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	231		$ 309
Gathering and Treating [Member] | San Juan Gallup [Member] | Other Noncurrent Liabilities [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation	162
Gathering and Treating [Member] | San Juan Gallup [Member] | Other Current Liabilities [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation	$ 22

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
		Mar. 31, 2020	Mar. 31, 2019
Earnings Per Share, Basic, by Common Class [Line Items]
Income (loss) from continuing operations attributable to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share		$ (208)	$ (48)
Weighted Average Number of Shares Outstanding, Basic		458	421
Weighted Average Number of Shares Outstanding, Diluted	[1]	458	421
Income (Loss) from Continuing Operations, Per Basic Share		$ (0.46)	$ (0.11)
Income (Loss) from Continuing Operations, Per Diluted Share		$ (0.46)	$ (0.11)
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	0
Restricted Stock [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		2.2	2.6
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		3.7	2.5
[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. 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 2020 2019 (Millions) Weighted-average nonvested restricted stock units and awards 2.2 2.6 Nonvested restricted stock units and awards antidilutive under the treasury stock method 3.7 2.5

Asset Sales and Other-Additiona

Asset Sales and Other-Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Asset Impairment Charges	$ 967
Gain on equity method investment transaction	0	$ 126
Long-term Investments	45		$ 48
Impairment of Leasehold	49
Lower of cost or market adjustment	$ 8
Whitewater [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Equity Method Investment, Ownership Percentage		20.00%
Gain on equity method investment transaction		$ 126
Long-term Investments		$ 15

Exploration Expense (Details)

Exploration Expense (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property amortization	$ 65	$ 23
Geologic and geophysical costs	2	1
Total exploration expenses	$ 67	$ 24

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Inventory [Line Items]
Materials, Supplies, and Other	$ 22	$ 36
Commodity production in transit or storage	8	5
Inventory, Total	$ 30	$ 41

Debt and Banking Arrangements_2

Debt and Banking Arrangements (Details) - USD ($) $ in Millions		Mar. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Long-term Debt		$ 3,240	$ 2,229
Total long-term debt		3,240	2,229
Less: Debt issuance costs on long-term debt(a)	[1]	40	27
Long-term debt, net	[1]	3,200	2,202
Debt and Lease Obligation		3,240	2,229
Debt, Current		0	0
Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt		114	0
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term Debt		73	73
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Long-term Debt		406	406
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term Debt		647	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	600
4.500% Senior Notes due 2030
Debt Instrument [Line Items]
Long-term Debt		$ 900	$ 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
	Mar. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Letters of credit issued	$ 23
Long-term Debt	3,240	$ 2,229
Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt	114	0
Line of Credit Facility, Maximum Borrowing Capacity during Collateral Period	2,100
Credit facility agreement	1,500
4.500% Senior Notes due 2030
Debt Instrument [Line Items]
Long-term Debt	900	$ 0
Debt Instrument, Face Amount	900
Proceeds from Issuance of Debt	886
Debt Issuance Costs, Gross	$ 14

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Current:
Federal	$ (19)	$ 0
State	0	(1)
Total current	(19)	(1)
Deferred:
Federal	(30)	(12)
State	(12)	(1)
Total deferred	(42)	(13)
Total provision (benefit)	$ (61)	$ (14)

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating Loss Carryforwards [Line Items]
Income Taxes Receivable	$ 38
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%
Operating Loss Carryforwards, Limitations on Use	50
AMT Credit Carryforward Refunds	$ 50
Unrecognized Tax Benefits	9
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 5

Contingent Liabilities - Additi

Contingent Liabilities - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2015
Loss Contingencies [Line Items]
Loss contingencies associated with royalty litigation	$ 7	$ 10
Powder River [Member]
Loss Contingencies [Line Items]
Surface Use Agreement Payments			$ 6
Asset Retirement Obligation			$ 46
Oil and Gas Service [Member]
Loss Contingencies [Line Items]
Contractual Obligation	102
Contractual Obligation, Due in Third Year	$ 41

Lease Costs (Details)

Lease Costs (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)
Lessee, Lease, Description [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 29

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	8 Months Ended
	Mar. 31, 2020	Mar. 31, 2020	Sep. 30, 2019
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount			$ 400
Stock Repurchased During Period, Shares	10,400,000	16,100,000
Share Repurchase, Average Price Per Share	$ 4.18	$ 6.30
Felix [Member]
Class of Stock [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	152,963,671

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Millions		3 Months Ended
		Mar. 31, 2020USD ($)MMBoe$ / bbl	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 876		$ 67
Derivative Liability, Fair Value, Gross Liability		27		91
Long-term debt, Fair Value	[1]	1,962		2,400
Long-term Debt		3,240		2,229
Impairment of Oil and Gas Properties		$ 967	$ 0
Forecasted weighted average price | $ / bbl		50.84
Forward market weighted average price | $ / bbl		38.72
Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 876		67
Derivative Liability, Fair Value, Gross Liability		27		91
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]	1,962		2,400
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		876		67
Derivative Liability, Fair Value, Gross Liability		27		91
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		0
Derivative Liability, Fair Value, Gross Liability		0		$ 0
Williston [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties		$ 1,000
Williston [Member] | Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved Developed Reserves (Energy) | MMBoe		147
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 $3,240 million and $2,229 million as of March 31, 2020 and December 31, 2019, 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	3 Months Ended
	Mar. 31, 2020bbl / dBTU / d$ / bbl$ / MMBtu
Crude Oil | 2020 [Member] | Basis Swap [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	35,782	[1],[2]
Underlying, Derivative Energy Measure	0.50	[2],[3]
Crude Oil | 2020 [Member] | Basis Swap [Member] | Nymex CMA Roll [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	8,909	[1],[2]
Underlying, Derivative Energy Measure	0.57	[2],[3]
Crude Oil | 2020 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	5,000	[1],[2]
Underlying, Derivative Energy Measure	8.36	[2],[3]
Crude Oil | 2020 [Member] | Price Risk Derivative [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	95,787	[1],[2]
Underlying, Derivative Energy Measure	56.17	[2],[3]
Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	20,000	[1],[2]
Crude Oil | 2021 [Member] | Basis Swap [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	15,000	[1],[2]
Underlying, Derivative Energy Measure	0.64	[2],[3]
Crude Oil | 2021 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000	[1],[2]
Underlying, Derivative Energy Measure	8	[2],[3]
Crude Oil | 2021 [Member] | Swaption | WTI
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	20,000
Underlying, Derivative Energy Measure	57.02
Crude Oil | 2022 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000	[1],[2]
Underlying, Derivative Energy Measure	7.75	[2],[3]
Natural Gas [Member] | 2020 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	100	[1],[2]
Underlying, Derivative | $ / MMBtu	(1.14)	[2],[3]
Natural Gas [Member] | 2021 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	80	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.65)	[2],[3]
Natural Gas [Member] | 2021 [Member] | Price Risk Derivative [Member] | Henry Hub
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	90	[1],[2]
Underlying, Derivative Energy Measure | $ / MMBtu	2.49	[2],[3]
Natural Gas [Member] | 2021 [Member] | Swaption | Henry Hub
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	50
Underlying, Derivative Energy Measure	2.57
Natural Gas [Member] | 2022 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	70	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.57)	[2],[3]
Natural Gas [Member] | 2023 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	70	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.51)	[2],[3]
Natural Gas [Member] | 2024 | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BTU / d	40
Underlying, Derivative | $ / MMBtu	(0.51)
Minimum [Member] | Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	53.33	[2],[3]
Maximum [Member] | Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	63.48	[2],[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
	Mar. 31, 2020	Mar. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	$ 117	$ 9

Offsetting of derivative assets

Offsetting of derivative assets and liabilities (Detail) - USD ($) $ in Millions		Mar. 31, 2020	Dec. 31, 2019
Gross And Net Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 876	$ 67
Derivative Asset, Fair Value, Gross Liability	[1]	(24)	(45)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		852	22
Derivative Liability, Fair Value, Gross Liability		(27)	(91)
Derivative Liability, Fair Value, Gross Asset	[1]	24	45
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ (3)	$ (46)
[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	3 Months Ended
	Mar. 31, 2020USD ($)
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	3 Months Ended
	Mar. 31, 2020USD ($)
Credit Exposure From Derivatives [Line Items]
Gross credit exposure from derivatives, Gross Total	$ 876
Net credit exposure from derivatives	$ 852
Number Of Largest Net Counter Party Positions Investment Grade	6
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	12.00%
NGL Energy Partners [Member] | Operating Expense [Member]
Credit Exposure From Derivatives [Line Items]
Concentration Risk, Percentage	1.00%