WPX Energy (WPX) 8-K 25 May 16 Other Events Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015
Document Documentand Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Entity Registrant Name	WPX ENERGY, INC.
Entity Central Index Key	1,518,832

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 38	$ 41
Accounts receivable, net of allowance of $6 million as of December 31, 2015 and December 31, 2014		300	437
Derivative assets		308	498
Inventories		46	31
Margin deposits		1	27
Disposal Group, Including Discontinued Operation, Assets, Current		178	930
Other		22	23
Total current assets		893	1,987
Properties and equipment, net (successful efforts method of accounting)		6,522	3,395
Derivative assets		51	24
Disposal Group, Including Discontinued Operation, Assets, Noncurrent		894	3,464
Other noncurrent assets		33	26
Total assets		8,393	8,896
Current liabilities:
Accounts payable		278	638
Accrued Liabilities and Other Liabilities		302	145
Disposal Group, Including Discontinued Operation, Liabilities, Current		140	357
Deferred Tax Liabilities, Net, Current (Note 1)		0	151
Derivative liabilities		13	37
Total current liabilities		733	1,328
Deferred income taxes		465	621
Long-term Debt and Capital Lease Obligations	[1]	3,189	2,260
Derivative liabilities		2	5
Asset retirement obligations		99	75
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		133	151
Other noncurrent liabilities		$ 237	$ 28
Contingent liabilities and commitments (Note 10)
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; 7 million shares issued at December 31, 2015)		$ 339	$ 0
Common stock (2 billion shares authorized at $0.01 par value; 275.4 million shares issued at December 31, 2015 and 203.7 million shares issued at December 31, 2014)		3	2
Additional paid-in-capital		6,164	5,562
Accumulated deficit		(2,971)	(1,244)
Accumulated other comprehensive income (loss)		0	(1)
Total stockholders’ equity		3,535	4,319
Noncontrolling interests in consolidated subsidiaries		0	109
Total equity		3,535	4,428
Total liabilities and equity		$ 8,393	$ 8,896
[1]	Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 6	$ 6
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares issued	7,000,000	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	275,400,000	203,700,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Product revenues:
Oil sales		$ 494		$ 669	$ 475
Natural gas sales		138		282	259
Natural gas liquid sales		23		20	10
Total product revenues		655		971	744
Gas management		286		1,110	882
Net gain (loss) on derivatives not designated as hedges (Note 15)		418		434	(124)
Other		7		8	3
Total revenues		1,366		2,523	1,505
Costs and expenses:
Lease and facility operating		145		143	109
Gathering, processing and transportation		64		71	73
Taxes other than income		62		88	68
Gas management, including charges for unutilized pipeline capacity (Note 5)		261		979	927
Exploration (Note 5)		85		101	417
Depreciation, depletion and amortization		528		363	354
Impairment of producing properties and costs of acquired unproved reserves	[1]	0		15	772
Net (gain) loss on sales of assets (Note 5)		(349)		0	0
General and administrative		210		224	218
Acquisition costs (Note 2)		23		0	0
Other—net		63		13	12
Total costs and expenses		1,092		1,997	2,950
Operating income (loss)		274		526	(1,445)
Interest expense (Note 2)		(187)		(123)	(108)
Loss on extinguishment of debt (Note 2)		(65)		0	0
Investment income, impairment of equity method investment and other		(2)		1	(19)
Income (loss) from continuing operations before income taxes		20		404	(1,572)
Provision (benefit) for income taxes		24		148	(567)
Income (loss) from continuing operations		(4)		256	(1,005)
Income (loss) from discontinued operations		(1,722)		(85)	(186)
Net income (loss)		(1,726)		171	(1,191)
Less: Net income (loss) attributable to noncontrolling interests		1		7	(6)
Net Income (Loss) Attributable to Parent		(1,727)		164	(1,185)
Preferred Stock Dividends, Income Statement Impact		9		0	0
Net Income (Loss) Available to Common Stockholders,		(1,736)		164	(1,185)
Income (Loss) from Continuing Operations Attributable to WPX		(13)		256	(993)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX		$ (1,723)		$ (92)	$ (192)
Basic earnings (loss) per common share (Note 4):
Income (Loss) from Continuing Operations, Per Basic Share		$ (0.06)		$ 1.26	$ (4.95)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share		(7.36)		(0.45)	(0.96)
Earnings Per Share, Basic		$ (7.42)		$ 0.81	$ (5.91)
Basic weighted-average shares		234.2		202.7	200.5
Diluted earnings (loss) per common share (Note 4)
Income (Loss) from Continuing Operations, Per Diluted Share		$ (0.06)		$ 1.24	$ (4.95)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share		(7.36)		(0.44)	(0.96)
Earnings Per Share, Diluted		$ (7.42)		$ 0.80	$ (5.91)
Diluted weighted-average shares		234.2	[2]	206.3	200.5	[2]
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjYwM2U5M2E1MWY3YTQ0YzhhZjMwMzczYzg0OTQyNGYyfFRleHRTZWxlY3Rpb246NEI0ODNEQkM2M0ZBMkNDODc3QTdBMTBBRDE2NEEwOTIM}

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Attributable to Parent		$ (1,727)	$ 164	$ (1,185)
Preferred Stock Dividends, Income Statement Impact		9	0	0
Net Income (Loss) Available to Common Stockholders,		(1,736)	164	(1,185)
Comprehensive income (loss) attributable to WPX Energy, Inc. common stockholders		(1,736)	164	(1,188)
Other comprehensive income (loss):
Net reclassifications into earnings of net cash flow hedge gains, net of tax	[1]	0	0	(3)
Other comprehensive income (loss), net of tax		$ 0	$ 0	$ (3)
[1]	Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million of income tax for 2013. Before tax amounts realized and reclassified to product revenues, primarily natural gas sales revenues, on the Consolidated Statements of Operations were $5 million for 2013.

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2013USD ($)
Statement of Partners' Capital [Abstract]
Income tax provision for cash flow hedge gains	$ 2
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$ 5

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Total Stockholders’ Equity	Preferred Stock [Member]	Common Stock	Capital in Excess of Par Value	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2012		$ 5,371	$ 5,268		$ 2	$ 5,487	$ (223)	$ 2	$ 103	[1]
Comprehensive income:
Net income (loss)		(1,191)	(1,185)				(1,185)		(6)	[1]
Other comprehensive income (loss)		(3)	$ (3)					(3)
Comprehensive income (loss)		(1,194)
Contribution from noncontrolling interest		4
Contribution from noncontrolling interest	[1]								4
Stock based compensation, net of tax benefit		29	$ 29			29
Balance at end of period at Dec. 31, 2013		4,210	4,109		2	5,516	(1,408)	(1)	101	[1]
Comprehensive income:
Net income (loss)		171	164				164		7	[1]
Other comprehensive income (loss)		0	0					0
Comprehensive income (loss)		171
Contribution from noncontrolling interest		1							1	[1]
Stock based compensation, net of tax benefit		46	46			46
Balance at end of period at Dec. 31, 2014		4,428	4,319		2	5,562	(1,244)	(1)	109	[1]
Noncontrolling Interest, Decrease from Deconsolidation									(110)
Comprehensive income:
Net income (loss)		(1,726)	(1,727)				(1,727)		1	[1]
Other comprehensive income (loss)		0
Comprehensive income (loss)		(1,726)
Stock based compensation, net of tax benefit		26	26			26
Balance at end of period at Dec. 31, 2015		3,535	3,535	$ 339	3	6,164	$ (2,971)	0	$ 0	[1]
Comprehensive income:
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings		(11)	(11)			(11)
Stock Issued During Period, Value, New Issues		292	292			292
Stock Issued During Period, Value, Acquisitions		296	296		$ 1	$ 295
Issuance of preferred stock to public, net of offering costs		339	339	$ 339
Stockholders' Equity, Other		$ (109)	$ 1					$ 1
[1]	Primarily represents the 31 percent of Apco Oil and Gas International Inc. owned by others.

Consolidated Statements of Cha8

Consolidated Statements of Changes in Equity (Parenthetical)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Noncontrolling interest, ownership percentage by noncontrolling owners	31.00%	31.00%	31.00%

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities
Net income (loss)		$ (1,726)	$ 171	$ (1,191)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		940	863	940
Deferred income tax provision (benefit)		(1,005)	46	(645)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments		2,426	236	1,483
Amortization of stock-based awards		35	36	32
Loss on extinguishment of acquired debt and acquisition bridge financing fees		81	0	0
Gain (loss) on sales of domestic assets and international interests		385	(196)	41
Cash provided (used) by operating assets and liabilities:
Accounts receivable		233	51	(43)
Inventories		(2)	19	(5)
Margin deposits and customer margin deposits payable		26	(10)	(18)
Other current assets		0	8	(7)
Accounts payable		(247)	4	41
Accrued and other current liabilities		79	(1)	(21)
Changes in current and noncurrent derivative assets and liabilities		199	(559)	106
Other, including changes in other noncurrent assets and liabilities		157	10	5
Net cash provided by operating activities(a)	[1]	811	1,070	636
Investing Activities
Capital expenditures	[2]	(1,124)	(1,807)	(1,154)
Proceeds from sales of domestic assets and international interests		1,019	374	49
Purchases of a business, net of cash acquired		(1,212)	0	0
Other		1	(4)	(6)
Net cash used in investing activities(a)	[1]	(1,316)	(1,437)	(1,111)
Financing Activities
Proceeds from common stock		295	16	6
Proceeds from preferred stock		339	0	0
Dividends paid on preferred stock		(6)	0	0
Proceeds from long-term debt		1,000	500	0
Payments for retirement of long-term debt		(45)	0	0
Payments for retirement of acquired debt		(1,055)	0	0
Borrowings on credit facility		841	1,947	970
Payments on credit facility		(856)	(2,077)	(560)
Payments for debt issuance costs and acquisition bridge financing fees		(40)	(13)	0
Other		0	(29)	10
Net cash provided by financing activities		473	344	426
Net increase (decrease) in cash and cash equivalents		(32)	(23)	(49)
Effect of Exchange Rate on Cash and Cash Equivalents		0	(6)	(5)
Cash and cash equivalents at beginning of period	[3]	70	99	153
Cash and cash equivalents at end of period	[3]	$ 38	$ 70	$ 99
[1]	Amounts include activity related to discontinued operations. See Note 3 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
[2]	Increase to properties and equipment$(865) $(1,934) $(1,207)Changes in related accounts payable(259) 127 53Capital expenditures$(1,124) $(1,807) $(1,154)
[3]	(c) For periods prior to sale, amounts include cash associated with our international operations and represents the difference between amounts reported as cash on the Consolidated Balance Sheets.

Consolidated Statements of Ca10

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase to properties and equipment		$ (865)	$ (1,934)	$ (1,207)
Changes in related accounts payable and accounts receivable		(259)	127	53
Capital expenditures	[1]	$ (1,124)	$ (1,807)	$ (1,154)
[1]	Increase to properties and equipment$(865) $(1,934) $(1,207)Changes in related accounts payable(259) 127 53Capital expenditures$(1,124) $(1,807) $(1,154)

Description of Business, Basis

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2015
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]	Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Description of Business Operations of our company include oil, natural gas and NGL development, production and gas management activities primarily located in Texas, North Dakota, New Mexico and Colorado in the United States. We specialize in development and production from tight-sands and shale formations in the Williston and San Juan Basins and we have recently entered the core of the Permian's Delaware Basin through our acquisition of RKI Exploration & Production, LLC (“RKI”). See Note 2 for additional information regarding this acquisition. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation and related derivatives, coupled with the sale of our commodity volumes. In addition, we had operations in the Piceance Basin in Colorado, which were sold April 8, 2016. We also had operations for a portion of 2015 in the Powder River Basin in Wyoming, which were sold on September 1, 2015 and, until January 29, 2015, we had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia. For all periods presented, the results of the Piceance Basin, Powder River Basin and Apco are reported as discontinued operations. The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company,” is at times referred to in the first person as “we,” “us” or “our.” Basis of Presentation These financial statements are prepared on a consolidated basis. Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of oil, natural gas and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international. Discontinued operations On February 8, 2016, we signed an agreement to sell our Piceance Basin operations to Terra Energy Partners LLC (“Terra”) for $910 million . This transaction closed on April 8, 2016. The assets and liabilities have been reclassified as held for sale on the Consolidated Balance Sheets and the results of operations of the Piceance Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3 ). On September 1, 2015, we completed the sale of our Powder River Basin operations in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014. On January 29, 2015, we completed the disposition of our international interests. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014. See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 10 for a discussion of contingencies related to Williams’ former power business (most of which was disposed of in 2007). Recently Adopted Accounting Standards In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs . The core principles of the guidance in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the guidance in this update. In August 2015, the FASB issued ASU 2015-15 to incorporate into the ASU an SEC announcement that the SEC staff will not object to an entity presenting the cost of securing a line of credit as an asset. The Company has adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2015 , and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $31 million and $20 million of unamortized debt issuance costs related to the Company's senior unsecured notes from other noncurrent assets to long-term debt within its Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 , respectively. The unamortized costs associated with our revolving line of credit remain in other noncurrent assets for the periods presented. Other than this reclassification, the adoption of this standard did not have an impact on the Company's consolidated financial statements. In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments that eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Under the ASU, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The ASU does not change the criteria for determining whether an adjustment qualifies as a measurement-period adjustment and does not change the length of the measurement period. ASU 2015-16 is effective for the annual reporting period beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been made available for issuance. The Company early adopted this ASU in 2015. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes as part of the Simplification Initiative. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective for financial statements issued for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of an interim or annual reporting period. The Company has adopted ASU 2015-17 prospectively beginning with the interim period October 1, 2015, thus prior periods were not retrospectively adjusted. Accounting Standards Not Yet Adopted In May 2014, the FASB issued ASU 2014-09 and has updated with additional ASUs, Revenue from Contracts with Customers . The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09, as amended, is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Company does not expect the adoption of ASU 2014-15 to have a significant impact on its Consolidated Financial Statements or related disclosures. In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, enhancing the reporting model for financial instruments. The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is only permitted under specific circumstances. The Company is currently evaluating the impact, if any, of ASU 2016-01 to the Company's financial position, results of operations or cash flows. Summary of Significant Accounting Policies Principles of consolidation The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated. Use of estimates 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. Significant estimates and assumptions which impact these financials include: • impairment assessments of long-lived assets; • valuations of derivatives; • estimation of oil and natural gas reserves; • assessments of litigation-related contingencies; • asset retirement obligations; and • valuation of deferred tax assets. These estimates are discussed further throughout these notes. Cash and cash equivalents Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired. Restricted cash Restricted cash consists of approximately $10 million and $6 million at December 31, 2015 and 2014 , respectively, and is included in other current assets on the Consolidated Balance Sheets. Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Inventories All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories. Years ended December 31, 2015 2014 (Millions) Material, supplies and other $ 44 $ 29 Crude oil production in transit 2 2 $ 46 $ 31 Properties and equipment Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive. Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties. Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations. Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred. Depreciation, depletion and amortization Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers. Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives. Impairment of long-lived assets 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. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired. Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates. Contingent liabilities Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized. Asset retirement obligations We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses. Cash flows from revolving credit facilities Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis. Derivative instruments and hedging activities We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include: • unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception; • unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception; • realized gains and losses on all derivatives that settle financially; • realized gains and losses on derivatives held for trading purposes; and • realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices. Product revenues Revenues for sales of oil, natural gas and natural gas liquids are recognized when the product is sold and delivered. Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2015 and 2014 was insignificant . Additionally, natural gas revenues include $5 million in 2013 of realized gains from derivatives designated as cash flow hedges of our production sold. Gas management revenues and expenses Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation and related hedges. The Company also sells oil, natural gas and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses. Charges for unutilized transportation capacity included in gas management expenses were $38 million , $57 million and $61 million in 2015 , 2014 and 2013 , respectively. Capitalization of interest We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million . We use the weighted average rate of our outstanding debt (see Note 8 ). Income taxes We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. Deferred tax liabilities and assets are classified as noncurrent in a classified statement of financial position. As of December 31, 2015 , the Company adopted new guidance that seeks to simplify the presentation of deferred tax liabilities and assets and has applied its provisions prospectively thus prior periods were not retrospectively adjusted. See Note 9 for additional discussion. Employee stock-based compensation Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three -year period from the date of grant and generally expire ten years after the grant. Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Earnings (loss) per common share Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 4 ). Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $45 million and $28 million as of December 31, 2015 and December 31, 2014 , respectively. Approximately $31 million and $20 million of unamortized debt issuance costs related to the Company's senior unsecured notes and were reclassified from other noncurrent assets to long-term debt within our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 , respectively. Debt issuance costs related to the senior unsecured Credit Facility remain recorded in other noncurrent assets on the Company's Consolidated Balance Sheets.

Acquisition (Notes)

Acquisition (Notes)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisition On August 17, 2015, we completed the acquisition of privately held RKI Exploration & Production, LLC (“RKI”). Per the terms of the merger agreement, the purchase price was $2.75 billion , consisting of 40 million unregistered shares of WPX common stock and approximately $2.28 billion in cash (the “Acquisition”). The cash consideration was subject to closing adjustments and was reduced by our assumption of $400 million of aggregate principal amount of RKI's senior notes and amounts outstanding under RKI's revolving credit facility along with other working capital items. The closing adjustments are subject to change as closing estimates are finalized. We incurred approximately $23 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. In addition, we incurred $16 million of acquisition bridge facility fees, included in interest expense, and a $65 million loss on extinguishment of RKI's senior notes, reflected as a separate line in the Consolidated Statements of Operations. RKI was engaged in the acquisition, exploration, development and production of oil and natural gas properties located onshore in the continental United States, concentrated primarily in the Permian Basin, and more specifically the Delaware Basin sub-area, which span parts of New Mexico and Texas. RKI also had oil and gas properties in the Powder River Basin. In connection with the Acquisition, RKI contributed its Powder River Basin assets and other properties outside the Delaware Basin to a wholly owned RKI subsidiary, the ownership interests of which were distributed to RKI's equity holders in connection with the Acquisition. Thus, we acquired RKI exclusive of the Powder River Basin assets and other properties outside the Delaware Basin. The majority of RKI's Delaware Basin leasehold is located in Loving County, Texas and Eddy County, New Mexico. RKI's assets in the Permian Basin include approximately 92,000 net acres in the core of the Permian's Delaware Basin. RKI operated 659 gross producing wells in the Delaware Basin with an average working interest of approximately 93 percent. RKI's average net daily production from its Delaware Basin properties for the year ended December 31, 2014 was 18.7 Mboe per day, 43 percent of which was oil, 34 percent natural gas and 23 percent NGLs. As of December 31, 2014, RKI reported proved reserves in the Delaware Basin of 101.5 MMboe, 40 percent of which was oil, 35 percent natural gas and 25 percent NGLs. WPX funded the Acquisition with proceeds from a combination of debt, preferred stock and common stock offerings along with available cash on hand and borrowings under its revolving credit facility. See Notes 8 and 13 for further discussion on the financing of this transaction. The following table presents the unaudited pro forma financial results for the years ended December 31, 2015 and 2014 as if the Acquisition and related financings had been completed January 1, 2014. In addition, the year ended December 31, 2015 has been adjusted to exclude $23 million of acquisition costs, $65 million loss on extinguishment of acquired debt and $16 million of acquisition bridge facility fees. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the 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. Years Ended December 31, 2015 2014 (Millions) Revenues $ 1,578 $ 2,905 Net income (loss) from continuing operations attributable to WPX Energy, Inc. $ 81 $ 278 The Acquisition qualified as a business combination, and as a result, we must estimate the fair value of the underlying shares distributed, the assets acquired and the liabilities assumed as of the August 17, 2015 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 used a combination of market data, discounted cash flow models and replacement estimates in determining the fair value of the oil and gas properties and the related midstream assets. All of which include estimates and assumptions 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. Deferred taxes must also be recorded for any differences between the assigned values and the carryover tax bases of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and carryovers at the Acquisition date (see Note 9 ). The initial accounting for the Acquisition is preliminary and adjustments to provisional amounts for properties and equipment, certain accrued receivables and liabilities and related deferred taxes 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 cash consideration is subject to change due to post-closing adjustments to the working capital estimates at the time of closing. Such adjustments could result in the recognition of goodwill which would be subject to impairment review. The following table summarizes the consideration paid for the Acquisition and the preliminary estimates of fair value of the assets acquired and liabilities assumed as of the Acquisition date. The purchase price allocation is preliminary and subject to adjustment, specifically post-closing working capital adjustments, finalization of the valuation of oil and gas properties and midstream assets and deferred taxes. These amounts will be finalized as soon as possible, but no later than September 30, 2016. Purchase Price Allocation (Millions) Consideration: Cash, net of an estimated post-close settlement $ 1,251 Fair value of WPX common stock issued 296 Total consideration $ 1,547 Fair value of liabilities assumed: Accounts payable $ 104 Accrued liabilities 74 Deferred income taxes 692 Long-term debt 990 Asset retirement obligation 23 Total liabilities assumed as of December 31, 2015 1,883 Fair value of assets acquired: Cash and cash equivalents 51 Accounts receivable, net 80 Derivative assets, current 97 Derivative assets, noncurrent 34 Inventories 12 Other current assets 3 Properties and equipment(a) 3,149 Other noncurrent assets 4 Total assets acquired as of December 31, 2015 3,430 Net fair value of assets and liabilities $ 1,547 __________ (a) Properties and equipment reflect the following as of the Acquisition date: Proved properties $ 881 Unproved properties 2,108 Gathering, processing and other facilities 157 Other 3 Total $ 3,149

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued operations [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Discontinued Operations On February 8, 2016 we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that holds our Piceance Basin operations for $910 million . The agreement also requires Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, in accordance with the sales agreement and prior to closing, WPX will novate a portion of WPX's natural gas derivatives with a fair value of $82 million as of December 31, 2015 to WPX Energy Rocky Mountain, LLC. The parties closed this sale in April of 2016. These operations are included in our domestic results presented below. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2016 and thereafter of approximately $423 million . We may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Piceance Basin. See Note 16 for a discussion of an agreement signed in May 2016 related to a portion of the remaining transportation obligations. The Piceance Basin represented 52 percent of our total proved reserves at December 31, 2015 and 58 percent of our total production for 2015. Significant transactions for the Piceance Basin Operations reflected in the tables below are as follows: • As a result of market conditions including oil and natural gas prices in the fourth quarter of 2015, we performed impairment assessments of our proved producing properties. As a result of these assessments, which included the possibility of cash flows from a divestiture of the Piceance Basin, we recorded a total of $2,334 million in impairment charges associated with the Piceance Basin, of which approximately $2,308 million is recorded as a separate line on the table below and $26 million is included in exploration expenses. • During the second quarter of 2014, we completed the sale of a portion of our working interests in certain Piceance Basin wells. Based on an estimated total value received at closing of $329 million which represented estimated final cash proceeds and an estimated fair value of incentive distribution rights we received, we recorded a $195 million loss on the sale in the second quarter of 2014. An additional $1 million loss on sale was recorded in the third quarter of 2014. • Impairments of exploratory well costs and dry hole costs for 2014 include $67 million of impairment related to our Niobrara Shale well costs in the Piceance Basin. • We recorded impairments in 2013, of $88 million in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area. In August 2015, we signed agreements for the sale of our Powder River Basin for $80 million , subject to closing adjustments. On September 1, 2015, we completed a portion of the Powder River Basin divestiture. The remaining portion of the divestiture, which relates to our equity method investment in Fort Union Gas Gathering, LLC, closed on October 30, 2015. We recorded a pre-tax loss of $15 million related to this transaction during 2015. During the first and second quarters of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices for the Powder River Basin. In addition, we retained certain firm gathering and treating obligations with total commitments of $104 million through 2020 related to the Powder River properties sold. These commitments had been in excess of our production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company with total commitments through 2021 totaling $150 million , which were related to the Powder River Operation. With the closing of the Powder River Basin sale and exiting this basin, we recorded $187 million of expense related to these contracts, which is included as a separate line below. This expense is the estimated present value of the $254 million in payments associated with these contracts remaining as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from third parties and discounting based on our risk adjusted borrowing rate. Offsetting liabilities of $54 million and $133 million were recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of the closing date. The results of our Piceance Basin and Powder River Basin operations are included in our domestic results presented below. During the third quarter of 2014, we had signed an agreement to sell our Powder River Basin holdings. This sales agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. During third-quarter 2015, we received $13 million in escrow funds as a result of the terminated contract and this amount is included in Other-net expense below. On October 3, 2014, we announced an agreement to sell our international interests for approximately $294 million subject to the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco. On January 29, 2015 we completed this divestiture and received net proceeds of $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date. These non-operated international holdings comprised our international segment. We recorded a pretax gain of $41 million related to this transaction during first quarter 2015. Summarized Results of Discontinued Operations For the year ended December 31, 2015 Domestic International Total (Millions) Total revenues $ 577 $ 15 $ 592 Costs and expenses: Lease and facility operating $ 99 $ 4 $ 103 Gathering, processing and transportation 257 — 257 Taxes other than income 18 3 21 Accrual for contract obligations retained and related accretion 190 — 190 Gas management 1 — 1 Exploration 26 — 26 Depreciation, depletion and amortization 412 — 412 Impairment of assets held for sale 2,324 — 2,324 General and administrative 44 1 45 Other—net (10 ) — (10 ) Total costs and expenses 3,361 8 3,369 Operating income (loss) (2,784 ) 7 (2,777 ) Investment income and other 5 1 6 Loss on sale of Powder River Basin (15 ) — (15 ) Gain on sale of international assets — 41 41 Income (loss) from discontinued operations before income taxes (2,794 ) 49 (2,745 ) Provision (benefit) for income taxes (1,020 ) (3 ) (1,023 ) Income (loss) from discontinued operations $ (1,774 ) $ 52 $ (1,722 ) For the year ended December 31, 2014 Domestic International Total (Millions) Total revenues $ 1,159 $ 163 $ 1,322 Costs and expenses: Lease and facility operating $ 142 $ 37 $ 179 Gathering, processing and transportation 327 1 328 Taxes other than income 54 28 82 Gas management, including charges for unutilized pipeline capacity 8 — 8 Exploration 72 4 76 Depreciation, depletion and amortization 458 42 500 Impairment of producing properties and costs of acquired unproved reserves 50 — 50 Loss on sale of working interest in the Piceance Basin 196 — 196 General and administrative 51 16 67 Other—net (1 ) 12 11 Total costs and expenses 1,357 140 1,497 Operating income (loss) (198 ) 23 (175 ) Interest capitalized 1 — 1 Investment income and other 6 19 25 Income (loss) from discontinued operations before income taxes (191 ) 42 (149 ) Provision (benefit) for income taxes(a) (71 ) 7 (64 ) Income (loss) from discontinued operations $ (120 ) $ 35 $ (85 ) __________ (a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock. For the year ended December 31, 2013 Domestic International Total (Millions) Total revenues $ 1,104 $ 152 $ 1,256 Costs and expenses: Lease and facility operating $ 162 $ 37 $ 199 Gathering, processing and transportation 357 3 360 Taxes other than income 49 24 73 Gas management, including charges for unutilized pipeline capacity 4 — 4 Exploration 7 7 14 Depreciation, depletion and amortization 552 34 586 Impairment of producing properties and costs of acquired unproved reserves 280 3 283 Gain on sale of Powder River Basin deep rights leasehold (36 ) — (36 ) General and administrative 57 14 71 Other—net 5 — 5 Total costs and expenses 1,437 122 1,559 Operating income (loss) (333 ) 30 (303 ) Interest capitalized 4 — 4 Investment income and other 4 21 25 Income (loss) from discontinued operations before income taxes (325 ) 51 (274 ) Provision (benefit) for income taxes(a) (119 ) 31 (88 ) Income (loss) from discontinued operations $ (206 ) $ 20 $ (186 ) __________ (a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013. Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations As of December 31, 2015 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin operations. December 31, 2015 Total Assets classified as held for sale Current assets: Accounts receivable (including an affiliate receivable) $ 55 Derivative assets 68 Inventories 13 Other 2 Total current assets 138 Properties and equipment, net(a) 880 Derivative assets 14 Total assets classified as held for sale—discontinued operations $ 1,032 Total assets classified as held for sale—continuing operations (Note 5) 40 Total assets classified as held for sale on the Consolidated Balance Sheets $ 1,072 Liabilities associated with assets held for sale Current liabilities: Accounts payable $ 93 Accrued and other current liabilities 47 Total current liabilities 140 Asset retirement obligations 133 Total liabilities associated with assets held for sale on the Consolidated Balance Sheets $ 273 __________ (a) Includes $2,308 million impairment in Piceance Basin of the net assets. As of December 31, 2014 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin, Powder River Basin and Appalachian Basin operations, and the international assets classified as held for sale and liabilities associated with assets held for sale related to our international operations which were divested in January 2015. December 31, 2014 Domestic International Total (Millions) Assets classified as held for sale Current assets: Cash and cash equivalents $ — $ 29 $ 29 Accounts receivable 140 25 165 Inventories 15 7 22 Other 3 14 17 Total current assets 158 75 233 Investments 18 134 152 Properties and equipment (successful efforts method of accounting)(a) 7,082 445 7,527 Less—accumulated depreciation, depletion and amortization (3,513 ) (228 ) (3,741 ) Properties and equipment, net 3,569 217 3,786 Derivative assets 14 — 14 Other noncurrent assets 3 6 9 Total assets classified as held for sale—discontinued operations $ 3,762 $ 432 $ 4,194 Total assets classified as held for sale—continuing operations (Note 5) 200 — 200 Total assets classified as held for sale on the Consolidated Balance Sheets $ 3,962 $ 432 $ 4,394 Liabilities associated with assets held for sale Current liabilities: Accounts payable $ 193 $ 34 $ 227 Accrued and other current liabilities 35 23 58 Total current liabilities 228 57 285 Deferred income taxes — 13 13 Long-term debt — 2 2 Asset retirement obligations 168 7 175 Other noncurrent liabilities 28 3 31 Total liabilities associated with assets held for sale—discontinued operations $ 424 $ 82 $ 506 Total liabilities associated with assets held for sale—continuing operations (Note 4) $ 2 $ — $ 2 Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(b) $ 426 $ 82 $ 508 __________ (a) Domestic includes $45 million impairment in Powder River Basin of the net assets. Noncontrolling interests in consolidated subsidiaries of $109 million as of December 31, 2014 , related to assets classified as held for sale. Cash Flows Attributable to Discontinued Operations Excluding taxes and changes to working capital, total cash provided by operating activities related to domestic discontinued operations was $184 million , $585 million and $478 million for 2015 , 2014 and 2013, respectively. Total cash used in investing activities related to domestic discontinued operations was $251 million , $512 million and $369 million for 2015 , 2014 and 2013, respectively. Cash provided by operating activities related to our international operations was $3 million , $65 million and $56 million for 2015 , 2014 and 2013, respectively. Total cash used in investing activities related our international operations was $15 million , $85 million and $43 million for 2015 , 2014 and 2013, respectively.

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share from Continuing Operations	12 Months Ended
	Dec. 31, 2015
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. Years Ended December 31, 2015 2014 2013 (Millions, except per-share amounts) Income (loss) from continuing operations attributable to WPX Energy, Inc. $ (4 ) $ 256 $ (993 ) Less: Dividends on preferred stock 9 — — Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ (13 ) $ 256 $ (993 ) Basic weighted-average shares 234.2 202.7 200.5 Effect of dilutive securities(a): Nonvested restricted stock units and awards — 2.7 — Stock options — 0.9 — Diluted weighted-average shares 234.2 206.3 200.5 Earnings (loss) per common share from continuing operations: Basic $ (0.06 ) $ 1.26 $ (4.95 ) Diluted $ (0.06 ) $ 1.24 $ (4.95 ) __________ (a) The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders. Years Ended December 31, 2015 2014 2013 (Millions) Weighted-average nonvested restricted stock units and awards 1.3 — 2.5 Weighted-average stock options 0.1 — 1.1 Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 13) 15.5 — — The table below includes information related to stock options that were outstanding at December 31, 2015, 2014 and 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares. 2015 2014 2013 Options excluded (millions) 2.6 1.4 0.4 Weighted-average exercise price of options excluded $ 16.16 $ 18.42 $ 20.24 Exercise price range of options excluded $11.46 - $21.81 $16.46 - $21.81 $20.21 - $20.97 Fourth quarter weighted-average market price $ 7.43 $ 15.96 $ 19.97 For 2015, approximately 3.0 million nonvested restricted stock units and awards were antidilutive and were excluded from the computation of diluted weighted-average shares.

Asset Sales, Impairments and Ex

Asset Sales, Impairments and Exploration Expenses	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Asset Sales, Impairments and Exploration Expenses	Asset Sales, Impairments, Other Expenses and Exploration Expenses In 2014, we recorded a total of $15 million in impairment charges associated with exploratory well costs and producing properties recorded as a separate line on the Consolidated Statements of Operations. In 2013, we recorded a total of $1.1 billion in impairment charges of which $772 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expenses and $20 million is included in investment income, impairment of equity method investment and other. These impairments are discussed further in the sections below. Asset Sales In December 2015, we announced an agreement to sell our San Juan Basin gathering system for consideration of approximately $309 million to a portfolio company of ISQ Global Infrastructure Fund, a fund managed by I Squared Capital. The consideration reflects $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX's development in the Gallup oil play. We are obligated to complete certain in-progress construction estimated to total approximately $13 million . Under the terms of the agreement, WPX will continue to operate, at the direction of the owner, the gathering system for an initial term of two years with the opportunity to continue in ensuing years. The parties expect to close in first-quarter 2016. Upon closing, the gathering system will consist of more than 220 miles of oil, gas and water gathering lines that WPX installed in conjunction with drilling in the Gallup oil play where it made a discovery in 2013. These assets totaled $40 million at December 31, 2015 and are classified as held for sale on the Consolidated Balance Sheets. During the fourth quarter of 2015, we completed the sale of a North Dakota gathering system for approximately $185 million , subject to closing adjustments, to a private equity fund managed by the Ares EIF Group, a subsidiary of Ares Management, L.P. (NYSE: ARES). Under the terms of the agreement, a subsidiary of the buyer, Midstream Capital Partners, will manage the overall system and we will operate, at the direction of the owner, the system for a two year initial term and any renewal terms. The system currently gathers approximately 11,000 barrels per day of oil, approximately 6,500 Mcf per day of natural gas and approximately 5,000 barrels per day of water. As a result of this transaction, we recorded a net gain of $70 million in fourth-quarter 2015. In addition, we accrued approximately $25 million related to future construction obligations under the terms of the agreement, of which $22 million is reported in other noncurrent liabilities and $3 million is reported in accrued and other current liabilities on the Consolidated Balance Sheet. We also accrued approximately $33 million of deferred gain related to these obligations, of which $29 million is reported in other noncurrent liabilities and $4 million is reported in accrued and other current liabilities on the Consolidated Balance Sheet. During May 2015, WPX completed the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast for approximately $209 million in cash. The transaction released us from various long-term natural gas purchase and sales obligations and approximately $390 million in future demand payment obligations associated with the transport position. As a result of this transaction, we recorded a net gain of $209 million in second-quarter 2015 on these executory contracts. During the first quarter of 2015, we sold a portion of our Appalachian Basin operations and released certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $288 million , subject to post-closing adjustments. Including an estimate of post-closing adjustments of $17 million , we recorded a net gain of $69 million in first-quarter 2015. The transaction included physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 horizontal wells. The assets were primarily located in the Appalachian Basin in Susquehanna County, Pennsylvania. The transaction also included the release of firm transportation capacity that we had under contract in the Northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we were released from approximately $24 million per year in annual demand obligations associated with the transport. Impairments The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments. Years Ended December 31, 2015 2014 2013 (Millions) Impairment of producing properties and costs of acquired unproved reserves(a) $ — $ 15 $ 772 Impairment of equity method investment in Appalachian Basin $ — $ — $ 20 __________ (a) Excludes related impairments of unproved leasehold included in exploration expenses. As a result of declines in forward crude oil and natural gas prices primarily during the fourth-quarter 2014 as compared to forward prices as of December 31, 2013, we performed impairment assessments of our proved producing properties and costs of acquired unproved reserves. Accordingly, we recorded the following impairments during 2014: • $11 million impairment in the fourth quarter in the Green River Basin; and • $4 million of impairments in the fourth quarter of other properties. As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded a $772 million impairment in the fourth quarter of 2013 of proved producing oil and gas properties in the Appalachian Basin. The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013. Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 14 ). Other Expenses In December 2015, we plugged and abandoned the remaining wells serviced by a certain natural gas gathering system in the Appalachian Basin. As a result, we recorded approximately $23 million associated with the net present value of future obligations under the gathering agreement which is included in other-net on the Consolidated Statement of Operations. During the first quarter of 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in other—net on the Consolidated Statements of Operations. Exploration Expenses The following table presents a summary of exploration expenses. Years Ended December 31, 2015 2014 2013 (Millions) Geologic and geophysical costs $ 7 $ 6 $ 12 Impairments of exploratory area well costs and dry hole costs 24 21 3 Unproved leasehold property impairments, amortization and expiration 54 74 402 Total exploration expenses $ 85 $ 101 $ 417 Impairments of exploratory well costs and dry hole costs for 2015 include $24 million related to a non-core exploratory play where we no longer intend to continue exploration activities. Impairments of exploratory well costs and dry hole costs for 2014 include $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities. The remaining amount in 2014 represents dry hole costs associated with exploratory wells where hydrocarbons were not detected. Unproved leasehold property impairments, amortization and expiration in 2015 includes impairments of $26 million related to a non-core exploratory play where we no longer intend to continue exploration activities. Unproved leasehold property impairment, amortization and expiration in 2014 includes $41 million related to unproved leasehold costs in exploratory areas where we no longer intend to continue exploration activities. Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold associated with our impairment of the producing properties in the Appalachian Basin.

Properties and Equipment

Properties and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Properties and Equipment	Properties and Equipment Properties and equipment is carried at cost and consists of the following: Estimated Useful Life(a) (Years) December 31, 2015 2014 (Millions) Proved properties (b) $ 5,520 $ 3,852 Unproved properties (c) 2,342 349 Gathering, processing and other facilities 15-25 217 102 Construction in progress (c) 198 368 Other 3-40 138 131 Total properties and equipment, at cost 8,415 4,802 Accumulated depreciation, depletion and amortization (1,893 ) (1,407 ) Properties and equipment—net $ 6,522 $ 3,395 __________ (a) Estimated useful lives are presented as of December 31, 2015 . (b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1). (c) Unproved properties and construction in progress are not yet subject to depreciation and depletion. On August 17, 2015 we completed the Acquisition of RKI. See Note 2 for additional detail related to the Acquisition. During 2014, we purchased oil and natural gas properties in the San Juan Basin for $150 million . The properties purchased included both producing wells and undeveloped locations. Approximately $50 million of the purchase price was allocated to proved producing properties and the remainder to proved undeveloped or unproved leasehold within properties and equipment. The purchase is included within our capital expenditures on the Consolidated Statements of Cash Flows. Unproved properties consist primarily of non-producing leasehold in the Permian, San Juan and Williston Basins. Asset Retirement Obligations Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment. A rollforward of our asset retirement obligations for the years ended 2015 and 2014 is presented below. 2015 2014 (Millions) Balance, January 1 $ 77 $ 67 Liabilities incurred 26 9 Liabilities settled (2 ) (1 ) Liabilities associated with assets sold — — Estimate revisions (4 ) (3 ) Accretion expense(a) 5 5 Balance, December 31 $ 102 $ 77 Amount reflected as current $ 3 $ 2 __________ (a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations. Estimate revisions in 2014 are primarily associated with decreases in anticipated plug and abandonment costs.

Accounts Payable and Accrued an

Accounts Payable and Accrued and Other Current Liabilities	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
Accounts Payable and Accrued and Other Current Liabilities	Accounts Payable and Accrued and Other Current Liabilities Accounts Payable The following table presents a summary of our accounts payable as of the dates indicated below. December 31, 2015 2014 (Millions) Trade $ 85 $ 171 Accrual for capital expenditures 65 235 Royalties 71 71 Affiliate payable for revenue related to assets held for sale 43 118 Other 14 43 $ 278 $ 638 Accrued and other current liabilities The following table presents a summary of our accrued and other current liabilities as of the dates indicated below. December 31, 2015 2014 (Millions) Taxes other than income taxes $ 25 $ 10 Accrued interest 82 53 Compensation and benefit related accruals 61 55 Gathering and transportation 8 7 Gathering and transportation related to exited areas 56 6 Accrued income taxes 41 3 Other, including other loss contingencies 29 11 $ 302 $ 145

Debt and Banking Arrangements

Debt and Banking Arrangements	12 Months Ended
	Dec. 31, 2015
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 below. December 31, 2015 (a) 2014 (a) (Millions) 5.250% Senior Notes due 2017 $ 355 $ 400 7.500% Senior Notes due 2020 500 — 6.000% Senior Notes due 2022 1,100 1,100 8.250% Senior Notes due 2023 500 — 5.250% Senior Notes due 2024 500 500 Credit facility agreement 265 280 Other 1 1 Total debt $ 3,221 $ 2,281 Less: Current portion of long-term debt 1 1 Total long-term debt $ 3,220 $ 2,280 Less: Debt issuance costs $ 31 $ 20 Total long-term debt, net(b) $ 3,189 $ 2,260 __________ (a) Interest paid on debt totaled $120 million and $97 million for 2015 and 2014 , respectively. (b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. Subsequent to December 31, 2015 , we have borrowed an additional $110 million on our revolving credit facility. Also subsequent to December 31, 2015 and through February 25, 2016, we have repurchased $51 million of long-term notes due in 2017. See Note 16 for information regarding 2016 amendments to and amounts outstanding under our Credit Facility and the tendering of the outstanding Senior Notes due in 2017 subsequent to February 25, 2016. Senior Notes On July 22, 2015, we completed our debt offering of (a) $500 million aggregate principal amount of 7.500% senior unsecured notes due 2020 (the “2020 Notes”) and (b) $500 million aggregate principal amount of 8.250% senior unsecured notes due 2023 (the “2023 Notes”). The notes are the Company’s senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on February 1 and August 1 of each year commencing on February 1, 2016. The 2020 Notes will mature on August 1, 2020. The 2023 Notes will mature on August 1, 2023. 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 2020 and 2023 Notes was approximately $494 million for each note after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility. In September 2014, we issued $500 million aggregate principal amount of 5.250% Senior Notes due 2024 (“the 2024 Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 2024 Notes were issued under an indenture, as supplemented by a supplemental indenture, each between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the 2024 Notes were approximately $494 million after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility. In November 2011, we issued $400 million aggregate principal amount of 5.250% Senior Notes due 2017 (the “2017 Notes”) and $1.1 billion aggregate principal amount of 6.000% Senior Notes due 2022 (the “2022 Notes”) pursuant to a private offering, and in June 2012 we exchanged these notes for registered 2017 Notes and 2022 Notes. The 2017 Notes and 2022 Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The terms of the indentures governing our notes are substantially identical. Optional Redemption. We have the option prior to maturity for the 2017 Notes, prior to July 1, 2020 for the 2020 Notes, prior to October 15, 2021 for the 2022 Notes, prior to June 1, 2023 for the 2023 Notes and prior to June 15, 2024 for the 2024 Notes to redeem some or all of such notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. We also have the option at any time or from time to time on or after July 1, 2020 to redeem the 2020 Notes, or on or after October 15, 2021 to redeem the 2022 Notes, or on or after June 1, 2023 to redeem the 2023 Notes and or on or after June 15, 2024, to redeem the 2024 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture. During 2015 , we repurchased approximately $45 million of the 2017 Notes. The Company's next debt maturity does not occur until 2020. Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest. Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity. Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series: (1) a default in the payment of interest on the notes when due that continues for 30 days ; (2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity, upon redemption, or otherwise; (3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days , or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days , after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and (4) certain events of bankruptcy, insolvency or reorganization described in the indenture. Credit Facility Agreement Including the impact of amendments in July 2015, we have a $1.75 billion five -year senior unsecured revolving credit facility agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility matures on October 28, 2019 . The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2015 , the weighted average variable interest rate was 2.20% on the $265 million outstanding under the Credit Facility Agreement. On July 16, 2015, the Company amended its senior unsecured revolving Credit Facility to, among other things (a) modify the financial covenants in a manner favorable to the Company in respect of (i) the ratio of PV to Consolidated Indebtedness and (ii) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX and (b) add a financial covenant requiring a minimum ratio of Consolidated EBITDAX to Consolidated Interest Charges (each capitalized term used herein but not defined is defined in the Company’s revolving Credit Facility, as amended). Under the amended revolving Credit Facility, if the Company’s Corporate Rating is (a) BB- or worse by S&P and Ba3 or worse by Moody’s or (b) B+ or worse by S&P or B1 or worse by Moody’s, the Company will be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the Credit Facility, to Consolidated Indebtedness of at least 1.10 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2016 and at least 1.50 to 1.00 thereafter unless and until (i) the Company’s Corporate Rating is (A) BBB- or better with S&P (without negative outlook or negative watch) or (B) Baa3 or better by Moody’s (without negative outlook or negative watch) and (ii) the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s. As of December 31, 2015 , our credit rating with S&P was BB, positive outlook and our credit rating with Moody's is Ba1, negative outlook. Subsequent to December 31, 2015 , our credit ratings were downgraded to BB-, negative outlook and B2, negative outlook with S&P and Moody's, respectively. In addition, the Company is required to maintain a ratio of Consolidated Net Indebtedness to Consolidated EBITDAX of not greater than 4.50 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2016 and 4.00 to 1.00 thereafter, unless at such time the Company’s Corporate Ratings are equal to, or better than, Baa3 or BBB- by at least one of S&P and Moody’s and not less than BB+ or Ba1 by the other such agency. Furthermore, the ratio of Consolidated Indebtedness to Consolidated Total Capitalization is not permitted to be greater than 60 percent and the Company may not permit the ratio of Consolidated EBITDAX to Consolidated Interest Charges to be less than 2.5 to 1.00 for the life of the agreement. As of December 31, 2015 , we were in compliance with our financial covenants and had full access to the Credit Facility. Interest on borrowings under the Credit Facility Agreement are payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5% , (ii) The Wells Fargo Bank, National Association, publicly announced prime rate, and (iii) one-month LIBOR plus 1.0% . The Applicable Rate is defined in the Credit Facility Agreement and is determined by which interest rate we select and the ratings of our long-term unsecured debt. At December 31, 2015 , the Applicable Rate was 1.875% on our LIBOR loans and 0.875% on our alternate base rate loans. Additionally, we will be required to pay a commitment fee, based on the ratings of our long-term unsecured debt, on the unused portion of the commitments under the Credit Facility Agreement. At December 31, 2015 , the commitment fee rate was 0.30% . The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness; our and our subsidiaries' ability to grant certain liens, materially change the nature of our or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of our material subsidiaries to enter into certain restrictive agreements; our and our material subsidiaries' ability to enter into certain affiliate transactions; and our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person. We and our subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to certain exceptions and/or standards of materiality applicable to the contracting parties that differ from those applicable to investors. The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available. Letters of Credit WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements most of which expire throughout 2016. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2015 , a total of $233 million in letters of credit have been issued, a majority of which support interstate pipeline contracts. If these letter of credit agreements are not renewed, we may issue letters of credit under our Credit Facility.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes The following table includes the provision (benefit) for income taxes from continuing operations. Years Ended December 31, 2015 2014 2013 (Millions) Provision (benefit): Current: Federal $ (4 ) $ 8 $ (28 ) State 7 1 (5 ) 3 9 (33 ) Deferred: Federal 12 134 (496 ) State 9 5 (38 ) 21 139 (534 ) Total provision (benefit) $ 24 $ 148 $ (567 ) The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes. Years Ended December 31, 2015 2014 2013 (Millions) Provision (benefit) at statutory rate $ 7 $ 141 $ (550 ) Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 4 4 (25 ) State income tax legislation change (net of federal benefit) — 9 — Effective state income tax rate change (net of federal benefit) 7 (9 ) (3 ) Other 6 3 11 Provision (benefit) for income taxes $ 24 $ 148 $ (567 ) The following table includes significant components of deferred tax liabilities and deferred tax assets. December 31, 2015 2014 (Millions) Deferred tax liabilities: Properties and equipment $ 988 $ 738 Derivatives, net 155 170 Other, net 1 17 Total deferred tax liabilities 1,144 925 Deferred tax assets: Accrued liabilities and other 248 124 Alternative minimum tax credits 114 60 Loss carryovers 441 51 Other, net — 32 Total deferred tax assets 803 267 Less: valuation allowance 124 114 Total net deferred tax assets 679 153 Net deferred tax liabilities $ 465 $ 772 Net cash payments (refunds) for income taxes were $(8) million , $9 million and $(26) million in 2015, 2014 and 2013, respectively. As a result of the sale of Apco in the first quarter of 2015, we no longer have foreign operations and the associated tax liabilities. The closing of the Apco sale resulted in a $42 million capital loss for which a valuation allowance was established in 2014. Significant changes to our operations during 2015 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we accrued an additional $7 million of deferred tax expense in 2015. Tax reform legislation that was enacted by the state of New York on March, 31, 2014 had an impact on us as a result of our marketing activities in the state. As a result, we recorded an additional $9 million of deferred tax expense in the first quarter of 2014. However, due to announced asset sales in fourth-quarter 2014, our state effective tax rate decreased resulting in a $9 million deferred tax benefit. The acquisition of the stock of RKI in third-quarter 2015 (see Note 2) resulted in an increase to our deferred tax liabilities of $693 million as of the Acquisition date. Included in this amount are deferred tax assets for federal net operating loss (“NOL”) carryovers of $125 million , minimum tax credits of $50 million and state NOL carryovers of $7 million . The Company has federal NOL carryovers of approximately $902 million at December 31, 2015, including the RKI NOL, that will not begin to expire until 2032 . In addition, we have $47 million of capital loss carryovers at December 31, 2015, that will begin to expire in 2020 . The Company has state NOL carryovers, including the RKI carryovers, of approximately $2.0 billion and $875 million at 2015 and 2014, respectively, of which more than 98 percent expire after 2029 . The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax is subject to various limitations under the Internal Revenue Code (the Code). The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three -year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an Ownership Change). As of December 31, 2015, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for RKI effective with the Acquisition. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the Acquisition. We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we 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 the 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. In previous periods, our deferred income tax liabilities and assets have been separated into current and noncurrent amounts. The company adopted ASU No. 2015-17: Balance Sheet Classification of Deferred Taxes as of December 31, 2015. See Note 1 for further discussion. 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. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business . 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. It is uncertain when the IRS will complete that audit. The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant. As of December 31, 2015 , the Company has no significant unrecognized tax benefits. During the next 12 months , we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.

Contingent Liabilities and Comm

Contingent Liabilities and Commitments	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities and Commitments	Contingent Liabilities and Commitments Royalty litigation In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We have completed the accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to stay this new lawsuit pending resolution of the first lawsuit in the Colorado Court of Appeals. In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs' motion for class certification. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico and violation of the New Mexico Oil and Gas Proceeds Payment Act, and seek declaratory judgment, accounting and injunction. 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 an estimated range of exposure related to these claims. 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 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. No similar specific guidance has been issued by ONRR for leases in Colorado though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2009 through December 2015, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $114 million . Environmental matters The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance. Matters related to Williams’ former power business In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications. Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order. 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 FERC 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 Western States 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. 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 exposures at this time. Other Indemnifications Pursuant to various purchase and sale agreements relating to divested businesses and assets, 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 breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided. At December 31, 2015 , we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made. In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it. Summary As of December 31, 2015 and December 31, 2014, the Company had accrued approximately $17 million and $16 million , respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year. Commitments As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2015 are as follows: (Millions) 2016 $ 140 2017 130 2018 116 2019 104 2020 91 Thereafter 105 Total $ 686 In conjunction with our exit of the Powder River Basin, we recorded liabilities associated with certain pipeline capacity obligations held by our marketing company of which $29 million and $84 million is recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of December 31, 2015. Commitments related to these pipeline agreements for 2016 and beyond total $139 million and are included in the table above. Also included in the table is approximately $527 million of transportation obligations primarily associated with our Piceance Basin of which $104 million will become the financial responsibility of the purchaser (see Note 3 of Notes to Consolidated Financial Statements). See Note 16 for a discussion of an agreement signed in May 2016 related to a portion of the remaining transportation obligations. We have certain commitments, for natural gas gathering and treating services, which total $524 million , including approximately $106 million associated with our Piceance Basin operations that will be assumed by the purchaser, $92 million associated with our exit from the Powder River Basin and $33 million associated with gathering commitments in a portion of our Appalachian Basin operations (see Notes 3 and 5 of the Notes to Consolidated Financial Statements). Liabilities associated with the Powder River Basin of $19 million and $40 million were recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of December 31, 2015. In addition, we accrued approximately $23 million related to the abandonment of a portion of our Appalachian Basin operations, of which $20 million is recorded in other noncurrent liabilities as of December 31, 2015. Commitments other than those associated with our Piceance Basin operations will be settled over approximately eight years . Future minimum annual rentals under noncancelable operating leases as of December 31, 2015, are payable as follows: (Millions) 2016 $ 28 2017 23 2018 12 2019 7 2020 7 Thereafter 9 Total $ 86 Total rent expense, excluding amounts capitalized, was $28 million , $26 million and $23 million in 2015, 2014 and 2013, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
Postemployment Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $15 million , $17 million and $16 million for 2015 , 2014 and 2013 , respectively. Approximately $9 million and $10 million were included in accrued and other current liabilities at December 31, 2015 and December 31, 2014 , respectively, related to the non-matching annual employer contribution.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation WPX Energy, Inc. 2013 Incentive Plan We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2013 Incentive Plan is 19.6 million shares. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan. The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012 . Subsequent offering periods are from January through June and from July through December. Employees purchased 191 thousand shares at an average price of $7.05 per share during 2015 . Employee stock-based awards Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three -year period from the date of grant and generally expire ten years after the grant. Restricted stock units are generally valued at fair value on the grant date and generally vest over three years . Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Total stock-based compensation expense for the years ended December 31, 2015 , 2014 and 2013 was $35 million , $35 million and $31 million , respectively. Stock-based compensation expense is reflected in general and administrative expense; however, approximately $4 million , $5 million and $4 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, is included in discontinued operations. Measured but unrecognized stock-based compensation expense at December 31, 2015 was $37 million . This amount is comprised of $1 million related to stock options and $36 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years. Stock Options The following summary reflects stock option activity and related information for the year ended December 31, 2015 . WPX Plan Stock Options Options Weighted- Average Exercise Price Aggregate Intrinsic Value (Millions) (Millions) Outstanding at December 31, 2014(a) 3.1 $ 14.80 $ 2 Granted — $ — Exercised (0.2 ) $ 10.33 Forfeited — $ — Outstanding at December 31, 2015 2.9 $ 15.07 $ — Exercisable at December 31, 2015 2.7 $ 14.75 $ — __________ (a) Includes approximately 137 thousand shares held by Williams' employees at a weighted average price of $10.64 per share at December 31, 2014 . The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 and 2013 was $319 thousand , $13 million and $5 million , respectively. The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2015 . WPX Plan Stock Options Outstanding Stock Options Exercisable Range of Exercise Prices Options Weighted- Average Exercise Price Weighted- Average Remaining Contractual Life Options Weighted- Average Exercise Price Weighted- Average Remaining Contractual Life (Millions) (Years) (Millions) (Years) $ 6.02 to $12.32 0.9 $ 9.79 3.0 0.9 $ 9.79 3.0 $ 14.41 to $17.47 1.2 $ 15.97 5.0 1.1 $ 15.92 4.6 $18.16 to $19.95 0.3 $ 18.21 6.4 0.3 $ 18.21 6.4 $20.21 to $21.81 0.5 $ 20.62 4.0 0.4 $ 20.37 2.8 Total 2.9 $ 15.07 4.4 2.7 $ 14.75 4.0 The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows: WPX Plan 2015 2014 2013 Weighted-average grant date fair value of options granted $ — $ 18.94 $ 6.04 Weighted-average assumptions: Dividend yield — — — Volatility — % 43.0 % 42.8 % Risk-free interest rate — % 1.85 % 1.06 % Expected life (years) 0.0 5.9 6.0 For 2014 and 2013 , we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method. Cash received from stock option exercises was $2 million , $14 million and $4 million during 2015 , 2014 and 2013 , respectively. Nonvested Restricted Stock Units The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2015 . WPX Plan Restricted Stock Units Shares Weighted- Average Fair Value(a) (Millions) Nonvested at December 31, 2014 5.1 $ 17.58 Granted 3.1 $ 10.24 Forfeited (0.1 ) $ 14.89 Vested (2.2 ) $ 18.34 Nonvested at December 31, 2015 5.9 $ 13.34 __________ (a) Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period. Other restricted stock unit information WPX Plan 2015 2014 2013 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 10.24 $ 18.37 $ 14.97 Total fair value of restricted stock units vested during the year (millions) $ 40 $ 33 $ 18 Performance-based shares granted represent 25 percent of nonvested restricted stock units outstanding at December 31, 2015 . These grants may be earned at the end of a three -year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Stockholders' Equity	Stockholders’ Equity On July 22, 2015, we completed equity offerings of (a) 30 million shares of our common stock for gross proceeds of approximately $303 million , before underwriter discounts and commissions of $10.5 million , at the public offering price of $10.10 per share and (b) $350 million of aggregate liquidation preference of 6.25% series A mandatory convertible preferred stock (“Mandatory Convertible Preferred Stock”) as further described below. On August 17, 2015, we issued 40 million unregistered shares of our common stock to RKI shareholders as part of the consideration under our merger agreement. The estimated fair value of the shares on the Acquisition date was $296 million . These shares were registered in December 2015. See Note 2 for further discussion of the Acquisition. Common Stock Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2015 , 2014 or 2013 . No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities. Subject to certain exceptions, so long as any share of our Mandatory Convertible Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Mandatory Convertible Preferred Stock. Preferred Stock Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding. As of December 31, 2015 , there were 7 million shares of our 6.25% series A Mandatory Convertible Preferred Stock (as described below) issued and outstanding. Series A Mandatory Convertible Preferred Stock On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our 6.25% Series A Mandatory Convertible Preferred Stock at $50 per share, for gross proceeds of approximately $350 million , before underwriting discounts and commissions of $10.5 million . The underwriters did not exercise their option to purchase additional shares. Dividends on our Mandatory Convertible Preferred Stock will be payable on a cumulative basis when, as and if declared by our Board of Directors, or an authorized committee of our Board of Directors, at an annual rate of 6.25% of the liquidation preference of $50 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018. Each share of our Mandatory Convertible Preferred Stock has a liquidation preference of $50 pursuant to the Certificate of Designations and unless converted or redeemed earlier each share of our Mandatory Convertible Preferred Stock will automatically convert on the mandatory conversion date, which is the third business day immediately following the last trading day of the final averaging period into between 4.1254 and 4.9504 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the average volume weighted average price per share of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding July 31, 2018, which we refer to as the “final averaging period.” Other than during a fundamental change conversion period, at any time prior to July 31, 2018, a holder may convert one share of our Mandatory Convertible Preferred Stock into a number of shares of our common stock equal to the minimum conversion rate of 4.1254 , subject to anti-dilution adjustments. If a holder converts one share of our Mandatory Convertible Preferred Stock during a specified period beginning on the effective date of a fundamental change (as described in the offering documents), the conversion rate will be adjusted under certain circumstances, and such holder will also be entitled to a make-whole dividend amount (as described in the offering documents). On October 2, 2015, our Board of Directors approved a quarterly dividend of $0.85938 per share to holders of our Mandatory Convertible Preferred Stock. The dividend was paid on November 2, 2015, to holders of record of our Mandatory Convertible Preferred Stock at the close of business on October 15, 2015. On November 12, 2015, our Board of Directors approved a quarterly dividend of $0.78125 per share to holders of our Mandatory Convertible Preferred Stock. The dividend was paid on February 1, 2016, to holders of record of our Mandatory Convertible Preferred Stock at the close of business on January 15, 2016.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows: • Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded. • Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars, calls or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. 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. • Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. 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, restricted cash and margin deposits approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 359 $ — $ 359 $ 14 $ 503 $ 5 $ 522 Energy derivative liabilities $ — $ 15 $ — $ 15 $ 32 $ 10 $ — $ 42 Total debt(a) $ — $ 2,495 $ — $ 2,495 $ — $ 2,218 $ — $ 2,218 __________ (a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $3,220 million and $2,280 million as of December 31, 2015 and 2014 , respectively. Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and 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 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 liabilities does not consider noncash collateral credit enhancements. Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1. Forward, swap, option and swaption contracts included in Level 2 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 costless collars, calls 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 several natural gas and crude oil swaps entered into, we granted swaptions and calls to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. 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 exchange-traded products or like products and the tenure of our derivatives portfolio extends through the end of 2018. 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 monthly 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. The instruments included in Level 3 at December 31, 2015, consist primarily of natural gas index transactions that are used to manage our physical requirements. 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 between Level 1 and Level 2 occurred during the years ended December 31, 2015 or 2014. The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy. Years ended December 31, 2015 2014 2013 (Millions) Beginning balance $ 5 $ — $ (1 ) Realized and unrealized gains (losses): Included in income (loss) from continuing operations (1 ) 5 (2 ) Included in other comprehensive income (loss) — — — Purchases, issuances, and settlements (4 ) — 3 Transfers out of Level 3 — — — Ending balance $ — $ 5 $ — Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31 $ — $ 5 $ (1 ) Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations. 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. On several occasions in the past three years, we considered the significant declines in forward natural gas, oil and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. 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), expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In each of the three years ended December 31, 2015 , our assessments identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy. Total losses for the years ended December 31, 2015 (a) 2014 (b) 2013 (c) (Millions) Impairments: Producing properties and costs of acquired unproved reserves (Note 3 and Note 5) $ 2,308 $ 20 $ 1,055 Unproved leasehold 26 — 317 Equity method investment (Note 5) — — 20 $ 2,334 $ 20 $ 1,392 __________ (a) As a result of our impairment assessment in 2015, we recorded the following significant impairment charges, including those reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately $880 million : • $2,308 million impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment. • $26 million impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment. (b) As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million : • $11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent . • $9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties including $5 million of which is reflected in discontinued operations. (c) As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million : • $792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent . • $317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market. • $107 million impairment charge related to natural gas producing properties in the Powder River Basin, reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent . • $88 million impairment charge related to acquired unproved reserves in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively. • $85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

Derivatives and Concentration o

Derivatives and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [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 swaptions. We also may enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation economically hedge the expected cash flows generated by those agreements. 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 December 31, 2015 . Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Price (c) Crude Oil Crude Oil 2016 Fixed Price Swaps WTI (27,549 ) $ 61.70 Crude Oil 2016 Basis Swaps Midland (5,000 ) $ (0.45 ) Crude Oil 2016 Fixed Price Calls WTI (1,243 ) $ 55.75 Crude Oil 2016 Swaptions WTI (1,257 ) $ 57.15 Crude Oil 2017 Fixed Price Swaps WTI (9,304 ) $ 61.66 Crude Oil 2017 Swaptions WTI (1,500 ) $ 59.00 Natural Gas Natural Gas 2016 Fixed Price Swaps Henry Hub (213 ) $ 3.79 Natural Gas 2016 Basis Swaps NGPL (5 ) $ (0.23 ) Natural Gas 2016 Basis Swaps Permian (33 ) $ (0.17 ) Natural Gas 2016 Basis Swaps Rockies (230 ) $ (0.21 ) Natural Gas 2016 Basis Swaps San Juan (100 ) $ (0.18 ) Natural Gas 2016 Basis Swaps SoCal (45 ) $ (0.01 ) Natural Gas 2017 Basis Swaps Rockies (50 ) $ (0.21 ) Natural Gas 2017 Basis Swaps San Juan (33 ) $ (0.16 ) Natural Gas 2017 Basis Swaps SoCal (10 ) $ — Natural Gas 2017 Fixed Price Calls Henry Hub (16 ) $ 4.50 Natural Gas 2017 Swaptions Henry Hub (65 ) $ 4.19 Natural Gas 2018 Fixed Price Calls Henry Hub (16 ) $ 4.75 __________ (a) Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, calls, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. (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 the natural gas is reported in $/MMBtu. Derivatives primarily related to transportation The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2015 . The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices. Commodity Period Contract Type (a) Location (b) Notional Volume (c) Natural Gas 2016 Index Multiple (17 ) __________ (a) We enter into exchange traded fixed price and basis swaps, over-the-counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component. (b) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements. (c) Natural gas volumes are reported in BBtu/day. Fair values and gains (losses) The following table presents the fair value of energy commodity derivatives. 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. December 31, 2015 2014 Assets Liabilities Assets Liabilities (Millions) Derivatives related to production not designated as hedging instruments $ 359 $ 15 $ 503 $ 10 Derivatives related to physical marketing agreements not designated as hedging instruments — — 19 32 Total derivatives not designated as hedging instruments $ 359 $ 15 $ 522 $ 42 For the periods ended December 31, 2015, 2014 and 2013, respectively, the Company had no energy commodity derivatives designated as cash flow hedges. The following table presents the net gain (loss) related to our energy commodity derivatives. Years Ended December 31, 2015 2014 2013 Gain (loss) from derivatives related to production not designated as hedging instruments(a) $ 438 $ 515 $ (57 ) Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments(b) (20 ) (81 ) (67 ) Net gain (loss) on derivatives not designated as hedges $ 418 $ 434 $ (124 ) __________ (a) Includes settlements totaling $650 million for the year ended December 31, 2015, and payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively. (b) Includes payments totaling $33 million , $120 million and $6 million for the years ended December 31, 2015, 2014 and 2013, respectively. The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities. 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) Cash Collateral Posted(Received) Net Amount December 31, 2015 (Millions) Derivative assets with right of offset or master netting agreements $ 359 $ (14 ) $ — $ 345 Derivative liabilities with right of offset or master netting agreements $ (15 ) $ 14 $ — $ (1 ) December 31, 2014 Derivative assets with right of offset or master netting agreements $ 522 $ (25 ) $ — $ 497 Derivative liabilities with right of offset or master netting agreements $ (42 ) $ 25 $ 17 $ — __________ (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 S&P’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 December 31, 2015 , we didn't have any collateral posted to derivative counterparties, including zero initial margin to clearinghouses or exchanges to enter into positions or maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $1 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. At December 31, 2014 , we had collateral totaling $26 million posted to derivative counterparties, which includes $9 million of initial margin to clearinghouses or exchanges to enter into positions and $17 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $17 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was less than $1 million at both December 31, 2015 and December 31, 2014 . 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 The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31. 2015 2014 (Millions) Receivables by product or service: Sale of natural gas, crude and related products and services $ 171 $ 339 Joint interest owners 90 88 Other 39 10 Total $ 300 $ 437 Natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Derivative assets and liabilities We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by creditworthy parties. We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2015 , 2014 and 2013 , 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. The following table summarizes the gross and net credit exposure from our derivative contracts as of December 31, 2015 . Counterparty Type Gross Total Net Total (Millions) Financial institutions (Investment Grade)(a) $ 360 $ 346 Credit reserves (1 ) (1 ) Credit exposure from derivatives $ 359 $ 345 __________ (a) 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 in investment grade. Our seven largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities. Other At December 31, 2015 , we held collateral support of approximately $45 million , either in the form of cash, letters of credit or surety bond, related to our gas management sale agreements. Collateral support for our commodity agreements include letters of credit and guarantees of payment by creditworthy parties. Revenues During 2015 , 2014 and 2013 , BP Energy Company accounted for 3 percent , 15 percent and 7 percent of our consolidated revenues, respectively. During 2015 , 2014 and 2013 , Western Refining accounted for 11 percent , 4 percent and 2 percent of our consolidated revenues, respectively. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2015
Subsequent Event [Line Items]
Subsequent Events [Text Block]	Subsequent Events Transportation obligations On May 25, 2016, WPX announced the signing of an agreement to buy out the remaining transportation obligations that supported its prior operating presence in the Piceance Basin for approximately $239 million . Upon closing, WPX will release all of its Piceance-related firm transportation capacity across four interstate pipeline systems to Citadel NGPE, LLC. The buyout also eliminates approximately $164 million in letters of credit and their associated annual interest expenses, and releases WPX from nearly $400 million in demand obligations from 2016 through 2032. WPX is using cash on-hand to fund the agreement. The parties expect to close the transaction in the third quarter, subject to regulatory approval and typical closing conditions. Senior Notes Subsequent to February 25, 2016, we redeemed an additional $87 million after we tendered for the remaining outstanding 5.250% senior notes due in 2017. Credit Facility On March 18, 2016, the Company entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, is now a $1.2 billion senior secured revolving credit facility with a maturity date of October 28, 2019 . The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of May 25, 2016, we did not have any outstanding borrowings under the Credit Facility Agreement. During any Collateral Trigger Period, loans under the Credit Facility will be subject to a Borrowing Base as calculated in accordance with the Provisions of the Credit Facility. As of March 18, 2016, the Borrowing Base was set at $1.025 billion . This Borrowing Base will remain in effect until the next Borrowing Base is re-determined pursuant to the Credit Facility. The next scheduled Re-determination date is October 1, 2016 and biannually thereafter. Subject to the satisfaction of certain conditions set forth in the Credit Facility, during any Collateral Trigger Period (as described below), the Company may designate Loans under the Credit Facility as either General Loans, the proceeds of which may be used for the general purposes described above, or as Development Loans, the proceeds of which shall be used solely for the development of oil and gas property owned or leased by the Company and certain of its subsidiaries. Additionally, during any Collateral Trigger Period, the Loans shall be secured and the obligations outstanding under the Credit Facility shall be guaranteed, in each case, as more particularly described below. On the date of the closing of the Credit Facility a Collateral Trigger Period shall be in effect and all Loans outstanding shall be deemed to be General Loans. The General Loans and the other General Secured Obligations outstanding under the Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Any Development Loans and any Development Secured Obligations shall be secured by certain oil, gas or other mineral properties developed with the proceeds thereof and not otherwise securing the General Secured Obligations. Such obligations will continue to be secured during any Collateral Trigger Period and such security interest shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility. The Collateral Trigger Period means, as applicable, (1) the period beginning on the date of the closing of the Credit Facility, as amended, and ending on the initial Collateral Trigger Termination Date and (2) each period beginning on a Collateral Trigger Date (as described below) and ending on the first Collateral Trigger Termination Date occurring after such Collateral Trigger Date. The Collateral Trigger Date is the first date after any Collateral Trigger Termination Date on which either (1) the Company’s Corporate Rating is Ba3 or lower (or unrated) by Moody’s or BB- or lower (or unrated) by S&P or (2) the Company elects to have the Borrowing Base apply. The Collateral Trigger Termination Date is the first date following the date of the closing of the Credit Facility and the first date following any Collateral Trigger Date, as applicable, on which (1)(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s or (2) both (i) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) is less than or equal to 3.00 to 1.00 and (ii) the Corporate Rating is (A) at least Ba1 by Moody’s and at least BB by S&P or (B) at least Ba2 by Moody’s and at least BB+ by S&P. If the Company elects to have the Borrowing Base apply, the Collateral Trigger Termination Date is the date the Company elects under the terms of the Credit Facility to no longer have the Borrowing Base apply. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings. During any Collateral Trigger Period, the Company is required to maintain a ratio of Consolidated Secured Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 3.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and 3.00 to 1.00 thereafter. During any Collateral Trigger Period, the Company may also not permit the ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter to be less than 1.0 to 1.0. Other than during a Collateral Trigger Period, the Company is required to maintain a ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 4.50 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2016 and 4.00 to 1.00 thereafter, unless at such time the Company’s Corporate Ratings are equal to, or better than, Baa3 or BBB- by at least one of S&P and Moody’s and not less than BB+ or Ba1 by the other such agency. In addition, other than during a Collateral Trigger Period, the ratio of Consolidated Indebtedness to Consolidated Total Capitalization is not permitted to be greater than 60 percent and is applicable for the life of the agreement. Furthermore, other than during a Collateral Trigger Period, the Company may not permit the ratio of Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) to Consolidated Interest Charges to be less than 2.5 to 1.00. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties. The Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments, a change of control and, during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected. If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies. Credit Ratings As of the date of this filing, our credit ratings were as follows: Standard and Poor’s(a) Corporate Credit Rating B+ Senior Unsecured Debt Rating B Outlook Negative Moody’s Investors Service(b) LT Corporate Family Rating B2 Senior Unsecured Debt Rating B3 Outlook Negative

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA	WPX Energy, Inc. QUARTERLY FINANCIAL DATA (Unaudited) Summarized quarterly financial data are as follows: First Quarter Second Quarter Third Quarter Fourth Quarter (Millions, except per-share amounts) 2015 Revenues $ 420 $ 154 $ 407 $ 385 Operating costs and expenses $ 300 $ 251 $ 300 $ 294 Income (loss) from continuing operations $ 52 $ 23 $ (70 ) $ (9 ) Income (loss) from discontinued operations 16 (53 ) (160 ) (1,525 ) Net income (loss) $ 68 $ (30 ) $ (230 ) $ (1,534 ) Amounts attributable to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ 52 $ 23 $ (74 ) $ (14 ) Income (loss) from discontinued operations 15 (53 ) (160 ) (1,525 ) Net income (loss) $ 67 $ (30 ) $ (234 ) $ (1,539 ) Basic earnings (loss) per common share: Income (loss) from continuing operations $ 0.26 $ 0.11 $ (0.29 ) $ (0.06 ) Income (loss) from discontinued operations 0.07 (0.25 ) (0.64 ) (5.53 ) Net income (loss) $ 0.33 $ (0.14 ) $ (0.93 ) $ (5.59 ) Diluted earnings (loss) per common share: Income (loss) from continuing operations $ 0.25 $ 0.11 $ (0.29 ) $ (0.06 ) Income (loss) from discontinued operations 0.07 (0.25 ) (0.64 ) (5.53 ) Net income (loss) $ 0.32 $ (0.14 ) $ (0.93 ) $ (5.59 ) 2014 Revenues $ 602 $ 465 $ 538 $ 918 Operating costs and expenses $ 545 $ 439 $ 362 $ 399 Income (loss) from continuing operations $ (28 ) $ (37 ) $ 52 $ 269 Income (loss) from discontinued operations 47 (96 ) 14 (50 ) Net income (loss) $ 19 $ (133 ) $ 66 $ 219 Amounts attributable to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (28 ) $ (37 ) $ 52 $ 269 Income (loss) from discontinued operations 46 (98 ) 10 (50 ) Net income (loss) $ 18 $ (135 ) $ 62 $ 219 Basic earnings (loss) per common share: Income (loss) from continuing operations $ (0.14 ) $ (0.18 ) $ 0.26 $ 1.32 Income (loss) from discontinued operations 0.23 (0.48 ) 0.04 (0.24 ) Net income (loss) $ 0.09 $ (0.66 ) $ 0.30 $ 1.08 Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (0.14 ) $ (0.18 ) $ 0.26 $ 1.30 Income (loss) from discontinued operations 0.23 (0.48 ) 0.04 (0.24 ) Net income (loss) $ 0.09 $ (0.66 ) $ 0.30 $ 1.06 The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding. Net income for first-quarter 2015 includes the following pre-tax items: • $41 million gain related to our divestment of APCO (see Note 3 ). • $69 million gain recorded for the sale of a portion of our Appalachian Basin operations (see Note 5 ). • During 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in other-net on the Consolidated Statements of Operations (see Note 5 ). Net loss for second-quarter 2015 includes the following pre-tax item: • $209 million gain recorded for the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast (see Note 5 ). Net loss for third-quarter 2015 includes the following pre-tax items: • We completed the acquisition of privately held RKI and incurred additional $104 million costs related to this (see Note 2 ). • Discontinued operations had $187 million additional expense related to contract obligations as a result of the Powder River Basin sale closing (see Note 3 ). • $47 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities. Net loss for fourth-quarter 2015 includes the following pre-tax items: • $2.3 billion of impairments costs on discontinued operation producing properties and leasehold (see Note 3 ). • $70 million gain on sale of a North Dakota gathering system (see Note 5 ). • $23 million related to gathering obligations in an area of the Appalachian Basin we exited in the fourth quarter of 2015 (see Note 5 ). Net income for first-quarter 2014 includes the following item: • $9 million deferred tax expense to accrue for the impact of new legislation (see Note 9 .) Net loss for second-quarter 2014 includes the following pre-tax items: • $195 million loss on the sale of a portion of our working interests in certain Piceance Basin wells, reported in discontinued operations (see Note 3 ). • $40 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities. • $11 million increase in gas management expense related to a tariff rate refund received in prior years which is no longer under appeal by the pipeline company. Net income for third-quarter 2014 includes the following pre-tax item: • $22 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities. Net income for fourth-quarter 2014 includes the following pre-tax items: • $87 million of impairments of costs of producing properties, acquired unproved reserves and leasehold (see Notes 3 and 5 ). • During 2014, we assigned our remaining natural gas storage capacity agreement to a third party and sold the remaining natural gas stored under this agreement for a total loss of approximately $18 million reflected in gas management expenses in the Consolidated Statements of Operations.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures	We have significant continuing oil and gas producing activities primarily in the Permian Basin in Texas and New Mexico, the Williston Basin in North Dakota and the Piceance and San Juan Basins in the Rocky Mountain region, all of which are located in the United States. Until January 2015, we had international oil and gas producing activities, primarily in Argentina. The international activities through the date of the sale are reported as discontinued operations (see Note 3 of Notes to Consolidated Financial Statements). International net proved reserves, including amounts related to an equity method investment, were approximately 35 MMboe or less than 5 percent of our total domestic and international reserves at December 31, 2014. Other than noted below, the following information relates to our domestic oil and gas activities and excludes our gas management activities. With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information of the Piceance Basin and information through the completion of the sale of the Powder River Basin, both of which have been reported as discontinued operations in our consolidated financial statements. Subsequent to December 31, 2015, we entered into an agreement for the sale of our Piceance Basin properties (see Note 3 of Notes to Consolidated Financial Statements). The Piceance Basin properties represent approximately 52 percent of our reserves. The Powder River Basin operations were sold in late 2015 and represented less than 5 percent of our total domestic proved reserves at December 31, 2014. Additionally, most of our Appalachian Basin assets were sold in early 2015 and also represented less than 5 percent of our total domestic proved reserves as of December 31, 2014. Capitalized Costs As of December 31, 2015 2014 (Millions) Proved Properties $ 5,703 $ 4,192 Unproved properties 2,342 349 8,045 4,541 Accumulated depreciation, depletion and amortization and valuation provisions (1,763 ) (1,292 ) Net capitalized costs $ 6,282 $ 3,249 __________ • Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $202 million and $109 million , net, for 2015 and 2014, respectively. The $109 million at December 31, 2014 includes costs related to gathering assets sold or held for sale in 2015. • Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells. • Unproved properties consist primarily of unproved leasehold costs. Cost Incurred For the years ended December 31, 2015 2014 2013 (Millions) Acquisition $ 3,208 $ 294 $ 57 Exploration 84 92 104 Development 657 1,376 939 $ 3,949 $ 1,762 $ 1,100 __________ • Costs incurred include capitalized and expensed items. • Acquisition costs are as follows: costs in 2015 primarily relate to the allocated purchase price of RKI properties in the Permian-Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) and includes 53 MMboe of proved developed reserves. Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include approximately 5 MMboe of proved reserves. The 2013 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves. • Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds. The 2015 amount primarily related to the drilling of Piceance Niobrara wells. • Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our Piceance Basin operations were $106 million , $430 million and $284 million for 2015, 2014 and 2013, respectively. Results of Operations For the years ended December 31, 2015 2014 2013 (Millions) Revenues: Oil sales $ 494 $ 669 $ 475 Natural gas sales 138 282 259 Natural gas liquid sales 23 20 10 Net gain (loss) on derivatives not designated as hedges 438 515 (57 ) Other revenues 7 8 3 Total revenues 1,100 1,494 690 Costs: Lease and facility operating 145 143 109 Gathering, processing and transportation 64 71 73 Taxes other than income 62 88 68 Exploration 85 101 417 Depreciation, depletion and amortization 528 363 354 Impairment of certain proved properties — 15 772 Impairment of costs of acquired unproved reserves — — — Net (gain) loss on sales of assets (349 ) — — General and administrative 203 217 211 Acquisition costs 23 — — Other (income) expense 63 13 12 Total costs 824 1,011 2,016 Results of operations 276 483 (1,326 ) Provision (benefit) for income taxes 101 176 (484 ) Exploration and production net income (loss) $ 175 $ 307 $ (842 ) __________ • Amounts for all years exclude the equity losses from our equity method investees. Net equity losses from these investees were $1 million and $21 million in 2014 and 2013 , respectively. • Other revenues consist of activities that are an indirect part of the producing activities. • Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2015 and 2014 include impairments of certain exploratory well costs (see Note 5 of Notes to Consolidated Financial Statements). Exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachian Basin. • Depreciation, depletion and amortization includes depreciation of support equipment. • Other income (expense) includes $22 million as a result of a termination of a crude oil transportation and sales agreement. Also included is a $23 million charge related to the net present value of future obligations under a gathering agreement in an Appalachian area for which we plugged and abandoned our remaining wells in December 2015. Proved Reserves The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. The following is a summary of changes in our domestic proved reserves including proved reserves in the Powder River Basin which is reported as discontinued operations. Excluded from the table are our international reserves that are primarily attributable to a consolidated subsidiary (Apco) which represented less than 5 percent of our total reserves. The international interests were sold in January 2015. In addition, the table includes proved reserves in the Piceance Basin. As of December 31, 2015, proved developed reserves and proved undeveloped reserves in the Piceance Basin were 228 MMboe and 75 MMboe, respectively. Oil (MMBbls) Natural Gas (Bcf) NGLs (MMBbls) All Products (MMBoe) Proved reserves at December 31, 2012 76.5 3,369.1 110.4 748.4 Revisions 3.5 308.3 (25.4 ) 29.5 Divestitures — (0.2 ) — — Extensions and discoveries 28.8 312.0 8.1 88.9 Production (5.9 ) (359.4 ) (7.4 ) (73.2 ) Proved reserves at December 31, 2013 102.9 3,629.8 85.7 793.6 Revisions (7.7 ) (198.3 ) (13.4 ) (54.1 ) Purchases 4.2 6.0 0.8 6.0 Divestitures (1.8 ) (314.6 ) (8.5 ) (62.7 ) Extensions and discoveries 42.4 362.1 12.5 115.2 Production (9.2 ) (335.4 ) (6.3 ) (71.4 ) Proved reserves at December 31, 2014 130.8 3,149.6 70.8 726.6 Revisions (31.9 ) (624.6 ) (14.0 ) (150.0 ) Purchases 39.8 205.6 20.7 94.7 Divestitures — (380.3 ) — (63.4 ) Extensions and discoveries 17.1 116.9 5.1 41.6 Production (13.1 ) (277.0 ) (7.3 ) (66.5 ) Proved reserves at December 31, 2015 142.7 2,190.2 75.3 583.0 Proved developed reserves: December 31, 2013 36.8 2,265.2 48.6 463.0 December 31, 2014 60.0 2,090.0 43.9 452.3 December 31, 2015 83.0 1,618.2 49.5 402.2 Proved undeveloped reserves: December 31, 2013 66.1 1,364.6 37.1 330.6 December 31, 2014 70.8 1,059.6 26.9 274.3 December 31, 2015 59.7 572.0 25.8 180.8 __________ • Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit . • Revision in 2015 primarily reflect 209 MMboe of negative revisions related to the decrease in the 12 month average prices partially offset by 59 MMboe of positive revisions due to decreased costs and well improvements. The 2015 revisions comprised 108 MMboe net negative revisions related to proved undeveloped locations and 42 MMboe net negative revisions related to proved developed locations. Revisions in 2014 primarily reflect 16 MMboe of net positive revisions to developed reserves and 70 MMboe of net negative revisions to undeveloped reserves. The 70 MMboe of net negative revisions were primarily due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules. Revisions in 2013 reflects 22 MMboe related to developed reserves and 7 MMboe related to undeveloped reserves. • Purchases reflects the RKI acquisition of which 53.4 MMboe is proved developed and 41.3 MMboe is associated with proved undeveloped locations. • Divestitures in 2015 relate to sales of properties in the Powder River Basin ( 28 MMboe) and the Appalachian Basin ( 35 MMboe). Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (see Notes 3 and 5 of Notes to Consolidated Financial Statements). • Extensions and discoveries in 2015 reflect 20.9 MMboe added for proved developed locations and 20.7 MMboe for proved undeveloped locations primarily related to our San Juan Gallup and Williston Basins. Extensions and discoveries in 2014 reflect 31 MMboe added for drilled locations and 84 MMboe added for new proved undeveloped locations. Extensions and discoveries in 2013 reflects 21 MMboe added for drilled locations and 68 MMboe added for new undeveloped locations. The 2014 and 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is based on the estimated quantities of proved reserves. Prices are based on the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years ended December 31, 2015, 2014 and 2013, the average domestic combined natural gas and NGL equivalent price was $2.32 , $4.34 and $3.63 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2015, 2014 and 2013 was $43.84 , $83.62 and $92.16 per barrel, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates. Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2015 2014 (Millions) Future cash inflows $ 12,391 $ 26,444 Less: Future production costs 7,757 12,641 Future development costs 1,761 3,426 Future income tax provisions — 2,519 Future net cash flows 2,873 7,858 Less 10 percent annual discount for estimated timing of cash flows 1,589 3,975 Standardized measure of discounted future net cash inflows $ 1,284 $ 3,883 __________ • Our historical tax basis (i.e. future deductions for taxable income calculation) of proved properties at December 31, 2015 is greater than the total future net cash flows before taxes; therefore, future taxable income would be less than zero. • Included in the $1,284 million of discounted future net cash inflows is $270 million related to the properties in the Piceance Basin. Sources of Change in Standardized Measure of Discounted Future Net Cash Flows For the years ended December 31, 2015 2014 2013 (Millions) Beginning of year $ 3,883 $ 2,964 $ 1,949 Sales of oil and gas produced, net of operating costs (541 ) (1,324 ) (1,040 ) Net change in prices and production costs (5,231 ) 303 1,198 Extensions, discoveries and improved recovery, less estimated future costs 254 1,761 1,282 Development costs incurred during year 276 592 414 Changes in estimated future development costs 1,213 143 (736 ) Purchase of reserves in place, less estimated future costs 657 147 — Sale of reserves in place, less estimated future costs (397 ) (391 ) (3 ) Revisions of previous quantity estimates (374 ) (536 ) 239 Accretion of discount 489 383 225 Net change in income taxes 1,073 (142 ) (540 ) Other (18 ) (17 ) (24 ) Net changes (2,599 ) 919 1,015 End of year $ 1,284 $ 3,883 $ 2,964

Schedule II - Valuation And Qua

Schedule II - Valuation And Qualifying Accounts	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS	SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS Beginning Balance Charged (Credited) to Costs and Expenses Other Deductions Ending Balance 2015: Allowance for doubtful accounts—accounts and notes receivable(a) $ 6 $ 5 $ — $ (5 ) $ 6 Deferred tax asset valuation allowance(b) 118 3 3 — 124 Price-risk management credit reserves—assets(a)(c) 1 — — — 1 2014: Allowance for doubtful accounts—accounts and notes receivable(a) $ 7 $ — $ — $ (1 ) $ 6 Deferred tax asset valuation allowance(b) 102 (1 ) 17 — 118 Price-risk management credit reserves—assets(a)(c) — — 1 — 1 2013: Allowance for doubtful accounts—accounts and notes receivable(a) $ 11 $ (3 ) $ — $ (1 ) $ 7 Deferred tax asset valuation allowance(b) 19 80 3 — 102 __________ (a) Deducted from related assets. (b) Deducted from related assets, with a portion included in assets held for sale. (c) Included in revenues.

Description of Business, Basi30

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Description of Business and Basis of Presentation	Description of Business Operations of our company include oil, natural gas and NGL development, production and gas management activities primarily located in Texas, North Dakota, New Mexico and Colorado in the United States. We specialize in development and production from tight-sands and shale formations in the Williston and San Juan Basins and we have recently entered the core of the Permian's Delaware Basin through our acquisition of RKI Exploration & Production, LLC (“RKI”). See Note 2 for additional information regarding this acquisition. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation and related derivatives, coupled with the sale of our commodity volumes. In addition, we had operations in the Piceance Basin in Colorado, which were sold April 8, 2016. We also had operations for a portion of 2015 in the Powder River Basin in Wyoming, which were sold on September 1, 2015 and, until January 29, 2015, we had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia. For all periods presented, the results of the Piceance Basin, Powder River Basin and Apco are reported as discontinued operations. The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company,” is at times referred to in the first person as “we,” “us” or “our.” Basis of Presentation These financial statements are prepared on a consolidated basis. Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of oil, natural gas and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
Discontinued operations	Discontinued operations On February 8, 2016, we signed an agreement to sell our Piceance Basin operations to Terra Energy Partners LLC (“Terra”) for $910 million . This transaction closed on April 8, 2016. The assets and liabilities have been reclassified as held for sale on the Consolidated Balance Sheets and the results of operations of the Piceance Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3 ). On September 1, 2015, we completed the sale of our Powder River Basin operations in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014. On January 29, 2015, we completed the disposition of our international interests. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014. See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 10 for a discussion of contingencies related to Williams’ former power business (most of which was disposed of in 2007)
New Accounting Pronouncements and Changes in Accounting Principles	Recently Adopted Accounting Standards In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs . The core principles of the guidance in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the guidance in this update. In August 2015, the FASB issued ASU 2015-15 to incorporate into the ASU an SEC announcement that the SEC staff will not object to an entity presenting the cost of securing a line of credit as an asset. The Company has adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2015 , and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $31 million and $20 million of unamortized debt issuance costs related to the Company's senior unsecured notes from other noncurrent assets to long-term debt within its Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 , respectively. The unamortized costs associated with our revolving line of credit remain in other noncurrent assets for the periods presented. Other than this reclassification, the adoption of this standard did not have an impact on the Company's consolidated financial statements. In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments that eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Under the ASU, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The ASU does not change the criteria for determining whether an adjustment qualifies as a measurement-period adjustment and does not change the length of the measurement period. ASU 2015-16 is effective for the annual reporting period beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been made available for issuance. The Company early adopted this ASU in 2015. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes as part of the Simplification Initiative. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective for financial statements issued for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of an interim or annual reporting period. The Company has adopted ASU 2015-17 prospectively beginning with the interim period October 1, 2015, thus prior periods were not retrospectively adjusted.
New Accounting Pronouncements Not yet Adopted	Accounting Standards Not Yet Adopted In May 2014, the FASB issued ASU 2014-09 and has updated with additional ASUs, Revenue from Contracts with Customers . The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09, as amended, is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Company does not expect the adoption of ASU 2014-15 to have a significant impact on its Consolidated Financial Statements or related disclosures. In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, enhancing the reporting model for financial instruments. The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is only permitted under specific circumstances. The Company is currently evaluating the impact, if any, of ASU 2016-01 to the Company's financial position, results of operations or cash flows.
Principles of consolidation	Principles of consolidation The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
Use of estimates	Use of estimates 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. Significant estimates and assumptions which impact these financials include: • impairment assessments of long-lived assets; • valuations of derivatives; • estimation of oil and natural gas reserves; • assessments of litigation-related contingencies; • asset retirement obligations; and • valuation of deferred tax assets. These estimates are discussed further throughout these notes.
Cash and cash equivalents	Cash and cash equivalents Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash	Restricted cash Restricted cash consists of approximately $10 million and $6 million at December 31, 2015 and 2014 , respectively, and is included in other current assets on the Consolidated Balance Sheets.
Accounts receivable	Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories	Inventories All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories. Years ended December 31, 2015 2014 (Millions) Material, supplies and other $ 44 $ 29 Crude oil production in transit 2 2 $ 46 $ 31
Properties and equipment	Properties and equipment Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive. Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Other capitalized costs	Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations. Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization	Depreciation, depletion and amortization Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers. Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets	Impairment of long-lived assets 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. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired. Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities	Contingent liabilities Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations	Asset retirement obligations We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities	Cash flows from revolving credit facilities Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities	Derivative instruments and hedging activities We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include: • unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception; • unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception; • realized gains and losses on all derivatives that settle financially; • realized gains and losses on derivatives held for trading purposes; and • realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues	Product revenues Revenues for sales of oil, natural gas and natural gas liquids are recognized when the product is sold and delivered. Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2015 and 2014 was insignificant . Additionally, natural gas revenues include $5 million in 2013 of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses	Gas management revenues and expenses Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation and related hedges. The Company also sells oil, natural gas and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses. Charges for unutilized transportation capacity included in gas management expenses were $38 million , $57 million and $61 million in 2015 , 2014 and 2013 , respectively.
Capitalization of interest	Capitalization of interest We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million . We use the weighted average rate of our outstanding debt (see Note 8 ).
Income taxes	Income taxes We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. Deferred tax liabilities and assets are classified as noncurrent in a classified statement of financial position. As of December 31, 2015 , the Company adopted new guidance that seeks to simplify the presentation of deferred tax liabilities and assets and has applied its provisions prospectively thus prior periods were not retrospectively adjusted. See Note 9 for additional discussion.
Employee stock-based compensation	Employee stock-based compensation Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three -year period from the date of grant and generally expire ten years after the grant. Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Earnings (loss) per common share	Earnings (loss) per common share Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 4 ).
Debt issuance costs	Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $45 million and $28 million as of December 31, 2015 and December 31, 2014 , respectively. Approximately $31 million and $20 million of unamortized debt issuance costs related to the Company's senior unsecured notes and were reclassified from other noncurrent assets to long-term debt within our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 , respectively. Debt issuance costs related to the senior unsecured Credit Facility remain recorded in other noncurrent assets on the Company's Consolidated Balance Sheets.

Description of Business, Basi31

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Schedule of Inventory, Current [Table Text Block]	The following table presents a summary of inventories. Years ended December 31, 2015 2014 (Millions) Material, supplies and other $ 44 $ 29 Crude oil production in transit 2 2 $ 46 $ 31

Acquisition (Tables)

Acquisition (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information [Table Text Block]	The following table presents the unaudited pro forma financial results for the years ended December 31, 2015 and 2014 as if the Acquisition and related financings had been completed January 1, 2014. In addition, the year ended December 31, 2015 has been adjusted to exclude $23 million of acquisition costs, $65 million loss on extinguishment of acquired debt and $16 million of acquisition bridge facility fees. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the 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. Years Ended December 31, 2015 2014 (Millions) Revenues $ 1,578 $ 2,905 Net income (loss) from continuing operations attributable to WPX Energy, Inc. $ 81 $ 278
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the consideration paid for the Acquisition and the preliminary estimates of fair value of the assets acquired and liabilities assumed as of the Acquisition date. The purchase price allocation is preliminary and subject to adjustment, specifically post-closing working capital adjustments, finalization of the valuation of oil and gas properties and midstream assets and deferred taxes. These amounts will be finalized as soon as possible, but no later than September 30, 2016. Purchase Price Allocation (Millions) Consideration: Cash, net of an estimated post-close settlement $ 1,251 Fair value of WPX common stock issued 296 Total consideration $ 1,547 Fair value of liabilities assumed: Accounts payable $ 104 Accrued liabilities 74 Deferred income taxes 692 Long-term debt 990 Asset retirement obligation 23 Total liabilities assumed as of December 31, 2015 1,883 Fair value of assets acquired: Cash and cash equivalents 51 Accounts receivable, net 80 Derivative assets, current 97 Derivative assets, noncurrent 34 Inventories 12 Other current assets 3 Properties and equipment(a) 3,149 Other noncurrent assets 4 Total assets acquired as of December 31, 2015 3,430 Net fair value of assets and liabilities $ 1,547 __________ (a) Properties and equipment reflect the following as of the Acquisition date: Proved properties $ 881 Unproved properties 2,108 Gathering, processing and other facilities 157 Other 3 Total $ 3,149

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued operations [Abstract]
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block]	Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations As of December 31, 2015 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin operations. December 31, 2015 Total Assets classified as held for sale Current assets: Accounts receivable (including an affiliate receivable) $ 55 Derivative assets 68 Inventories 13 Other 2 Total current assets 138 Properties and equipment, net(a) 880 Derivative assets 14 Total assets classified as held for sale—discontinued operations $ 1,032 Total assets classified as held for sale—continuing operations (Note 5) 40 Total assets classified as held for sale on the Consolidated Balance Sheets $ 1,072 Liabilities associated with assets held for sale Current liabilities: Accounts payable $ 93 Accrued and other current liabilities 47 Total current liabilities 140 Asset retirement obligations 133 Total liabilities associated with assets held for sale on the Consolidated Balance Sheets $ 273 __________ (a) Includes $2,308 million impairment in Piceance Basin of the net assets. As of December 31, 2014 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin, Powder River Basin and Appalachian Basin operations, and the international assets classified as held for sale and liabilities associated with assets held for sale related to our international operations which were divested in January 2015. December 31, 2014 Domestic International Total (Millions) Assets classified as held for sale Current assets: Cash and cash equivalents $ — $ 29 $ 29 Accounts receivable 140 25 165 Inventories 15 7 22 Other 3 14 17 Total current assets 158 75 233 Investments 18 134 152 Properties and equipment (successful efforts method of accounting)(a) 7,082 445 7,527 Less—accumulated depreciation, depletion and amortization (3,513 ) (228 ) (3,741 ) Properties and equipment, net 3,569 217 3,786 Derivative assets 14 — 14 Other noncurrent assets 3 6 9 Total assets classified as held for sale—discontinued operations $ 3,762 $ 432 $ 4,194 Total assets classified as held for sale—continuing operations (Note 5) 200 — 200 Total assets classified as held for sale on the Consolidated Balance Sheets $ 3,962 $ 432 $ 4,394 Liabilities associated with assets held for sale Current liabilities: Accounts payable $ 193 $ 34 $ 227 Accrued and other current liabilities 35 23 58 Total current liabilities 228 57 285 Deferred income taxes — 13 13 Long-term debt — 2 2 Asset retirement obligations 168 7 175 Other noncurrent liabilities 28 3 31 Total liabilities associated with assets held for sale—discontinued operations $ 424 $ 82 $ 506 Total liabilities associated with assets held for sale—continuing operations (Note 4) $ 2 $ — $ 2 Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(b) $ 426 $ 82 $ 508 __________ (a) Domestic includes $45 million impairment in Powder River Basin of the net assets
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]	Summarized Results of Discontinued Operations For the year ended December 31, 2015 Domestic International Total (Millions) Total revenues $ 577 $ 15 $ 592 Costs and expenses: Lease and facility operating $ 99 $ 4 $ 103 Gathering, processing and transportation 257 — 257 Taxes other than income 18 3 21 Accrual for contract obligations retained and related accretion 190 — 190 Gas management 1 — 1 Exploration 26 — 26 Depreciation, depletion and amortization 412 — 412 Impairment of assets held for sale 2,324 — 2,324 General and administrative 44 1 45 Other—net (10 ) — (10 ) Total costs and expenses 3,361 8 3,369 Operating income (loss) (2,784 ) 7 (2,777 ) Investment income and other 5 1 6 Loss on sale of Powder River Basin (15 ) — (15 ) Gain on sale of international assets — 41 41 Income (loss) from discontinued operations before income taxes (2,794 ) 49 (2,745 ) Provision (benefit) for income taxes (1,020 ) (3 ) (1,023 ) Income (loss) from discontinued operations $ (1,774 ) $ 52 $ (1,722 ) For the year ended December 31, 2014 Domestic International Total (Millions) Total revenues $ 1,159 $ 163 $ 1,322 Costs and expenses: Lease and facility operating $ 142 $ 37 $ 179 Gathering, processing and transportation 327 1 328 Taxes other than income 54 28 82 Gas management, including charges for unutilized pipeline capacity 8 — 8 Exploration 72 4 76 Depreciation, depletion and amortization 458 42 500 Impairment of producing properties and costs of acquired unproved reserves 50 — 50 Loss on sale of working interest in the Piceance Basin 196 — 196 General and administrative 51 16 67 Other—net (1 ) 12 11 Total costs and expenses 1,357 140 1,497 Operating income (loss) (198 ) 23 (175 ) Interest capitalized 1 — 1 Investment income and other 6 19 25 Income (loss) from discontinued operations before income taxes (191 ) 42 (149 ) Provision (benefit) for income taxes(a) (71 ) 7 (64 ) Income (loss) from discontinued operations $ (120 ) $ 35 $ (85 ) __________ (a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock. For the year ended December 31, 2013 Domestic International Total (Millions) Total revenues $ 1,104 $ 152 $ 1,256 Costs and expenses: Lease and facility operating $ 162 $ 37 $ 199 Gathering, processing and transportation 357 3 360 Taxes other than income 49 24 73 Gas management, including charges for unutilized pipeline capacity 4 — 4 Exploration 7 7 14 Depreciation, depletion and amortization 552 34 586 Impairment of producing properties and costs of acquired unproved reserves 280 3 283 Gain on sale of Powder River Basin deep rights leasehold (36 ) — (36 ) General and administrative 57 14 71 Other—net 5 — 5 Total costs and expenses 1,437 122 1,559 Operating income (loss) (333 ) 30 (303 ) Interest capitalized 4 — 4 Investment income and other 4 21 25 Income (loss) from discontinued operations before income taxes (325 ) 51 (274 ) Provision (benefit) for income taxes(a) (119 ) 31 (88 ) Income (loss) from discontinued operations $ (206 ) $ 20 $ (186 ) __________ (a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

Earnings (Loss) Per Common Sh34

Earnings (Loss) Per Common Share from Continuing Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share from Continuing Operations	The following table summarizes the calculation of earnings per share. Years Ended December 31, 2015 2014 2013 (Millions, except per-share amounts) Income (loss) from continuing operations attributable to WPX Energy, Inc. $ (4 ) $ 256 $ (993 ) Less: Dividends on preferred stock 9 — — Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ (13 ) $ 256 $ (993 ) Basic weighted-average shares 234.2 202.7 200.5 Effect of dilutive securities(a): Nonvested restricted stock units and awards — 2.7 — Stock options — 0.9 — Diluted weighted-average shares 234.2 206.3 200.5 Earnings (loss) per common share from continuing operations: Basic $ (0.06 ) $ 1.26 $ (4.95 ) Diluted $ (0.06 ) $ 1.24 $ (4.95 ) __________ (a) The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders. Years Ended December 31, 2015 2014 2013 (Millions) Weighted-average nonvested restricted stock units and awards 1.3 — 2.5 Weighted-average stock options 0.1 — 1.1 Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 13) 15.5 — —
Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Options	The table below includes information related to stock options that were outstanding at December 31, 2015, 2014 and 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares. 2015 2014 2013 Options excluded (millions) 2.6 1.4 0.4 Weighted-average exercise price of options excluded $ 16.16 $ 18.42 $ 20.24 Exercise price range of options excluded $11.46 - $21.81 $16.46 - $21.81 $20.21 - $20.97 Fourth quarter weighted-average market price $ 7.43 $ 15.96 $ 19.97

Asset Sales, Impairments and 35

Asset Sales, Impairments and Exploration Expenses (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Summary of Significant Gains or Losses Reflected in Impairment of Producing Properties and Costs of Acquired Unproved Reserves, Goodwill Impairment and Other-Net within Costs and Expenses	The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments. Years Ended December 31, 2015 2014 2013 (Millions) Impairment of producing properties and costs of acquired unproved reserves(a) $ — $ 15 $ 772 Impairment of equity method investment in Appalachian Basin $ — $ — $ 20 __________ (a) Excludes related impairments of unproved leasehold included in exploration expenses.
Summary of Exploration Expenses	The following table presents a summary of exploration expenses. Years Ended December 31, 2015 2014 2013 (Millions) Geologic and geophysical costs $ 7 $ 6 $ 12 Impairments of exploratory area well costs and dry hole costs 24 21 3 Unproved leasehold property impairments, amortization and expiration 54 74 402 Total exploration expenses $ 85 $ 101 $ 417

Properties and Equipment (Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Properties and Equipment, at Cost	Properties and equipment is carried at cost and consists of the following: Estimated Useful Life(a) (Years) December 31, 2015 2014 (Millions) Proved properties (b) $ 5,520 $ 3,852 Unproved properties (c) 2,342 349 Gathering, processing and other facilities 15-25 217 102 Construction in progress (c) 198 368 Other 3-40 138 131 Total properties and equipment, at cost 8,415 4,802 Accumulated depreciation, depletion and amortization (1,893 ) (1,407 ) Properties and equipment—net $ 6,522 $ 3,395 __________ (a) Estimated useful lives are presented as of December 31, 2015 . (b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1). (c) Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Rollforward of Asset Retirement Obligation	A rollforward of our asset retirement obligations for the years ended 2015 and 2014 is presented below. 2015 2014 (Millions) Balance, January 1 $ 77 $ 67 Liabilities incurred 26 9 Liabilities settled (2 ) (1 ) Liabilities associated with assets sold — — Estimate revisions (4 ) (3 ) Accretion expense(a) 5 5 Balance, December 31 $ 102 $ 77 Amount reflected as current $ 3 $ 2 __________ (a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Accounts Payable and Accrued 37

Accounts Payable and Accrued and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
Accounts Payable	Accounts Payable The following table presents a summary of our accounts payable as of the dates indicated below. December 31, 2015 2014 (Millions) Trade $ 85 $ 171 Accrual for capital expenditures 65 235 Royalties 71 71 Affiliate payable for revenue related to assets held for sale 43 118 Other 14 43 $ 278 $ 638
Accrued and Other Current Liabilities	Accrued and other current liabilities The following table presents a summary of our accrued and other current liabilities as of the dates indicated below. December 31, 2015 2014 (Millions) Taxes other than income taxes $ 25 $ 10 Accrued interest 82 53 Compensation and benefit related accruals 61 55 Gathering and transportation 8 7 Gathering and transportation related to exited areas 56 6 Accrued income taxes 41 3 Other, including other loss contingencies 29 11 $ 302 $ 145

Debt and Banking Arrangements (

Debt and Banking Arrangements (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	The following table presents a summary of our debt as of the dates indicated below. December 31, 2015 (a) 2014 (a) (Millions) 5.250% Senior Notes due 2017 $ 355 $ 400 7.500% Senior Notes due 2020 500 — 6.000% Senior Notes due 2022 1,100 1,100 8.250% Senior Notes due 2023 500 — 5.250% Senior Notes due 2024 500 500 Credit facility agreement 265 280 Other 1 1 Total debt $ 3,221 $ 2,281 Less: Current portion of long-term debt 1 1 Total long-term debt $ 3,220 $ 2,280 Less: Debt issuance costs $ 31 $ 20 Total long-term debt, net(b) $ 3,189 $ 2,260 __________ (a) Interest paid on debt totaled $120 million and $97 million for 2015 and 2014 , respectively. (b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Provision (Benefit) for Incom39

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes from Continuing Operations	The following table includes the provision (benefit) for income taxes from continuing operations. Years Ended December 31, 2015 2014 2013 (Millions) Provision (benefit): Current: Federal $ (4 ) $ 8 $ (28 ) State 7 1 (5 ) 3 9 (33 ) Deferred: Federal 12 134 (496 ) State 9 5 (38 ) 21 139 (534 ) Total provision (benefit) $ 24 $ 148 $ (567 )
Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate	The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes. Years Ended December 31, 2015 2014 2013 (Millions) Provision (benefit) at statutory rate $ 7 $ 141 $ (550 ) Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 4 4 (25 ) State income tax legislation change (net of federal benefit) — 9 — Effective state income tax rate change (net of federal benefit) 7 (9 ) (3 ) Other 6 3 11 Provision (benefit) for income taxes $ 24 $ 148 $ (567 )
Significant Components of Deferred Tax Liabilities and Deferred Tax Assets	The following table includes significant components of deferred tax liabilities and deferred tax assets. December 31, 2015 2014 (Millions) Deferred tax liabilities: Properties and equipment $ 988 $ 738 Derivatives, net 155 170 Other, net 1 17 Total deferred tax liabilities 1,144 925 Deferred tax assets: Accrued liabilities and other 248 124 Alternative minimum tax credits 114 60 Loss carryovers 441 51 Other, net — 32 Total deferred tax assets 803 267 Less: valuation allowance 124 114 Total net deferred tax assets 679 153 Net deferred tax liabilities $ 465 $ 772

Contingent Liabilities and Co40

Contingent Liabilities and Commitments (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitment Under Contracts	Our commitments under these contracts as of December 31, 2015 are as follows: (Millions) 2016 $ 140 2017 130 2018 116 2019 104 2020 91 Thereafter 105 Total $ 686
Future Minimum Annual Rentals Under Noncancelable Operating Leases	Future minimum annual rentals under noncancelable operating leases as of December 31, 2015, are payable as follows: (Millions) 2016 $ 28 2017 23 2018 12 2019 7 2020 7 Thereafter 9 Total $ 86

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock Option Activity and Related Information	Stock Options The following summary reflects stock option activity and related information for the year ended December 31, 2015 . WPX Plan Stock Options Options Weighted- Average Exercise Price Aggregate Intrinsic Value (Millions) (Millions) Outstanding at December 31, 2014(a) 3.1 $ 14.80 $ 2 Granted — $ — Exercised (0.2 ) $ 10.33 Forfeited — $ — Outstanding at December 31, 2015 2.9 $ 15.07 $ — Exercisable at December 31, 2015 2.7 $ 14.75 $ — __________ (a) Includes approximately 137 thousand shares held by Williams' employees at a weighted average price of $10.64 per share at December 31, 2014 .
Additional Information about Stock Options Outstanding and Exercisable	The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2015 . WPX Plan Stock Options Outstanding Stock Options Exercisable Range of Exercise Prices Options Weighted- Average Exercise Price Weighted- Average Remaining Contractual Life Options Weighted- Average Exercise Price Weighted- Average Remaining Contractual Life (Millions) (Years) (Millions) (Years) $ 6.02 to $12.32 0.9 $ 9.79 3.0 0.9 $ 9.79 3.0 $ 14.41 to $17.47 1.2 $ 15.97 5.0 1.1 $ 15.92 4.6 $18.16 to $19.95 0.3 $ 18.21 6.4 0.3 $ 18.21 6.4 $20.21 to $21.81 0.5 $ 20.62 4.0 0.4 $ 20.37 2.8 Total 2.9 $ 15.07 4.4 2.7 $ 14.75 4.0
Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model	The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows: WPX Plan 2015 2014 2013 Weighted-average grant date fair value of options granted $ — $ 18.94 $ 6.04 Weighted-average assumptions: Dividend yield — — — Volatility — % 43.0 % 42.8 % Risk-free interest rate — % 1.85 % 1.06 % Expected life (years) 0.0 5.9 6.0
Summary of Nonvested Restricted Stock Unit Activity and Related Information	Nonvested Restricted Stock Units The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2015 . WPX Plan Restricted Stock Units Shares Weighted- Average Fair Value(a) (Millions) Nonvested at December 31, 2014 5.1 $ 17.58 Granted 3.1 $ 10.24 Forfeited (0.1 ) $ 14.89 Vested (2.2 ) $ 18.34 Nonvested at December 31, 2015 5.9 $ 13.34 __________ (a) Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other Restricted Stock Unit Information	Other restricted stock unit information WPX Plan 2015 2014 2013 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 10.24 $ 18.37 $ 14.97 Total fair value of restricted stock units vested during the year (millions) $ 40 $ 33 $ 18

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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, restricted cash and margin deposits approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 359 $ — $ 359 $ 14 $ 503 $ 5 $ 522 Energy derivative liabilities $ — $ 15 $ — $ 15 $ 32 $ 10 $ — $ 42 Total debt(a) $ — $ 2,495 $ — $ 2,495 $ — $ 2,218 $ — $ 2,218 __________ (a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $3,220 million and $2,280 million as of December 31, 2015 and 2014 , respectively.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs	The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy. Years ended December 31, 2015 2014 2013 (Millions) Beginning balance $ 5 $ — $ (1 ) Realized and unrealized gains (losses): Included in income (loss) from continuing operations (1 ) 5 (2 ) Included in other comprehensive income (loss) — — — Purchases, issuances, and settlements (4 ) — 3 Transfers out of Level 3 — — — Ending balance $ — $ 5 $ — Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31 $ — $ 5 $ (1 )
Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy	The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy. Total losses for the years ended December 31, 2015 (a) 2014 (b) 2013 (c) (Millions) Impairments: Producing properties and costs of acquired unproved reserves (Note 3 and Note 5) $ 2,308 $ 20 $ 1,055 Unproved leasehold 26 — 317 Equity method investment (Note 5) — — 20 $ 2,334 $ 20 $ 1,392 __________ (a) As a result of our impairment assessment in 2015, we recorded the following significant impairment charges, including those reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately $880 million : • $2,308 million impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment. • $26 million impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment. (b) As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million : • $11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent . • $9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties including $5 million of which is reflected in discontinued operations. (c) As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million : • $792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent . • $317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market. • $107 million impairment charge related to natural gas producing properties in the Powder River Basin, reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent . • $88 million impairment charge related to acquired unproved reserves in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively. • $85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

Derivatives and Concentration43

Derivatives and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Volumes 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	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 December 31, 2015 . Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Price (c) Crude Oil Crude Oil 2016 Fixed Price Swaps WTI (27,549 ) $ 61.70 Crude Oil 2016 Basis Swaps Midland (5,000 ) $ (0.45 ) Crude Oil 2016 Fixed Price Calls WTI (1,243 ) $ 55.75 Crude Oil 2016 Swaptions WTI (1,257 ) $ 57.15 Crude Oil 2017 Fixed Price Swaps WTI (9,304 ) $ 61.66 Crude Oil 2017 Swaptions WTI (1,500 ) $ 59.00 Natural Gas Natural Gas 2016 Fixed Price Swaps Henry Hub (213 ) $ 3.79 Natural Gas 2016 Basis Swaps NGPL (5 ) $ (0.23 ) Natural Gas 2016 Basis Swaps Permian (33 ) $ (0.17 ) Natural Gas 2016 Basis Swaps Rockies (230 ) $ (0.21 ) Natural Gas 2016 Basis Swaps San Juan (100 ) $ (0.18 ) Natural Gas 2016 Basis Swaps SoCal (45 ) $ (0.01 ) Natural Gas 2017 Basis Swaps Rockies (50 ) $ (0.21 ) Natural Gas 2017 Basis Swaps San Juan (33 ) $ (0.16 ) Natural Gas 2017 Basis Swaps SoCal (10 ) $ — Natural Gas 2017 Fixed Price Calls Henry Hub (16 ) $ 4.50 Natural Gas 2017 Swaptions Henry Hub (65 ) $ 4.19 Natural Gas 2018 Fixed Price Calls Henry Hub (16 ) $ 4.75 __________ (a) Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, calls, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. (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 the natural gas is reported in $/MMBtu. Derivatives primarily related to transportation The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2015 . The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices. Commodity Period Contract Type (a) Location (b) Notional Volume (c) Natural Gas 2016 Index Multiple (17 ) __________ (a) We enter into exchange traded fixed price and basis swaps, over-the-counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component. (b) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements. (c) Natural gas volumes are reported in BBtu/day.
Fair Value of Energy Commodity Derivatives	The following table presents the fair value of energy commodity derivatives. 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. December 31, 2015 2014 Assets Liabilities Assets Liabilities (Millions) Derivatives related to production not designated as hedging instruments $ 359 $ 15 $ 503 $ 10 Derivatives related to physical marketing agreements not designated as hedging instruments — — 19 32 Total derivatives not designated as hedging instruments $ 359 $ 15 $ 522 $ 42
DerivativeGainLoss [Table Text Block]	The following table presents the net gain (loss) related to our energy commodity derivatives. Years Ended December 31, 2015 2014 2013 Gain (loss) from derivatives related to production not designated as hedging instruments(a) $ 438 $ 515 $ (57 ) Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments(b) (20 ) (81 ) (67 ) Net gain (loss) on derivatives not designated as hedges $ 418 $ 434 $ (124 ) __________ (a) Includes settlements totaling $650 million for the year ended December 31, 2015, and payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively. (b) Includes payments totaling $33 million , $120 million and $6 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Gross And Net Derivative Asset and Liability	The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Cash Collateral Posted(Received) Net Amount December 31, 2015 (Millions) Derivative assets with right of offset or master netting agreements $ 359 $ (14 ) $ — $ 345 Derivative liabilities with right of offset or master netting agreements $ (15 ) $ 14 $ — $ (1 ) December 31, 2014 Derivative assets with right of offset or master netting agreements $ 522 $ (25 ) $ — $ 497 Derivative liabilities with right of offset or master netting agreements $ (42 ) $ 25 $ 17 $ — __________ (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.
Concentration of Receivables, Net of Allowances, by Product or Service	The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31. 2015 2014 (Millions) Receivables by product or service: Sale of natural gas, crude and related products and services $ 171 $ 339 Joint interest owners 90 88 Other 39 10 Total $ 300 $ 437
Gross and Net Credit Exposure from Derivative Contracts	The following table summarizes the gross and net credit exposure from our derivative contracts as of December 31, 2015 . Counterparty Type Gross Total Net Total (Millions) Financial institutions (Investment Grade)(a) $ 360 $ 346 Credit reserves (1 ) (1 ) Credit exposure from derivatives $ 359 $ 345 __________ (a) 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 in investment grade.

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data	Summarized quarterly financial data are as follows: First Quarter Second Quarter Third Quarter Fourth Quarter (Millions, except per-share amounts) 2015 Revenues $ 420 $ 154 $ 407 $ 385 Operating costs and expenses $ 300 $ 251 $ 300 $ 294 Income (loss) from continuing operations $ 52 $ 23 $ (70 ) $ (9 ) Income (loss) from discontinued operations 16 (53 ) (160 ) (1,525 ) Net income (loss) $ 68 $ (30 ) $ (230 ) $ (1,534 ) Amounts attributable to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ 52 $ 23 $ (74 ) $ (14 ) Income (loss) from discontinued operations 15 (53 ) (160 ) (1,525 ) Net income (loss) $ 67 $ (30 ) $ (234 ) $ (1,539 ) Basic earnings (loss) per common share: Income (loss) from continuing operations $ 0.26 $ 0.11 $ (0.29 ) $ (0.06 ) Income (loss) from discontinued operations 0.07 (0.25 ) (0.64 ) (5.53 ) Net income (loss) $ 0.33 $ (0.14 ) $ (0.93 ) $ (5.59 ) Diluted earnings (loss) per common share: Income (loss) from continuing operations $ 0.25 $ 0.11 $ (0.29 ) $ (0.06 ) Income (loss) from discontinued operations 0.07 (0.25 ) (0.64 ) (5.53 ) Net income (loss) $ 0.32 $ (0.14 ) $ (0.93 ) $ (5.59 ) 2014 Revenues $ 602 $ 465 $ 538 $ 918 Operating costs and expenses $ 545 $ 439 $ 362 $ 399 Income (loss) from continuing operations $ (28 ) $ (37 ) $ 52 $ 269 Income (loss) from discontinued operations 47 (96 ) 14 (50 ) Net income (loss) $ 19 $ (133 ) $ 66 $ 219 Amounts attributable to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (28 ) $ (37 ) $ 52 $ 269 Income (loss) from discontinued operations 46 (98 ) 10 (50 ) Net income (loss) $ 18 $ (135 ) $ 62 $ 219 Basic earnings (loss) per common share: Income (loss) from continuing operations $ (0.14 ) $ (0.18 ) $ 0.26 $ 1.32 Income (loss) from discontinued operations 0.23 (0.48 ) 0.04 (0.24 ) Net income (loss) $ 0.09 $ (0.66 ) $ 0.30 $ 1.08 Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (0.14 ) $ (0.18 ) $ 0.26 $ 1.30 Income (loss) from discontinued operations 0.23 (0.48 ) 0.04 (0.24 ) Net income (loss) $ 0.09 $ (0.66 ) $ 0.30 $ 1.06

Supplemental Oil and Gas Disc45

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Capitalized Costs	Capitalized Costs As of December 31, 2015 2014 (Millions) Proved Properties $ 5,703 $ 4,192 Unproved properties 2,342 349 8,045 4,541 Accumulated depreciation, depletion and amortization and valuation provisions (1,763 ) (1,292 ) Net capitalized costs $ 6,282 $ 3,249 __________ • Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $202 million and $109 million , net, for 2015 and 2014, respectively. The $109 million at December 31, 2014 includes costs related to gathering assets sold or held for sale in 2015. • Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells. • Unproved properties consist primarily of unproved leasehold costs.
Cost Incurred	Cost Incurred For the years ended December 31, 2015 2014 2013 (Millions) Acquisition $ 3,208 $ 294 $ 57 Exploration 84 92 104 Development 657 1,376 939 $ 3,949 $ 1,762 $ 1,100 __________ • Costs incurred include capitalized and expensed items. • Acquisition costs are as follows: costs in 2015 primarily relate to the allocated purchase price of RKI properties in the Permian-Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) and includes 53 MMboe of proved developed reserves. Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include approximately 5 MMboe of proved reserves. The 2013 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves. • Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds. The 2015 amount primarily related to the drilling of Piceance Niobrara wells. • Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our Piceance Basin operations were $106 million , $430 million and $284 million for 2015, 2014 and 2013, respectively.
Results of Operations	Results of Operations For the years ended December 31, 2015 2014 2013 (Millions) Revenues: Oil sales $ 494 $ 669 $ 475 Natural gas sales 138 282 259 Natural gas liquid sales 23 20 10 Net gain (loss) on derivatives not designated as hedges 438 515 (57 ) Other revenues 7 8 3 Total revenues 1,100 1,494 690 Costs: Lease and facility operating 145 143 109 Gathering, processing and transportation 64 71 73 Taxes other than income 62 88 68 Exploration 85 101 417 Depreciation, depletion and amortization 528 363 354 Impairment of certain proved properties — 15 772 Impairment of costs of acquired unproved reserves — — — Net (gain) loss on sales of assets (349 ) — — General and administrative 203 217 211 Acquisition costs 23 — — Other (income) expense 63 13 12 Total costs 824 1,011 2,016 Results of operations 276 483 (1,326 ) Provision (benefit) for income taxes 101 176 (484 ) Exploration and production net income (loss) $ 175 $ 307 $ (842 ) __________ • Amounts for all years exclude the equity losses from our equity method investees. Net equity losses from these investees were $1 million and $21 million in 2014 and 2013 , respectively. • Other revenues consist of activities that are an indirect part of the producing activities. • Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2015 and 2014 include impairments of certain exploratory well costs (see Note 5 of Notes to Consolidated Financial Statements). Exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachian Basin. • Depreciation, depletion and amortization includes depreciation of support equipment. • Other income (expense) includes $22 million as a result of a termination of a crude oil transportation and sales agreement. Also included is a $23 million charge related to the net present value of future obligations under a gathering agreement in an Appalachian area for which we plugged and abandoned our remaining wells in December 2015.
Proved Reserves	The following is a summary of changes in our domestic proved reserves including proved reserves in the Powder River Basin which is reported as discontinued operations. Excluded from the table are our international reserves that are primarily attributable to a consolidated subsidiary (Apco) which represented less than 5 percent of our total reserves. The international interests were sold in January 2015. In addition, the table includes proved reserves in the Piceance Basin. As of December 31, 2015, proved developed reserves and proved undeveloped reserves in the Piceance Basin were 228 MMboe and 75 MMboe, respectively. Oil (MMBbls) Natural Gas (Bcf) NGLs (MMBbls) All Products (MMBoe) Proved reserves at December 31, 2012 76.5 3,369.1 110.4 748.4 Revisions 3.5 308.3 (25.4 ) 29.5 Divestitures — (0.2 ) — — Extensions and discoveries 28.8 312.0 8.1 88.9 Production (5.9 ) (359.4 ) (7.4 ) (73.2 ) Proved reserves at December 31, 2013 102.9 3,629.8 85.7 793.6 Revisions (7.7 ) (198.3 ) (13.4 ) (54.1 ) Purchases 4.2 6.0 0.8 6.0 Divestitures (1.8 ) (314.6 ) (8.5 ) (62.7 ) Extensions and discoveries 42.4 362.1 12.5 115.2 Production (9.2 ) (335.4 ) (6.3 ) (71.4 ) Proved reserves at December 31, 2014 130.8 3,149.6 70.8 726.6 Revisions (31.9 ) (624.6 ) (14.0 ) (150.0 ) Purchases 39.8 205.6 20.7 94.7 Divestitures — (380.3 ) — (63.4 ) Extensions and discoveries 17.1 116.9 5.1 41.6 Production (13.1 ) (277.0 ) (7.3 ) (66.5 ) Proved reserves at December 31, 2015 142.7 2,190.2 75.3 583.0 Proved developed reserves: December 31, 2013 36.8 2,265.2 48.6 463.0 December 31, 2014 60.0 2,090.0 43.9 452.3 December 31, 2015 83.0 1,618.2 49.5 402.2 Proved undeveloped reserves: December 31, 2013 66.1 1,364.6 37.1 330.6 December 31, 2014 70.8 1,059.6 26.9 274.3 December 31, 2015 59.7 572.0 25.8 180.8 __________ • Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit . • Revision in 2015 primarily reflect 209 MMboe of negative revisions related to the decrease in the 12 month average prices partially offset by 59 MMboe of positive revisions due to decreased costs and well improvements. The 2015 revisions comprised 108 MMboe net negative revisions related to proved undeveloped locations and 42 MMboe net negative revisions related to proved developed locations. Revisions in 2014 primarily reflect 16 MMboe of net positive revisions to developed reserves and 70 MMboe of net negative revisions to undeveloped reserves. The 70 MMboe of net negative revisions were primarily due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules. Revisions in 2013 reflects 22 MMboe related to developed reserves and 7 MMboe related to undeveloped reserves. • Purchases reflects the RKI acquisition of which 53.4 MMboe is proved developed and 41.3 MMboe is associated with proved undeveloped locations. • Divestitures in 2015 relate to sales of properties in the Powder River Basin ( 28 MMboe) and the Appalachian Basin ( 35 MMboe). Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (see Notes 3 and 5 of Notes to Consolidated Financial Statements). • Extensions and discoveries in 2015 reflect 20.9 MMboe added for proved developed locations and 20.7 MMboe for proved undeveloped locations primarily related to our San Juan Gallup and Williston Basins. Extensions and discoveries in 2014 reflect 31 MMboe added for drilled locations and 84 MMboe added for new proved undeveloped locations. Extensions and discoveries in 2013 reflects 21 MMboe added for drilled locations and 68 MMboe added for new undeveloped locations. The 2014 and 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin.
Standardized Measure of Discounted Future Net Cash Flows	Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2015 2014 (Millions) Future cash inflows $ 12,391 $ 26,444 Less: Future production costs 7,757 12,641 Future development costs 1,761 3,426 Future income tax provisions — 2,519 Future net cash flows 2,873 7,858 Less 10 percent annual discount for estimated timing of cash flows 1,589 3,975 Standardized measure of discounted future net cash inflows $ 1,284 $ 3,883 __________ • Our historical tax basis (i.e. future deductions for taxable income calculation) of proved properties at December 31, 2015 is greater than the total future net cash flows before taxes; therefore, future taxable income would be less than zero. • Included in the $1,284 million of discounted future net cash inflows is $270 million related to the properties in the Piceance Basin.
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows	Sources of Change in Standardized Measure of Discounted Future Net Cash Flows For the years ended December 31, 2015 2014 2013 (Millions) Beginning of year $ 3,883 $ 2,964 $ 1,949 Sales of oil and gas produced, net of operating costs (541 ) (1,324 ) (1,040 ) Net change in prices and production costs (5,231 ) 303 1,198 Extensions, discoveries and improved recovery, less estimated future costs 254 1,761 1,282 Development costs incurred during year 276 592 414 Changes in estimated future development costs 1,213 143 (736 ) Purchase of reserves in place, less estimated future costs 657 147 — Sale of reserves in place, less estimated future costs (397 ) (391 ) (3 ) Revisions of previous quantity estimates (374 ) (536 ) 239 Accretion of discount 489 383 225 Net change in income taxes 1,073 (142 ) (540 ) Other (18 ) (17 ) (24 ) Net changes (2,599 ) 919 1,015 End of year $ 1,284 $ 3,883 $ 2,964

Schedule II - Valuation And Q46

Schedule II - Valuation And Qualifying Accounts Schedule II (Tables)	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts Disclosure [Line Items]
Summary of Valuation Allowance [Table Text Block]	Beginning Balance Charged (Credited) to Costs and Expenses Other Deductions Ending Balance 2015: Allowance for doubtful accounts—accounts and notes receivable(a) $ 6 $ 5 $ — $ (5 ) $ 6 Deferred tax asset valuation allowance(b) 118 3 3 — 124 Price-risk management credit reserves—assets(a)(c) 1 — — — 1 2014: Allowance for doubtful accounts—accounts and notes receivable(a) $ 7 $ — $ — $ (1 ) $ 6 Deferred tax asset valuation allowance(b) 102 (1 ) 17 — 118 Price-risk management credit reserves—assets(a)(c) — — 1 — 1 2013: Allowance for doubtful accounts—accounts and notes receivable(a) $ 11 $ (3 ) $ — $ (1 ) $ 7 Deferred tax asset valuation allowance(b) 19 80 3 — 102 __________ (a) Deducted from related assets. (b) Deducted from related assets, with a portion included in assets held for sale. (c) Included in revenues.

Description of Business, Basi47

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 08, 2016
Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage	69.00%
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Minimum	20.00%
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Maximum	50.00%
Restricted cash related to escrow accounts to settle agreement	$ 10	$ 6
Hedge gains realized from natural gas revenues			$ 5
Charges for unutilized transportation capacity included in gas management expenses	$ 38	57	$ 61
Projects with construction periods, minimum	3 months
Total estimated project cost	$ 1
Share Based Compensation Arrangement By Share Based Payment Award Minimum Exercisable Period For Stock Options	3 years
Share Based Compensation Arrangement By Share Based Payment Award Award Term	10 years
Restricted stock units vesting period	3 years
Debt Issuance Costs, Noncurrent, Net	$ 45	28
Senior Notes [Member]
Accounting Policies [Line Items]
Debt Issuance Costs, Noncurrent, Net	$ 31	$ 20
Subsequent Event | Piceance Basin [Member]
Accounting Policies [Line Items]
Disposal Group, Including Discontinued Operation, Consideration				$ 910

Description of Business, Basi48

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventory [Line Items]
Material Supplies And Other	$ 44	$ 29
Crude Inventory In Transit	2	2
Inventories	$ 46	$ 31

Acquisition Business Acquisitio

Acquisition Business Acquisition, Pro Forma Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Revenues	$ 1,578	$ 2,905
Net income (loss) from continuing operations attributable to WPX Energy, Inc.	$ 81	$ 278

Acquisition Summary of Consider

Acquisition Summary of Consideration Paid and Fair Value of Assets Acquired and Liabilities Assumed(Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Properties and equipment-net, at cost		$ 8,415	$ 4,802
Consideration
Cash, net of an estimated post-close settlement		1,251
Fair value of WPX common stock issued		296
Total consideration		1,547
Fair value of liabilities assumed
Accounts payable		104
Accrued liabilities		74
Deferred income taxes		692
Long-term debt		990
Asset retirement obligation		23
Total liabilities assumed as of December 31, 2015		1,883
Fair value of assets acquired
Cash and cash equivalents		51
Accounts receivable, net		80
Derivative assets, current		97
Derivative assets, noncurrent		34
Inventories		12
Other current assets		3
Properties and equipment(a)	[1]	3,149
Other noncurrent assets		4
Total assets acquired as of December 31, 2015		3,430
Net fair value of assets and liabilities		1,547
RKI [Member]
Business Acquisition [Line Items]
Properties and equipment-net, at cost		3,149
Proved Developed Reserves [Member]
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2],[3]	5,520	3,852
Proved Developed Reserves [Member] | RKI [Member]
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2],[3]	881
Unproved Properties
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2],[4]	2,342	349
Unproved Properties | RKI [Member]
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2],[4]	2,108
Gathering, Processing and Other Facilities
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2]	217	102
Gathering, Processing and Other Facilities | RKI [Member]
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2]	157
Other
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2]	138	$ 131
Other | RKI [Member]
Business Acquisition [Line Items]
Properties and equipment-net, at cost	[2]	$ 3
[1]	Properties and equipment reflect the following as of the Acquisition date:Proved properties $881Unproved properties 2,108Gathering, processing and other facilities 157Other 3Total $3,149
[2]	Estimated useful lives are presented as of December 31, 2015.
[3]	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
[4]	Unproved properties and construction in progress are not yet subject to depreciation and depletion.

Acquisition Additional informat

Acquisition Additional information (Details) shares in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)aWellshares	Dec. 31, 2014USD ($)MBoeMMBoe	Dec. 31, 2013USD ($)	Aug. 17, 2015USD ($)
Business Acquisition [Line Items]
Acquisition costs (Note 2)		$ 23	$ 0	$ 0
Loss on extinguishment of debt (Note 2)		$ (65)	$ 0	$ 0
RKI [Member]
Business Acquisition [Line Items]
Purchase Price					$ 2,750
Consideration Transferred, Equity Interests Issued and Issuable | shares		40
Payments to Acquire Businesses, Gross		$ 2,280
Acquisition debt assumed		400
Acquisition costs (Note 2)	$ 104	23
Acquisition bridge facility fees		16
Loss on extinguishment of debt (Note 2)		$ (65)
Net Acres | a		92,000
Productive Oil Wells, Number of Wells, Gross | Well		659
Working Interest		93.00%
Production, Barrels of Oil Equivalents | MBoe			18.7
Proved Developed And Undeveloped Reserves Net Equivalent | MMBoe			101.5
Crude Oil [Member] | RKI [Member]
Business Acquisition [Line Items]
Percentage of Production by product			43.00%
Percentage reserves by product			40.00%
Natural Gas Liquids | RKI [Member]
Business Acquisition [Line Items]
Percentage of Production by product			23.00%
Percentage reserves by product			25.00%
Natural Gas | RKI [Member]
Business Acquisition [Line Items]
Percentage of Production by product			34.00%
Percentage reserves by product			35.00%

Discontinued Operations - Addit

Discontinued Operations - Additional Information (Detail) - USD ($) $ in Millions		3 Months Ended								9 Months Ended	12 Months Ended
		Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 08, 2016	Jan. 29, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets													$ (36)
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents												$ 29
Impairment of Oil and Gas Properties, Disposal Group											$ 2,324	50	283
Contractual Obligation			$ 686								686
Noncontrolling interests in consolidated subsidiaries			0								0	109
Asset impairment charges			2,300									15	1,100
Impairment of producing properties and costs of acquired unproved reserves	[1]										0	15	772
Results of Operations, Dry Hole Costs											24	21	3
Unproved leasehold property impairment, amortization and expiration											54	74	402
Proceeds from sales of domestic assets and international interests											$ 1,019	374	49
Kokopelli area of Piceance Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment Of Costs Of Acquired Unproved Reserves								$ 69	$ 19
Piceance Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Derivatives, Determination of Fair Value											82
Other Commitment			423								$ 423
Proved Developed Reserves Production Percentage Maximum											52.00%
Percentage of Production by product											58.00%
Asset impairment charges											$ 2,334
Impairment of producing properties and costs of acquired unproved reserves											2,308
Impairment Of Costs Of Acquired Unproved Reserves													88
Results of Operations, Dry Hole Costs												67
Unproved leasehold property impairment, amortization and expiration											26
Loss On Sale Of Working Interests						$ 1	$ 195
Powder River Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities of Business Transferred under Contractual Arrangement, Noncurrent			133								133
Escrow Deposits Related to Property Sales											13
Disposal Group, Including Discontinued Operation, Consideration			80								80
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax											15
Impairment of Oil and Gas Properties, Disposal Group											16	45
Contractual Obligation			254								254
Liabilities of Business Transferred under Contractual Arrangement, Current			54								54
Disposal group contract obligation expense				$ 187						$ 187	190
International
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration			291								291	294
Gain (Loss) on Disposition of Assets					$ (41)						(41)		0
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax											(41)
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents												29			$ 17
Impairment of Oil and Gas Properties, Disposal Group											0	0	3
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities											3	65	56
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities											15	85	43
Domestic
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets													(36)
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax											15
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents												0
Impairment of Oil and Gas Properties, Disposal Group											2,324	50	280
Disposal group contract obligation expense											190
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities											184	585	478
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities											251	$ 512	$ 369
Gathering and Treating [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other Commitment			524								524
Gathering and Treating [Member] | Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation			104								104
Capacity [Member] | Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation			$ 150								150
Subsequent Event | Piceance Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration														$ 910
Disposal group contract obligation expense		$ 104
Post Closing [Member] | Piceance Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of domestic assets and international interests											$ 329
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.

Discontinued Operations - Summa

Discontinued Operations - Summarized Results of Discontinued Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									$ 592	$ 1,322		$ 1,256
Lease and facility operating									103	179		199
Gathering, processing and transportation									257	328		360
Taxes other than income									21	82		73
GasManagementExpenseDisposalGroup							$ 11		1	8		4
Exploration									26	76		14
Depreciation, depletion and amortization									412	500		586
Impairment of Oil and Gas Properties, Disposal Group									2,324	50		283
Gain (Loss) on Sale of Deep Rights Leasehold										(196)
Gain (Loss) on Disposition of Assets												(36)
General and administrative									45	67		71
Other net									(10)	11		5
Total costs and expenses									3,369	1,497		1,559
Operating income (loss)									(2,777)	(175)		(303)
Interest capitalized										1		4
Investment income and other									6	25		25
Income (loss) from discontinued operations before income taxes									(2,745)	(149)		(274)
Discontinued Operation, Tax Effect of Discontinued Operation									(1,023)	(64)		(88)
Income (loss) from discontinued operations	$ (1,525)	$ (160)	$ (53)	$ 16	$ (50)	$ 14	$ (96)	$ 47	(1,722)	(85)		(186)
International
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
DeferredForeignIncomeTaxExpenseBenefit-Argentina												10
Deferred Tax Asset, Parent's Basis in Discontinued Operation					$ 18					18
Total revenues									15	163		152
Lease and facility operating									4	37		37
Gathering, processing and transportation									0	1		3
Taxes other than income									3	28		24
GasManagementExpenseDisposalGroup									0	0		0
Exploration									0	4		7
Depreciation, depletion and amortization									0	42		34
Impairment of Oil and Gas Properties, Disposal Group									0	0		3
Gain (Loss) on Sale of Deep Rights Leasehold										0
Gain (Loss) on Disposition of Assets				$ (41)					(41)			0
General and administrative									1	16		14
Other net									0	12		0
Total costs and expenses									8	140		122
Operating income (loss)									7	23		30
Interest capitalized										0		0
Investment income and other									1	19		21
Income (loss) from discontinued operations before income taxes									49	42		51
Discontinued Operation, Tax Effect of Discontinued Operation									(3)	7	[1]	31	[2]
Income (loss) from discontinued operations									52	35		20
Domestic
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									577	1,159		1,104
Lease and facility operating									99	142		162
Gathering, processing and transportation									257	327		357
Taxes other than income									18	54		49
Disposal group contract obligation expense									190
GasManagementExpenseDisposalGroup									1	8		4
Exploration									26	72		7
Depreciation, depletion and amortization									412	458		552
Impairment of Oil and Gas Properties, Disposal Group									2,324	50		280
Gain (Loss) on Sale of Deep Rights Leasehold										(196)
Gain (Loss) on Disposition of Assets												(36)
General and administrative									44	51		57
Other net									(10)	(1)		5
Total costs and expenses									3,361	1,357		1,437
Operating income (loss)									(2,784)	(198)		(333)
Interest capitalized										1		4
Investment income and other									5	6		4
Income (loss) from discontinued operations before income taxes									(2,794)	(191)		(325)
Discontinued Operation, Tax Effect of Discontinued Operation									(1,020)	(71)		(119)
Income (loss) from discontinued operations									$ (1,774)	$ (120)		$ (206)
[1]	(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.
[2]	International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

Discontinued Operations Discont

Discontinued Operations Discontinued Operations- Balance Sheet Disclosures by Disposal Groups (Details) - USD ($) $ in Millions		Dec. 31, 2015		Jan. 29, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents					$ 29
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net		$ 55			165
Disposal group derivative assets, current		68
Disposal Group, Including Discontinued Operation, Inventory		13			22
Disposal Group, Including Discontinued Operation, Other Assets, Current		2			17
Disposal Group Assets, Current		138			233
Disposal Group, Including Discontinued Operation, Investment					152
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment					7,527
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization					(3,741)
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net		880	[1]		3,786
Disposal Group Derivative Assets Noncurrent		14			14
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent					9
Disposal Group, Including Discontinued Operation, Assets		1,032			4,194
Assets Held for Sale, Continuing Operations					200
Assets of disposal group classified as held for sale		1,072			4,394
Disposal Group, Including Discontinued Operation, Accounts Payable		93			227
Disposal Group, Including Discontinued Operation, Accrued Liabilities		47			58
Disposal Group Liabilities, Current		140			285
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities					13
long term debt noncurrent disposal group					2
Disposal Group Asset Retirement Obligation Noncurrent		133			175
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent					31
Disposal Group, Including Discontinued Operation, Liabilities					506
Liabilities of Disposal Group in Continuing Operations					2
Liabilities of disposal group associated with assets held for sale		273			508
Continuing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets Held for Sale, Continuing Operations		$ 40			200
Domestic
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents					0
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net					140
Disposal Group, Including Discontinued Operation, Inventory					15
Disposal Group, Including Discontinued Operation, Other Assets, Current					3
Disposal Group Assets, Current					158
Disposal Group, Including Discontinued Operation, Investment					18
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	[2]				7,082
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization					(3,513)
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net					3,569
Disposal Group Derivative Assets Noncurrent					14
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent					3
Disposal Group, Including Discontinued Operation, Assets					3,762
Assets of disposal group classified as held for sale					3,962
Disposal Group, Including Discontinued Operation, Accounts Payable					193
Disposal Group, Including Discontinued Operation, Accrued Liabilities					35
Disposal Group Liabilities, Current					228
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities					0
long term debt noncurrent disposal group					0
Disposal Group Asset Retirement Obligation Noncurrent					168
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent					28
Disposal Group, Including Discontinued Operation, Liabilities					424
Liabilities of Disposal Group in Continuing Operations					2
Liabilities of disposal group associated with assets held for sale					426
International
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents				$ 17	29
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net					25
Disposal Group, Including Discontinued Operation, Inventory					7
Disposal Group, Including Discontinued Operation, Other Assets, Current					14
Disposal Group Assets, Current					75
Disposal Group, Including Discontinued Operation, Investment					134
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment					445
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization					(228)
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net					217
Disposal Group Derivative Assets Noncurrent					0
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent					6
Disposal Group, Including Discontinued Operation, Assets					432
Assets Held for Sale, Continuing Operations					0
Assets of disposal group classified as held for sale					432
Disposal Group, Including Discontinued Operation, Accounts Payable					34
Disposal Group, Including Discontinued Operation, Accrued Liabilities					23
Disposal Group Liabilities, Current					57
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities					13
long term debt noncurrent disposal group					2
Disposal Group Asset Retirement Obligation Noncurrent					7
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent					3
Disposal Group, Including Discontinued Operation, Liabilities					82
Liabilities of Disposal Group in Continuing Operations					0
Liabilities of disposal group associated with assets held for sale					$ 82
[1]	ncludes $2,308 million impairment in Piceance Basin of the net assets.
[2]	(a) Domestic includes $45 million impairment in Powder River Basin of the net assets

Earnings (Loss) Per Common Sh55

Earnings (Loss) Per Common Share from Continuing Operations (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (loss) from continuing operations attributable to parent including preferred dividends									$ (4)		$ 256	$ (993)
Preferred Stock Dividends, Income Statement Impact									9		0	0
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$ (14)	$ (74)	$ 23	$ 52	$ 269	$ 52	$ (37)	$ (28)	$ (13)		$ 256	$ (993)
Basic weighted-average shares									234.2		202.7	200.5
Diluted weighted-average shares									234.2	[1]	206.3	200.5	[1]
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock											0	0
Earnings (loss) per common share from continuing operations:
Basic (in dollars per share)	$ (0.06)	$ (0.29)	$ 0.11	$ 0.26	$ 1.32	$ 0.26	$ (0.18)	$ (0.14)	$ (0.06)		$ 1.26	$ (4.95)
Diluted (in dollars per share)	$ (0.06)	$ (0.29)	$ 0.11	$ 0.25	$ 1.30	$ 0.26	$ (0.18)	$ (0.14)	$ (0.06)		$ 1.24	$ (4.95)
Nonvested Restricted Stock Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements									1.3		2.7	2.5
Stock Options
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements									0.1		0.9	1.1
Convertible Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock									15.5
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjYwM2U5M2E1MWY3YTQ0YzhhZjMwMzczYzg0OTQyNGYyfFRleHRTZWxlY3Rpb246NEI0ODNEQkM2M0ZBMkNDODc3QTdBMTBBRDE2NEEwOTIM}

Earnings (Loss) Per Common Sh56

Earnings (Loss) Per Common Share from Continuing Operations - (Details1) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average exercise price of options excluded	$ 16.16	$ 18.42	$ 20.24
Fourth quarter weighted-average market price	7.43	15.96	19.97
Exercise price range of options excluded, upper limit	21.81	21.81	20.97
Exercise price range of options excluded, lower limit	$ 11.46	$ 16.46	$ 20.21
Restricted Stock Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2.6	1.4	0.4

Asset Sales, Impairments and 57

Asset Sales, Impairments and Exploration Expenses - Significant Adjustments with Domestic Operations (Detail) $ in Millions		3 Months Ended			12 Months Ended
		Dec. 31, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)abbl / dMcfe / dWell	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Asset impairment charges		$ 2,300				$ 15	$ 1,100
Impairment of producing properties and costs of acquired unproved reserves	[1]				$ 0	15	772
Unproved leasehold property impairment, amortization and expiration					54	74	402
Results of Operations, Dry Hole Costs					24	21	3
Investment income, impairment of equity method investment and other					(2)	1	(19)
Disposal Group, Including Discontinued Operation, Assets, Current		178			178	930
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal					349	0	0
Gain (Loss) on Disposition of Proved Property				$ 69
Proceeds from sales of assets					1,019	374	49
Loss on Contract Termination					22
Accretion of discount		23			489	$ 383	225
Appalachian Basin
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property impairment, amortization and expiration							317
Accretion of discount					23
Northeast [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal					209
Pennsylvania [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Cost Of Oil And Gas Services					24
Gain (Loss) on Disposition of Proved Property					$ 69
Oil and Gas Property, Deep Rights, Acres Sold During Period | a					46,700
Proceeds from sales of assets					$ 288
Oil and Gas Delivery Commitments and Contracts, Daily Production | Mcfe / d					260
Proved developed wells related to sale | Well					63
Production related to sale | Mcfe / d					50
Post closing adjustment [Member] | Pennsylvania [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets					$ (17)
Impairment of Equity Method Investment in Appalachian Basin [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Investment income, impairment of equity method investment and other							$ 20
Northeast [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal			$ 209
Long-term Purchase Commitment, Amount					390
San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		309			309
Discontinued Operation, Amount of Continuing Cash Flows after Disposal					$ 24
Discontinued Operation, Nature of Activities Having Continuing Involvement after Disposal					13
Significant Acquisitions and Disposals, Description					220
Contract Term					2 years
Disposal Group, Including Discontinued Operation, Assets, Current		40			$ 40
NORTH DAKOTA
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		185			$ 185
Contract Term					2 years
Oil Gathering | bbl / d					11,000
Natural gas gathering | Mcfe / d					6,500
Water gathering | bbl / d					5,000
Deferred Gain on Sale of Property		33			$ 33
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		70			70
Other Current Liabilities [Member] | NORTH DAKOTA
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Deferred Gain on Sale of Property		4			4
Other Noncurrent Liabilities [Member] | NORTH DAKOTA
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Deferred Gain on Sale of Property		29			29
Commitments [Member] | NORTH DAKOTA
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		25			25
Commitments [Member] | Other Current Liabilities [Member] | NORTH DAKOTA
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		3			3
Commitments [Member] | Other Noncurrent Liabilities [Member] | NORTH DAKOTA
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		22			22
Cash [Member] | Northeast [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		209			209
Cash [Member] | San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		$ 285			$ 285
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.

Asset Sales, Impairments and 58

Asset Sales, Impairments and Exploration Expenses - Summary of Impairments (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Impairment Costs [Line Items]
Impairment of producing properties and costs of acquired unproved reserves	[1]	$ 0		$ 15		$ 772
Impairment Equity method investment		$ 0	[2]	0	[3]	20	[4]
Appalachian Basin
Impairment Costs [Line Items]
Impairment Charge						$ 772
Green River Basin
Impairment Costs [Line Items]
Impairment Charge				11
Other Property
Impairment Costs [Line Items]
Impairment Charge				$ 4
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.
[2]	As a result of our impairment assessment in 2015, we recorded the following significant impairment charges, including those reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately $880 million: •$2,308 million impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment.•$26 million impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment.
[3]	As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:•$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.•$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties
[4]	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin, reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

Asset Sales, Impairments and 59

Asset Sales, Impairments and Exploration Expenses - Summary of Exploration Expenses (Detail) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Geologic And Geophysical Costs				$ 7	$ 6	$ 12
Results of Operations, Dry Hole Costs				24	21	3
Unproved leasehold property impairment, amortization and expiration				54	74	402
Exploration (Note 5)				85	101	417
Exploration Abandonment and Impairment Expense	$ 47	$ 22	$ 40
Other Property
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Results of Operations, Dry Hole Costs					16
Unproved leasehold property impairment, amortization and expiration				26	$ 41
Exploration Abandonment and Impairment Expense				$ 24
Appalachian Basin
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property impairment, amortization and expiration						$ 317

Properties and Equipment - Carr

Properties and Equipment - Carried at Cost (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost		$ 8,415	$ 4,802
Accumulated depreciation, depletion and amortization		(1,893)	(1,407)
Properties and equipment-net		6,522	3,395
Proved properties
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1],[2]	5,520	3,852
Unproved Properties
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1],[3]	2,342	349
Gathering, Processing and Other Facilities
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1]	$ 217	102
Gathering, Processing and Other Facilities | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	15 years
Gathering, Processing and Other Facilities | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	25 years
Construction in Progress
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1],[3]	$ 198	368
Other
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1]	$ 138	$ 131
Other | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	3 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	40 years
[1]	Estimated useful lives are presented as of December 31, 2015.
[2]	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
[3]	Unproved properties and construction in progress are not yet subject to depreciation and depletion.

Properties and Equipment - Addi

Properties and Equipment - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Current	$ 2	$ 3
Payments to Acquire Oil and Gas Property	150
Proved Developed Reserves [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Oil and Gas Property	$ 50

Properties and Equipment - Roll

Properties and Equipment - Rollforward Asset Retirement Obligation (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance		$ 77	$ 67
Liabilities incurred during the period		26	9
Liabilities settled during the period		(2)	(1)
Asset Retirement Obligation, Liabilities associated with assets sold		0	0
Estimate revisions		(4)	(3)
Accretion expense	[1]	5	5
Ending Balance		102	77
Amount reflected as current		$ 3	$ 2
[1]	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Accounts Payable and Accrued 63

Accounts Payable and Accrued and Other Current Liabilities - Accounts Payable (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Payables and Accruals [Abstract]
Trade	$ 85	$ 171
Accrual for capital expenditures	65	235
Royalty Payable	71	71
Due to Affiliate	43	118
Other	14	43
Accounts payable	$ 278	$ 638

Accounts Payable and Accrued 64

Accounts Payable and Accrued and Other Current Liabilities - Accrued and Other Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Payables and Accruals [Abstract]
Accrual for Taxes Other than Income Taxes, Current	$ 25	$ 10
Interest Payable, Current	82	53
Accrued Compensation And Related Liabilities Current	61	55
Gathering and transportation	8	7
Gathering and transportation related to exited areas	56	6
Accrued Income Taxes, Current	41	3
Other Accrued Liabilities, Current	29	11
Accrued Liabilities and Other Liabilities	$ 302	$ 145

Debt and Banking Arrangements -

Debt and Banking Arrangements - Debt (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	[1]	$ 3,221	$ 2,281
Debt, Current		1	1
Long-term Debt, Excluding Current Maturities		3,220	2,280
Debt Issuance Costs, Noncurrent, Net		45	28
Long-term Debt and Capital Lease Obligations	[2]	3,189	2,260
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Total debt	[1]	355	400
7.500% Senior Notes due 2020
Debt Instrument [Line Items]
Total debt	[1]	500	0
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Total debt	[1]	1,100	1,100
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Total debt	[1]	500	0
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Total debt	[1]	500	500
Credit Facility Agreement
Debt Instrument [Line Items]
Total debt	[1]	265	280
Other
Debt Instrument [Line Items]
Total debt	[1]	1	1
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Issuance Costs, Noncurrent, Net		$ 31	$ 20
[1]	Interest paid on debt totaled $120 million and $97 million for 2015 and 2014, respectively.
[2]	Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Debt and Banking Arrangements66

Debt and Banking Arrangements - Debt - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, interest expense	$ 120	$ 97
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.25%	5.25%
Debt Instrument Maturity Year	2,017	2,017
7.500% Senior Notes due 2020
Debt Instrument [Line Items]
Debt instrument stated interest rate	7.50%
Debt Instrument Maturity Year	2,020
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt instrument stated interest rate	6.00%	6.00%
Debt Instrument Maturity Year	2,022	2,022
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument stated interest rate	8.25%
Debt Instrument Maturity Year	2,023
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.25%	5.25%
Debt Instrument Maturity Year	2,024	2,024

Debt and Banking Arrangements67

Debt and Banking Arrangements - Additional Information (Detail) $ in Millions		3 Months Ended	12 Months Ended
		Mar. 31, 2016	Dec. 31, 2015USD ($)Contract	Dec. 31, 2014USD ($)	Jun. 30, 2016USD ($)	Feb. 24, 2016USD ($)	Jul. 22, 2015USD ($)	Sep. 30, 2014USD ($)	Nov. 30, 2011USD ($)
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount			$ 45
Debt redemption price as percentage of principal amount			100.00%
Ratio Of Consolidated Indebtedness To Consolidated Capitalization Maximum			60.00%
Ratio of Consolidated EBITDAX To Consolidated Interest Minimum			2.5
Debt Instrument, Description of Variable Rate Basis			0.01875
Line of Credit Facility, Commitment Fee Percentage			0.30%
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate			0.875%
Number of letter of credit agreements | Contract			3
Letters of credit issued			$ 233
Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount						$ 51
Ratio Of Consolidated Indebtedness To Consolidated Capitalization Maximum		60.00%
Ratio of Consolidated EBITDAX To Consolidated Interest Minimum		2.5
Letters of credit issued					$ 164
Unsecured Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 1,750
Debt Instrument, Term			5 years
Weighted average interest rate			2.20%
Unsecured Revolving Credit Facility | Federal Funds Rate
Debt Instrument [Line Items]
Basis spread on variable rate			0.50%
Unsecured Revolving Credit Facility | one-month LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate			1.00%
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt Instrument, Face Amount									$ 400
Long-term Debt	[1]		$ 355	$ 400
5.250% Senior Notes due 2017 | Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount					$ 87
Debt instrument stated interest rate					5.25%
7.500% Senior Notes due 2020
Debt Instrument [Line Items]
Net Proceeds From Debt Offering			494
Long-term Debt	[1]		500	0
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Face Amount									$ 1,100
Long-term Debt	[1]		1,100	1,100
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Net Proceeds From Debt Offering			494
Long-term Debt	[1]		500	0
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Face Amount								$ 500
Net Proceeds From Debt Offering								$ 494
Long-term Debt	[1]		500	500
Credit Facility Agreement
Debt Instrument [Line Items]
Long-term Debt	[1]		$ 265	$ 280
Credit Facility Agreement | Subsequent Event
Debt Instrument [Line Items]
Long-term Debt	[1]					$ 110
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt Instrument Maturity Year			2,017	2,017
Debt instrument stated interest rate			5.25%	5.25%
7.500% Senior Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, Face Amount							$ 500
Debt Instrument Maturity Year			2,020
Debt instrument stated interest rate			7.50%
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument Maturity Year			2,022	2,022
Debt instrument stated interest rate			6.00%	6.00%
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Face Amount							$ 500
Debt Instrument Maturity Year			2,023
Debt instrument stated interest rate			8.25%
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument stated interest rate			5.25%
Change of Control
Debt Instrument [Line Items]
Percentage of repurchase of notes on principal amount of notes			101.00%
Prior to December 31, 2016 [Member]
Debt Instrument [Line Items]
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness			1.10
Limit On Consolidated Indebtedness to Consolidated EBITDAX			4.50
After December 31, 2016 [Member]
Debt Instrument [Line Items]
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness			1.50
Limit On Consolidated Indebtedness to Consolidated EBITDAX			4
[1]	Interest paid on debt totaled $120 million and $97 million for 2015 and 2014, respectively.

Provision (Benefit) for Incom68

Provision (Benefit) for Income Taxes - Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ (4)	$ 8	$ (28)
State	7	1	(5)
Total current	3	9	(33)
Deferred:
Federal	12	134	(496)
State	9	5	(38)
Total Deferred	21	139	(534)
Total provision (benefit)	$ 24	$ 148	$ (567)

Provision (Benefit) for Incom69

Provision (Benefit) for Income Taxes - Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Provision (benefit) at statutory rate	$ 7	$ 141	$ (550)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	4	4	(25)
Effective Income Tax Rate Reconciliation, Tax Contingency, State and Local, Amount	0	9	0
Effective state income tax rate change (net of federal benefit)	7	(9)	(3)
Other	6	3	11
Total provision (benefit)	$ 24	$ 148	$ (567)

Provision (Benefit) for Incom70

Provision (Benefit) for Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Provision For Income Taxes [Line Items]
Proceeds from Income Tax Refunds			$ (8,000,000)		$ (26,000,000)
Deferred Tax Assets, Valuation Allowance	$ 114,000,000		124,000,000	$ 114,000,000
Income tax cash paid				9,000,000
Deferred Other Tax Expense (Benefit)	9,000,000	$ 9,000,000	$ 7,000,000
Operating Loss Carryforwards, Expiration Date			2,020
Operating Loss Carryforwards, Limitations on Use			0.5
Percentage Deferred Tax Assets Operating Loss Carryforwards State That Expire			98.00%
Deferred Tax Assets, Capital Loss Carryforwards			$ 47,000,000
Alternative minimum tax credits	60,000,000		114,000,000	60,000,000
Unrecognized Tax Benefits			$ 0
Uncertain tax position expiration period			12 months
Foreign Tax Authority [Member]
Provision For Income Taxes [Line Items]
Deferred Tax Assets, Valuation Allowance			$ 42,000,000
Domestic Tax Authority [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards			$ 902,000,000
Operating Loss Carryforwards, Expiration Date			2,032
State and Local Jurisdiction [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards	$ 875,000,000		$ 2,000,000,000	$ 875,000,000
RKI [Member]
Provision For Income Taxes [Line Items]
Deferred Tax Liabilities, Gross, Current			$ 693,000,000
Operating Loss Carryforwards, Expiration Date			2,029
Alternative minimum tax credits			$ 50,000,000
RKI [Member] | Domestic Tax Authority [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards			125,000,000
RKI [Member] | State and Local Jurisdiction [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards			$ 7,000,000
Maximum
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards, Limitations on Use			P3Y

Provision (Benefit) for Incom71

Provision (Benefit) for Income Taxes - Significant Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred tax liabilities:
Properties and equipment	$ 988	$ 738
Deferred Tax Liabilities, Derivatives	155	170
Other, net	1	17
Deferred Tax Liabilities, Gross	1,144	925
Deferred tax assets:
Accrued liabilities and other	248	124
Alternative minimum tax credits	114	60
Loss carryovers	441	51
Other, net	0	32
Total deferred tax assets	803	267
Less: valuation allowance	124	114
Total net deferred tax assets	679	153
Deferred Tax Liabilities, Net	$ 465	$ 772

Contingent Liabilities and Co72

Contingent Liabilities and Commitments - Additional Information (Detail) $ in Millions	1 Months Ended	12 Months Ended			84 Months Ended	97 Months Ended
	Sep. 30, 2006Claim	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)	Jul. 31, 2008USD ($)
Loss Contingencies [Line Items]
Accrued Liabilities and Other Liabilities		$ 302	$ 145		$ 302
Other noncurrent liabilities		$ 237	28		237
Processing, treating and transportation costs used in the calculation of federal royalties					114
Service commitment period		8 years
Contractual Obligation		$ 686			686
Total rent expenses		28	26	$ 23
Capacity [Member] | Powder River Basin
Loss Contingencies [Line Items]
Accrued Liabilities and Other Liabilities		29			29
Other noncurrent liabilities		84			84
Capacity [Member] | Piceance Basin [Member]
Loss Contingencies [Line Items]
Contractual Obligation		527			527
Gathering and Treating [Member]
Loss Contingencies [Line Items]
Gathering and Treating Commitments		524			524
Gathering and Treating [Member] | Piceance Basin [Member]
Loss Contingencies [Line Items]
Gathering and Treating Commitments		106			106
Gathering and Treating [Member] | Appalachian Basin
Loss Contingencies [Line Items]
Other noncurrent liabilities		20			20
Accrued Liabilities		23			23
Gathering and Treating Commitments		33			33
Royalty Litigation
Loss Contingencies [Line Items]
Number of claims reserved for court resolution | Claim	2
Loss Contingency, Damages Sought, Value						$ 20
Loss contingencies associated with royalty litigation		17	$ 16		17
Discontinued Operations [Member] | Capacity [Member]
Loss Contingencies [Line Items]
Contractual Obligation		150			150
Discontinued Operations [Member] | Capacity [Member] | Powder River Basin
Loss Contingencies [Line Items]
Contractual Obligation		139			139
Discontinued Operations [Member] | Gathering and Treating [Member]
Loss Contingencies [Line Items]
Contractual Obligation		104			104
Discontinued Operations [Member] | Gathering and Treating [Member] | Powder River Basin
Loss Contingencies [Line Items]
Accrued Liabilities and Other Liabilities		19			19
Other noncurrent liabilities		40			40
Gathering and Treating Commitments		92			92
Assumed by purchasers [Member] | Capacity [Member] | Piceance Basin [Member]
Loss Contingencies [Line Items]
Contractual Obligation		$ 104			$ 104

Contingent Liabilities and Co73

Contingent Liabilities and Commitments - Commitments Under Contracts (Detail) $ in Millions	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 140
2,017	130
2,018	116
2,019	104
2,020	91
Thereafter	105
Total	$ 686

Contingent Liabilities and Co74

Contingent Liabilities and Commitments - Future Minimum Annual Rentals Under Noncancelable Operating Leases (Detail) $ in Millions	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 28
2,017	23
2,018	12
2,019	7
2,020	7
Thereafter	9
Total	$ 86

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer contribution	$ 15	$ 17	$ 16
Postretirement Defined Benefit Plans, Liabilities	$ 9	$ 10
Maximum
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer matching percentage	6.00%
If employee are 40 years or older [Member]
Employee Benefit And Retirement Plans [Line Items]
Non matching employer contribution under defined benefit contribution plan	8.00%
If employees are under age 40 [Member]
Employee Benefit And Retirement Plans [Line Items]
Non matching employer contribution under defined benefit contribution plan	6.00%

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Based Compensation Activity [Line Items]
Common stock share authorized	2,000,000,000	2,000,000,000
Stock option exercisable period	3 years
Stock option term	10 years
Restricted stock units vesting period	3 years
Unrecognized stock based compensation	$ 37,000
Unrecognized stock based compensation, weighted average period of recognition	1 year 9 months
Value of stock option exercised during year	$ 319	$ 13,000	$ 5,000
Cash received from stock option exercises	$ 2,000	14,000	4,000
Unearned grant expected to be recognized in period	3 years
Minimum
Stock Based Compensation Activity [Line Items]
Range of vested shares of original grant amount	0.00%
Maximum
Stock Based Compensation Activity [Line Items]
Range of vested shares of original grant amount	200.00%
Nonvested Restricted Stock Units
Stock Based Compensation Activity [Line Items]
Performance based share granted, percent of nonvested restricted stock units outstanding	25.00%
Administrative expenses
Stock Based Compensation Activity [Line Items]
Stock based compensation expense	$ 35,000	35,000	31,000
Stock Options
Stock Based Compensation Activity [Line Items]
Unrecognized stock based compensation	1,000
Restricted Stock Units
Stock Based Compensation Activity [Line Items]
Unrecognized stock based compensation	$ 36,000
Two Thousand Thirteen Incentive Plan [Member]
Stock Based Compensation Activity [Line Items]
Common stock share authorized	19,600,000
Discount allowed on employee stock purchase plan	15.00%
Employee stock purchase plan purchase price first offering start date	Mar. 1, 2012
Employee stock purchase plan purchase price first offering end date	Jun. 30, 2012
Number of share purchased under stock option plan	191,000
Stock option plan, average purchase price	$ 7.05
Two Thousand Thirteen Incentive Plan [Member] | Maximum
Stock Based Compensation Activity [Line Items]
Number of share available for purchase under stock option plan	1,000,000
Domestic | Administrative expenses
Stock Based Compensation Activity [Line Items]
Stock based compensation expense	$ 4,000	$ 5,000	$ 4,000

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Detail) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Option Outstanding
Beginning Balance (in shares) | shares	3.1	[1]
Granted (in shares) | shares	0
Exercised (in shares) | shares	(0.2)
Forfeited (in shares) | shares	0
Ending Balance (in shares) | shares	2.9
Exercisable at end of period (in shares) | shares	2.7
Weighted Average Exercise price
Beginning Balance (in dollars per share) | $ / shares	$ 14.80
Granted (in dollars per share) | $ / shares	0
Exercised (in dollars per share) | $ / shares	10.33
Forfeited (in dollars per share) | $ / shares	0
Ending Balance (in dollars per share) | $ / shares	15.07
Exercisable at end of period (in dollars per share) | $ / shares	$ 14.75
Aggregate Intrinsic value
Beginning Balance | $	$ 2
Ending Balance | $	0
Exercisable at end of period | $	$ 0
[1]	Includes approximately 137 thousand shares held by Williams' employees at a weighted average price of $10.64 per share at December 31, 2014.

Stock-Based Compensation - Su78

Stock-Based Compensation - Summary of Stock Option Activity and Related Information - Additional Information (Detail) - Williams Employees shares in Thousands	12 Months Ended
	Dec. 31, 2014$ / sharesshares
Schedule Of Stock Options [Line Items]
Share held by Williams' employees | shares	137
Weighted average price of share held by Williams' employee | $ / shares	$ 10.64

Stock-Based Compensation - Su79

Stock-Based Compensation - Summary of Stock Option Outstanding and Exercisable (Detail) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$ 11.46	$ 16.46		$ 20.21
Range of Exercise Prices, Upper Limit	$ 21.81	$ 21.81		$ 20.97
Options outstanding (in shares)	2.9	3.1	[1]
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$ 15.07	$ 14.80
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	4 years 5 months
Options exercisable (in shares)	2.7
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$ 14.75
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	4 years
$ 6.02 to $12.32
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$ 6.02
Range of Exercise Prices, Upper Limit	$ 12.32
Options outstanding (in shares)	0.9
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$ 9.79
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	3 years
Options exercisable (in shares)	0.9
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$ 9.79
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	3 years
$14.41 to $17.47
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$ 14.41
Range of Exercise Prices, Upper Limit	$ 17.47
Options outstanding (in shares)	1.2
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$ 15.97
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	5 years
Options exercisable (in shares)	1.1
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$ 15.92
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	4 years 7 months
$18.16 to $19.95
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$ 18.16
Range of Exercise Prices, Upper Limit	$ 19.95
Options outstanding (in shares)	0.3
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$ 18.21
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	6 years 5 months
Options exercisable (in shares)	0.3
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$ 18.21
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	6 years 5 months
$20.21 to $21.81
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$ 20.21
Range of Exercise Prices, Upper Limit	$ 21.81
Options outstanding (in shares)	0.5
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$ 20.62
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	4 years
Options exercisable (in shares)	0.4
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$ 20.37
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	2 years 9 months
[1]	Includes approximately 137 thousand shares held by Williams' employees at a weighted average price of $10.64 per share at December 31, 2014.

Stock-Based Compensation - Esti

Stock-Based Compensation - Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted-average or grant date fair value of options granted	$ 0	$ 18.94	$ 6.04
Dividend yield	0.00%	0.00%	0.00%
Volatility	0.00%	43.00%	42.80%
Risk-free interest rate	0.00%	1.85%	1.06%
Expected life	0 years	5 years 11 months	6 years

Stock-Based Compensation - Su81

Stock-Based Compensation - Summary of Nonvested Restricted Stock Unit Activity and Related Information (Detail) shares in Millions	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Nonvested Shares
Beginning Balance | shares	5.1
Granted | shares	3.1
Forfeited | shares	(0.1)
Vested | shares	(2.2)
Ending balance | shares	5.9
Weighted-Average Fair Value
Nonvested, Beginning Balance | $ / shares	$ 17.58	[1]
Granted | $ / shares	10.24	[1]
Forfeited | $ / shares	14.89	[1]
Vested | $ / shares	18.34	[1]
Nonvested, Ending Balance | $ / shares	$ 13.34	[1]
[1]	Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Stock-Based Compensation - Othe

Stock-Based Compensation - Other Restricted Stock Unit (Detail) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]
Weighted-average grant date fair value of restricted stock units granted during the year, per share	[1]	$ 10.24
Restricted Stock Units
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]
Weighted-average grant date fair value of restricted stock units granted during the year, per share		$ 10.24	$ 18.37	$ 14.97
Total fair value of restricted stock units vested during the year (millions)		$ 40	$ 33	$ 18
[1]	Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Stockholders' Equity - Addition

Stockholders' Equity - Additional Information (Detail) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 22, 2015
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Preferred stock, shares issued		7,000,000	7,000,000	0
Preferred stock, par value		$ 0.01	$ 0.01	$ 0.01
Proceeds from common stock			$ 295,000,000	$ 16,000,000	$ 6,000,000
Business Acquisition, Share Price						$ 10.10
Proceeds from preferred stock			339,000,000	$ 0	$ 0
Preferred Stock, Liquidation Preference, Value		$ 50	50
Fair value of WPX common stock issued			$ 296,000,000
Preferred Stock, Dividends Per Share, Declared		$ 0.85938
RKI [Member]
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Preferred stock, shares issued		7,000,000	7,000,000
Preferred stock, par value		$ 0.01	$ 0.01
Common Stock, Discount on Shares		$ 10,500,000	$ 10,500,000
Preferred Stock, Discount on Shares		10,500,000	$ 10,500,000
Preferred Stock, Dividend Rate, Percentage			6.25%
Preferred Stock, Liquidation Preference, Value		$ 50	$ 50
Noncash or Part Noncash Acquisition, Noncash Financial or Equity Instrument Consideration, Shares Issued			40,000,000
Preferred Stock [Member] | RKI [Member]
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Proceeds from preferred stock			$ 350,000,000
Common Stock | RKI [Member]
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Stock Issued During Period, Shares, New Issues			30,000,000
Proceeds from common stock			$ 303,000,000
Minimum
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Convertible Preferred Stock, Shares Issued upon Conversion		4.1254	4.1254
Maximum
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Convertible Preferred Stock, Shares Issued upon Conversion		4.9504	4.9504
Subsequent Event
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Preferred Stock, Dividends Per Share, Declared	$ 0.78125

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	[1]	$ 2,495	$ 2,218
Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		359	522
Energy derivative liabilities		15	42
Level 1 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		0	14
Energy derivative liabilities		0	32
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	[1]	2,495	2,218
Level 2 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		359	503
Energy derivative liabilities		15	10
Level 3 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		0	5
Energy derivative liabilities		$ 0	$ 0
[1]	The carrying value of total debt, excluding capital leases and debt issuance costs, was $3,220 million and $2,280 million as of December 31, 2015 and 2014, respectively.

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities	$ 3,220	$ 2,280

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Fair Value Measurements Using Significant Unobservable Inputs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 5	$ 0	$ (1)
Realized and unrealized gains (losses) included in income (loss) from continuing operations	(1)	5	(2)
Realized and unrealized gains (losses) included in other comprehensive income (loss)	0	0	0
Purchases, issuances, and settlements	(4)	0	3
Transfers out of Level 3	0	0	0
Ending balance	0	5	0
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$ 0	$ 5	$ (1)

Fair Value Measurements - Impai

Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy - Additional Information (Detail) Mcfe in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)$ / Mcfe		Dec. 31, 2014USD ($)Mcfe$ / Mcfe		Dec. 31, 2013USD ($)Mcfe$ / Mcfe
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of producing properties and costs of acquired unproved reserves		$ 880		$ 11		$ 365
Impairment of producing properties and costs of acquired unproved reserves	[1]	$ 0		$ 15		$ 772
Weighted average natural gas price | $ / Mcfe		2.32		4.34		3.63
Unproved leasehold property impairment, amortization and expiration		$ 54		$ 74		$ 402
Impairment of producing properties and costs of acquired unproved reserves (Note 4)		2,308	[2]	20	[3]	1,055	[4]
Unproved Leasehold Property Impairment		26	[2]	0	[3]	317	[4]
Equity method investment (Note 4)		0	[2]	0	[3]	20	[4]
Asset Impairment Charges Including Discontinued Operations		2,334		20		1,392
Piceance Basin [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of producing properties and costs of acquired unproved reserves		2,308
Unproved leasehold property impairment, amortization and expiration		$ 26
Green River Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge				$ 11
Green River Basin | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Weighted average natural gas price | $ / Mcfe				4.77
Green River Basin | Producing Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax				9.00%
Green River Basin | Undeveloped Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax				11.00%
Green River Basin | Minimum | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved reserve quantities of gas equivalent | Mcfe				23
Appalachian Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge Including Equity Method Investment						792
Impairment Charge						772
Unproved leasehold property impairment, amortization and expiration						$ 317
Appalachian Basin | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Weighted average natural gas price | $ / Mcfe						3.60
Percentage of discount rate after-tax						11.00%
Appalachian Basin | Minimum | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved reserve quantities of gas equivalent | Mcfe						299
Powder River Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge						$ 107
Impairment of producing properties and costs of acquired unproved reserves						$ 85
Powder River Basin | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Weighted average natural gas price | $ / Mcfe						3.53
Percentage of discount rate after-tax						11.00%
Powder River Basin | Probable Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax						15.00%
Powder River Basin | Possible Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax						18.00%
Powder River Basin | Minimum | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved reserve quantities of gas equivalent | Mcfe						294
Piceance
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of producing properties and costs of acquired unproved reserves						$ 88
Piceance | Probable Reserves
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax						13.00%
Piceance | Possible Reserves
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax						15.00%
Other Member
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of producing properties and costs of acquired unproved reserves				$ 9
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.
[2]	As a result of our impairment assessment in 2015, we recorded the following significant impairment charges, including those reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately $880 million: •$2,308 million impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment.•$26 million impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment.
[3]	As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:•$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.•$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties
[4]	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin, reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

Derivatives and Concentration88

Derivatives and Concentration of Credit Risk - Derivative Volumes 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 (Detail) BTU / d in Thousands	12 Months Ended
	Dec. 31, 2015bbl / dBTU / d$ / bbl$ / MMBtu
Short Position [Member] | 2015 [Member] | Gas Transportation and Storage [Member] | Natural Gas | Multiple Locations [Member]
Derivative [Line Items]
Notional Volume	(17)
Price Risk Derivative [Member] | 2016 [Member] | Derivatives related to production | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(27,549)	[1],[2]
Underlying, Derivative | $ / bbl	61.70	[1],[3]
Price Risk Derivative [Member] | 2016 [Member] | Derivatives related to production | Natural Gas | Henry Hub
Derivative [Line Items]
Notional Volume	(213)	[1],[2]
Underlying, Derivative | $ / MMBtu	3.79	[1],[3]
Price Risk Derivative [Member] | 2017 [Member] | Derivatives related to production | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(9,304)	[1],[2]
Underlying, Derivative | $ / bbl	61.66	[1],[3]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Crude Oil [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)	[1],[2]
Underlying, Derivative | $ / bbl	(0.45)	[1],[3]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas | NGPL [Member]
Derivative [Line Items]
Notional Volume	(5)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.23)	[1],[3]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas | Permian [Member]
Derivative [Line Items]
Notional Volume	(33)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.17)	[1],[3]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas | Rockies [Member]
Derivative [Line Items]
Notional Volume	(230)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.21)	[1],[3]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas | San Juan [Member]
Derivative [Line Items]
Notional Volume	(100)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.18)	[1],[3]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas | Southern California Gas [Member]
Derivative [Line Items]
Notional Volume	(45)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.01)	[1],[3]
Basis Swap [Member] | 2017 [Member] | Derivatives related to production | Natural Gas | Rockies [Member]
Derivative [Line Items]
Notional Volume	(50)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.21)	[1],[3]
Basis Swap [Member] | 2017 [Member] | Derivatives related to production | Natural Gas | San Juan [Member]
Derivative [Line Items]
Notional Volume	(33)	[1],[2]
Underlying, Derivative | $ / MMBtu	(0.16)	[1],[3]
Basis Swap [Member] | 2017 [Member] | Derivatives related to production | Natural Gas | Southern California [Member]
Derivative [Line Items]
Notional Volume	(10)	[1],[2]
Underlying, Derivative | $ / MMBtu	0	[1],[3]
Call Option [Member] | 2016 [Member] | Derivatives related to production | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(1,243)	[1],[2]
Underlying, Derivative | $ / bbl	55.75	[1],[3]
Call Option [Member] | 2018 [Member] | Derivatives related to production | Natural Gas | Henry Hub
Derivative [Line Items]
Notional Volume	(16)	[1],[2]
Underlying, Derivative | $ / MMBtu	4.75	[1],[3]
Call Option [Member] | 2017 [Member] | Derivatives related to production | Natural Gas | Henry Hub
Derivative [Line Items]
Notional Volume	(16)	[1],[2]
Underlying, Derivative | $ / MMBtu	4.50	[1],[3]
Swaption [Member] | 2016 [Member] | Derivatives related to production | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(1,257)	[1],[2]
Underlying, Derivative | $ / bbl	57.15	[1],[3]
Swaption [Member] | 2017 [Member] | Derivatives related to production | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(1,500)	[1],[2]
Underlying, Derivative | $ / bbl	59	[1],[3]
Swaption [Member] | 2017 [Member] | Derivatives related to production | Natural Gas | Henry Hub
Derivative [Line Items]
Notional Volume	(65)	[1],[2]
Underlying, Derivative | $ / MMBtu	4.19	[1],[3]
[1]	(a)Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, calls, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us.
[2]	(b)Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day
[3]	(c)The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.

Derivatives and Concentration89

Derivatives and Concentration of Credit Risk - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Collateral posted to derivative		$ 26
Initial margin	$ 0	9
Maintenance margin		17
Net derivative liability position	1	$ 17
Additional collateral posted	$ 1
Unearned Non Cash Stock Based Compensation Expected To Recognize As Expense Over Period	3 years
Net credit exposure percentage	99.00%
Collateral support	$ 45
Domestic Segment | BP Energy
Derivative [Line Items]
Percentage of consolidated revenue	3.00%	15.00%	7.00%
Domestic Segment | Western Refining [Member]
Derivative [Line Items]
Percentage of consolidated revenue	11.00%	4.00%	2.00%
Maximum
Derivative [Line Items]
Reduction in derivative liabilities	$ 1	$ 1

Derivatives and Concentration90

Derivatives and Concentration of Credit Risk - Fair Value of Energy Commodity Derivatives (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	$ 359	$ 522
Total derivatives, Liabilities	15	42
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	359	522
Total derivatives, Liabilities	15	42
Not Designated as Hedging Instrument | Derivatives related to production
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	359	503
Total derivatives, Liabilities	15	10
Not Designated as Hedging Instrument | Derivatives Related to Physical Marketing Agreements
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	0	19
Total derivatives, Liabilities	$ 0	$ 32

Derivatives and Concentration91

Derivatives and Concentration of Credit Risk - Offsetting of Derivative Assets and Liabilities (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Gross Amount Presented on Balance Sheet		$ 359	$ 522
Netting Adjustment	[1]	(14)	(25)
Cash Collateral Posted(Received)		0	0
Net Amount		345	497
Derivative Liability [Abstract]
Gross Amount Presented on Balance Sheet		(15)	(42)
Netting adjustment	[1]	14	25
Cash Collateral Posted(Received)		0	17
Net Amount		$ (1)	$ 0
[1]	With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Derivatives and Concentration92

Derivatives and Concentration of Credit Risk - Concentration of Receivables, Net of Allowances, by Product or Service (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Receivables [Line Items]
Account receivables	$ 300	$ 437
Sale of natural gas and related products and services
Receivables [Line Items]
Account receivables	171	339
Joint interest owners
Receivables [Line Items]
Account receivables	90	88
Other
Receivables [Line Items]
Account receivables	$ 39	$ 10

Derivatives and Concentration93

Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts (Detail) $ in Millions	Dec. 31, 2015USD ($)
Credit Exposure From Derivatives [Line Items]
Total gross credit exposure from derivative contracts before credit reserve	$ 360
Gross credit reserves	(1)
Maximum Potential Future Exposure On Credit Risk Derivatives Gross	359
Total net credit exposure from derivative contracts before credit reserve	346
Net credit reserves	(1)
Net credit exposure from derivatives	$ 345

Derivatives and Concentration94

Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015
Standard & Poor's
Credit Exposure From Derivatives [Line Items]
Counterparties credit rating in investment grade	BBB-
Moody's Investors Service
Credit Exposure From Derivatives [Line Items]
Counterparties credit rating in investment grade	Baa3

Derivatives and Concentration95

Derivatives and Concentration of Credit Risk Derivatives and concentration of credit risk Gain (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
DerivativeGainLoss [Line Items]
Net gain (loss) on derivatives not designated as hedges (Note 15)		$ 418	$ 434	$ (124)
Energy Related Derivative
DerivativeGainLoss [Line Items]
Payment Made for Settlement of Derivatives			4	11
Payment Received for Settlement of Derivatives		650
Net gain (loss) on derivatives not designated as hedges (Note 15)	[1]	438	515	(57)
Derivatives Related to Physical Marketing Agreements
DerivativeGainLoss [Line Items]
Payment Made for Settlement of Derivatives		33	120	6
Net gain (loss) on derivatives not designated as hedges (Note 15)	[2]	$ (20)	$ (81)	$ (67)
[1]	(a)Includes settlements totaling $650 million for the year ended December 31, 2015, and payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively
[2]	(b)Includes payments totaling $33 million, $120 million and $6 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Subsequent event (Details)

Subsequent event (Details)		3 Months Ended		12 Months Ended
		Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Feb. 24, 2016USD ($)	Dec. 31, 2014USD ($)
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount				$ 45,000,000
Ratio Of Consolidated Indebtedness To Consolidated Capitalization Maximum				60.00%
Ratio of Consolidated EBITDAX To Consolidated Interest Minimum				2.5
Letters of credit issued				$ 233,000,000
Subsequent Event
Subsequent Event [Line Items]
Payments for (Proceeds from) other agreements		$ 239,000,000
Debt Instrument, Repurchased Face Amount					$ 51,000,000
Ratio Of Consolidated Indebtedness To Consolidated Capitalization Maximum			60.00%
Ratio of Consolidated EBITDAX To Consolidated Interest Minimum			2.5
Letters of credit issued		164,000,000
5.250% Senior Notes due 2017
Subsequent Event [Line Items]
Long-term Debt	[1]			355,000,000		$ 400,000,000
5.250% Senior Notes due 2017 | Subsequent Event
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount		$ 87,000,000
Debt instrument stated interest rate		5.25%
Credit Facility Agreement
Subsequent Event [Line Items]
Long-term Debt	[1]			$ 265,000,000		$ 280,000,000
Credit Facility Agreement | Subsequent Event
Subsequent Event [Line Items]
Long-term Debt	[1]				$ 110,000,000
Revolving Credit Facility [Member] | Subsequent Event
Subsequent Event [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 1,200,000,000
Line of Credit Facility, Maximum Borrowing Capacity during Collateral Period			$ 1,025,000,000
Collateral Trigger Period [Member] | Subsequent Event
Subsequent Event [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX			3
Minimum Current Ratio			1
After December 31, 2017 [Member] | Collateral Trigger Period [Member] | Subsequent Event
Subsequent Event [Line Items]
Maximum Limit On Consolidated Secure Indebtedness to Consolidated EBITDAX			3
Prior to December 31, 2016 [Member] | Subsequent Event
Subsequent Event [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX			4.50
Before December 31, 2017 [Member] | Collateral Trigger Period [Member] | Subsequent Event
Subsequent Event [Line Items]
Maximum Limit On Consolidated Secure Indebtedness to Consolidated EBITDAX			3.25
After December 31, 2016 [Member] | Subsequent Event
Subsequent Event [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX			4
Piceance Basin Transportation obligation [Member] | Subsequent Event
Subsequent Event [Line Items]
Other Commitment		$ 400,000,000
[1]	Interest paid on debt totaled $120 million and $97 million for 2015 and 2014, respectively.

Quarterly Financial Data Quarte

Quarterly Financial Data Quarterly Financial Data-Summarized Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Line Items]
Revenues	$ 385	$ 407	$ 154	$ 420	$ 918	$ 538	$ 465	$ 602	$ 1,366	$ 2,523	$ 1,505
Operating costs and expenses	294	300	251	300	399	362	439	545
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	(9)	(70)	23	52	269	52	(37)	(28)	(4)	256	(1,005)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	(1,525)	(160)	(53)	16	(50)	14	(96)	47	(1,722)	(85)	(186)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,534)	(230)	(30)	68	219	66	(133)	19	(1,726)	171	(1,191)
Income (Loss) from Continuing Operations Attributable to WPX	(14)	(74)	23	52	269	52	(37)	(28)	(13)	256	(993)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX	(1,525)	(160)	(53)	15	(50)	10	(98)	46	(1,723)	(92)	(192)
Net Income (Loss) Attributable to Parent	$ (1,539)	$ (234)	$ (30)	$ 67	$ 219	$ 62	$ (135)	$ 18	$ (1,727)	$ 164	$ (1,185)
Income (Loss) from Continuing Operations, Per Basic Share	$ (0.06)	$ (0.29)	$ 0.11	$ 0.26	$ 1.32	$ 0.26	$ (0.18)	$ (0.14)	$ (0.06)	$ 1.26	$ (4.95)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	(5.53)	(0.64)	(0.25)	0.07	(0.24)	0.04	(0.48)	0.23	(7.36)	(0.45)	(0.96)
Earnings Per Share, Basic	(5.59)	(0.93)	(0.14)	0.33	1.08	0.30	(0.66)	0.09	(7.42)	0.81	(5.91)
Income (Loss) from Continuing Operations, Per Diluted Share	(0.06)	(0.29)	0.11	0.25	1.30	0.26	(0.18)	(0.14)	(0.06)	1.24	(4.95)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	(5.53)	(0.64)	(0.25)	0.07	(0.24)	0.04	(0.48)	0.23	(7.36)	(0.44)	(0.96)
Earnings Per Share, Diluted	$ (5.59)	$ (0.93)	$ (0.14)	$ 0.32	$ 1.06	$ 0.30	$ (0.66)	$ 0.09	$ (7.42)	$ 0.80	$ (5.91)

Quarterly Financial Data - Addi

Quarterly Financial Data - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Line Items]
Gain (Loss) on Disposition of Assets for Financial Service Operations												$ 36
Gain (Loss) on Disposition of Proved Property				$ 69
Loss on Contract Termination										$ 22
Business Combination, Acquisition Related Costs										23	$ 0	0
Asset impairment charges	$ 2,300										15	1,100
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal										349	0	0
Accretion of discount	23									489	383	225
Impairment Of Costs Of Producing Properties, Acquired Unproved Reserves, leasehold, and equity method investment					$ 87
Proceeds from Sale of Other Assets					18
Exploration Abandonment and Impairment Expense		$ 47				$ 22	$ 40
GasManagementExpenseDisposalGroup							11			1	8	4
Deferred Other Tax Expense (Benefit)					$ 9			$ 9		7
Piceance Basin [Member]
Quarterly Financial Data [Line Items]
Accretion of discount										23
Powder River Basin
Quarterly Financial Data [Line Items]
Impairment of producing properties and costs of acquired unproved reserves												85
Domestic
Quarterly Financial Data [Line Items]
Gain (Loss) on Disposition of Assets for Financial Service Operations												36
Disposal group contract obligation expense										190
GasManagementExpenseDisposalGroup										1	8	4
International
Quarterly Financial Data [Line Items]
Gain (Loss) on Disposition of Assets for Financial Service Operations				$ 41						41		0
GasManagementExpenseDisposalGroup										0	$ 0	0
Northeast [Member]
Quarterly Financial Data [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal			$ 209
Powder River Basin
Quarterly Financial Data [Line Items]
Disposal group contract obligation expense		187							$ 187	190
NORTH DAKOTA
Quarterly Financial Data [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ 70									70
Piceance Basin [Member]
Quarterly Financial Data [Line Items]
Asset impairment charges										2,334
Loss On Sale Of Working Interests						$ 1	$ 195
Impairment of producing properties and costs of acquired unproved reserves												$ 88
RKI [Member]
Quarterly Financial Data [Line Items]
Business Combination, Acquisition Related Costs		$ 104								$ 23

Supplemental Oil and Gas Disc99

Supplemental Oil and Gas Disclosures - Additional Information (Detail) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)MMBoe	Dec. 31, 2015USD ($)MMBoe$ / Mcfe$ / bbl	Dec. 31, 2014USD ($)MMBoe$ / Mcfe$ / bbl	Dec. 31, 2013USD ($)MMBoe$ / Mcfe$ / bbl	Dec. 31, 2012USD ($)MMBoe
Supplementary Information [Line Items]
Equipment and facilities in support of oil and gas production excluded from capitalization		$ 202	$ 109
Equity earnings from the international equity method investee			1	$ 21
Loss on Contract Termination		22
Accretion of discount	$ 23	$ 489	$ 383	$ 225
Weighted average natural gas price | $ / Mcfe		2.32	4.34	3.63
Weighted average oil per barrel price | $ / bbl		43.84	83.62	92.16
Discount rate		10.00%
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	$ 1,284	$ 1,284	$ 3,883	$ 2,964	$ 1,949
Powder River Basin
Supplementary Information [Line Items]
Proved Developed Reserves Production Percentage Maximum			5.00%
International
Supplementary Information [Line Items]
Proved Developed Reserves (Energy) | MMBoe			35
Proved Developed Reserves Production Percentage Maximum			5.00%
Appalachian Basin
Supplementary Information [Line Items]
Proved Developed Reserves Production Percentage Maximum			5.00%
Accretion of discount		$ 23
Piceance Basin [Member]
Supplementary Information [Line Items]
Proved Developed Reserves (Energy) | MMBoe	228	228
Proved Developed Reserves Production Percentage Maximum		52.00%
Accretion of discount		$ 23
Proved undeveloped reserves | MMBoe	75	75
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	$ 270	$ 270
Oil and Condensate Sales | Permian [Member]
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy) | MMBoe	53	53
Oil and Condensate Sales | San Juan [Member]
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy) | MMBoe			5
All products
Supplementary Information [Line Items]
Proved Developed Reserves (Energy) | MMBoe	402.2	402.2	452.3	463
Proved Developed and Undeveloped Reserve, Net (Energy) | MMBoe	583	583	726.6	793.6	748.4
Proved undeveloped reserves | MMBoe	180.8	180.8	274.3	330.6
Piceance Basin [Member]
Supplementary Information [Line Items]
Proved Developed Reserves Production Percentage Maximum		52.00%
Domestic
Supplementary Information [Line Items]
Costs Incurred, Development Costs		$ 657	$ 1,376	$ 939
Domestic | Piceance Basin [Member]
Supplementary Information [Line Items]
Costs Incurred, Development Costs		$ 106	$ 430	$ 284

Supplemental Oil and Gas Dis100

Supplemental Oil and Gas Disclosures - Capitalization Cost (Detail) - Domestic - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Capitalized Expedition Cost Related To Specific Assets [Line Items]
Proved Properties	$ 5,703	$ 4,192
Unproved properties	2,342	349
Total property costs	8,045	4,541
Accumulated depreciation, depletion and amortization and valuation provisions	(1,763)	(1,292)
Net capitalized costs	$ 6,282	$ 3,249

Supplemental Oil and Gas Dis101

Supplemental Oil and Gas Disclosures - Cost Incurred (Detail) - Domestic - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	$ 3,208	$ 294	$ 57
Exploration	84	92	104
Development	657	1,376	939
Total costs incurred	$ 3,949	$ 1,762	$ 1,100

Supplemental Oil and Gas Dis102

Supplemental Oil and Gas Disclosures - Results of Operation (Detail) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accretion of discount		$ 23	$ 489	$ 383	$ 225
Impairment of certain natural gas properties	[1]		0	15	772
Net (gain) loss on sales of assets (Note 5)			(349)	0	0
Business Combination, Acquisition Related Costs			23	0	0
Piceance Basin [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accretion of discount			23
Impairment of certain natural gas properties			2,308
Exploration and production [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			1,100	1,494	690
Net gain (loss) on derivatives not designated as hedges			438	515	(57)
Other revenues			7	8	3
Lease and facility operating			145	143	109
Gathering, processing and transportation			64	71	73
Taxes other than income			62	88	68
Exploration			85	101	417
Depreciation, depletion and amortization			528	363	354
Impairment of certain natural gas properties			0
Impairment Of Proved Oil And Gas Properties				15	772
Impairment of costs of acquired unproved reserves			0	0	0
Net (gain) loss on sales of assets (Note 5)			(349)	0	0
General and administrative			203	217	211
Business Combination, Acquisition Related Costs			23	0	0
Other (income) expense			63	13	12
Total costs			824	1,011	2,016
Results of operations			276	483	(1,326)
Provision (benefit) for income taxes			101	176	(484)
Exploration and production net income (loss)			175	307	(842)
Exploration and production [Member] | Natural Gas
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			138	282	259
Exploration and production [Member] | Oil and Condensate Sales
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			494	669	475
Exploration and production [Member] | Natural Gas Liquids
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			$ 23	$ 20	$ 10
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.

Supplemental Oil and Gas Dis103

Supplemental Oil and Gas Disclosures - Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2015MMBoeMMcfMMBbls	Dec. 31, 2014MMBoeMMcfMMBbls	Dec. 31, 2013MMBoeMMcfMMBbls
Supplementary Information [Line Items]
Revisions | MMBoe	209
Natural Gas
Supplementary Information [Line Items]
Proved reserves beginning balance | MMcf	3,149,600	3,629,800	3,369,100
Revisions | MMcf	(624,600)	(198,300)	308,300
Purchases | MMcf	205,600	6,000
Divestitures | MMcf	380,300	(314,600)	(200)
Extensions and discoveries | MMcf	116,900	362,100	312,000
Production | MMcf	(277,000)	(335,400)	(359,400)
Proved reserves ending balance | MMcf	2,190,200	3,149,600	3,629,800
Proved developed reserves | MMcf	1,618,200	2,090,000	2,265,200
Proved undeveloped reserves | MMcf	572,000	1,059,600	1,364,600
Oil and Condensate Sales
Supplementary Information [Line Items]
Proved reserves beginning balance	130.8	102.9	76.5
Revisions	(31.9)	(7.7)	3.5
Purchases	39.8	4.2
Divestitures	0	(1.8)	0
Extensions and discoveries	17.1	42.4	28.8
Production	(13.1)	(9.2)	(5.9)
Proved reserves ending balance	142.7	130.8	102.9
Proved developed reserves	83	60	36.8
Proved undeveloped reserves	59.7	70.8	66.1
Natural Gas Liquids
Supplementary Information [Line Items]
Proved reserves beginning balance	70.8	85.7	110.4
Revisions	(14)	(13.4)	(25.4)
Purchases	20.7	0.8
Divestitures	0	(8.5)	0
Extensions and discoveries	5.1	12.5	8.1
Production	(7.3)	(6.3)	(7.4)
Proved reserves ending balance	75.3	70.8	85.7
Proved developed reserves	49.5	43.9	48.6
Proved undeveloped reserves	25.8	26.9	37.1
All products
Supplementary Information [Line Items]
Proved reserves beginning balance | MMBoe	726.6	793.6	748.4
Revisions | MMBoe	(150)	(54.1)	29.5
Purchases | MMBoe	94.7	6
Divestitures | MMBoe	(63.4)	(62.7)	0
Extensions and discoveries | MMBoe	41.6	115.2	88.9
Production | MMBoe	66.5	71.4	73.2
Proved Developed Reserves (Energy) | MMBoe	402.2	452.3	463
Proved undeveloped reserves | MMBoe	180.8	274.3	330.6

Supplemental Oil and Gas Dis104

Supplemental Oil and Gas Disclosures - Proved Reserves - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015MMBoe	Dec. 31, 2014MMBoeMcfe	Dec. 31, 2013MMBoe
Reserve Quantities [Line Items]
Computation Of Oil Natural Gas And Ngl Reserves	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit
Revisions	209
All products
Reserve Quantities [Line Items]
Revisions	(150)	(54.1)	29.5
Purchases	94.7	6
Divestitures	(63.4)	(62.7)	0
Extensions and discoveries	41.6	115.2	88.9
Powder River Basin
Reserve Quantities [Line Items]
Divestitures	28
Piceance Basin [Member]
Reserve Quantities [Line Items]
Divestitures	35
Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Revisions	42	16	22
Purchases	53.4
Extensions and discoveries	20.9	31	21
Proved Undeveloped Reserves [Member] [Member]
Reserve Quantities [Line Items]
Revisions	108	70	7
Purchases	41.3
Extensions and discoveries	20.7	84	68
Other Property
Reserve Quantities [Line Items]
Revisions	59

Supplemental Oil and Gas Dis105

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 12,391	$ 26,444
Future production costs	7,757	12,641
Future development costs	1,761	3,426
Future income tax provisions	0	2,519
Future net cash flows	2,873	7,858
Less 10 percent annual discount for estimated timing of cash flows	(1,589)	(3,975)
Standardized measure of discounted future net cash inflows	1,284	$ 3,883	$ 2,964	$ 1,949
Piceance Basin [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure of discounted future net cash inflows	$ 270

Supplemental Oil and Gas Dis106

Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows beginning of period		$ 3,883	$ 2,964	$ 1,949
Sales of oil and gas produced, net of operating costs		(541)	(1,324)	(1,040)
Net change in prices and production costs		(5,231)	303	1,198
Extensions, discoveries and improved recovery, less estimated future costs		254	1,761	1,282
Development costs incurred during year		276	592	414
Changes in estimated future development costs		1,213	143	(736)
Purchase of reserves in place, less estimated future costs		657	147	0
Sale of reserves in place, loss estimated future costs		(397)	(391)	(3)
Revisions of previous quantity estimates		(374)	(536)	239
Accretion of discount	$ 23	489	383	225
Net change in income taxes		1,073	(142)	(540)
Other		(18)	(17)	(24)
Net changes		(2,599)	919	1,015
Standardized measure of discounted future net cash flows end of period	1,284	1,284	$ 3,883	$ 2,964
Piceance Basin [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Accretion of discount		23
Standardized measure of discounted future net cash flows end of period	$ 270	$ 270

Schedule II - Valuation And 107

Schedule II - Valuation And Qualifying Accounts (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for doubtful accounts - accounts and notes receivable
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	[1]	$ 6	$ 7	$ 11
Valuation Allowances and Reserves, Additions for Charges to Cost and Expense	[1]	5	0	(3)
Valuation Allowances and Reserves, Additions for Charges to Other Accounts	[1]	0	0	0
Valuation Allowances and Reserves, Deductions	[1]	(5)	(1)	(1)
Ending Balance	[1]	6	6	7
Deferred tax asset valuation allowance
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	[2]	118	102	19
Valuation Allowances and Reserves, Additions for Charges to Cost and Expense	[2]	3	(1)	80
Valuation Allowances and Reserves, Additions for Charges to Other Accounts	[2]	3	17	3
Valuation Allowances and Reserves, Deductions	[2]	0	0	0
Ending Balance	[2]	124	118	102
Price-risk management credit reserves-assets
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	[1],[3]	1	0
Valuation Allowances and Reserves, Additions for Charges to Cost and Expense	[1],[3]	0	0
Valuation Allowances and Reserves, Additions for Charges to Other Accounts	[1],[3]	0	1
Valuation Allowances and Reserves, Deductions	[1],[3]	0	0
Ending Balance	[1],[3]	$ 1	$ 1	$ 0
[1]	Deducted from related assets.
[2]	Deducted from related assets, with a portion included in assets held for sale.
[3]	Included in revenues.