WPX Energy (WPX) 10-K 26 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 24, 2015	Jun. 30, 2014
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	WPX
Entity Registrant Name	WPX ENERGY, INC.
Entity Central Index Key	1518832
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		203,877,415
Entity Public Float			$4,832,711,197

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$41		$47
Accounts receivable, net of allowance of $6 million and $7 million as of December 31, 2014 and 2013, respectively	459		518
Deferred income taxes	0		49
Derivative assets	498		50
Inventories	45		66
Margin deposits	27		71
Disposal Group, Including Discontinued Operation, Assets, Current	773		92
Other	26		29
Total current assets	1,869		922
Properties and equipment, net (successful efforts method of accounting)	6,842		6,760
Derivative assets	38		7
Other noncurrent assets	49		740
Total assets	8,798		8,429
Current liabilities:
Accounts payable	712		634
Accrued and other current liabilities	177		167
Disposal Group, Including Discontinued Operation, Liabilities, Current	132		41
Customer margin deposits payable	0		55
Deferred Tax Liabilities, Net, Current	151		0
Derivative liabilities	37		110
Total current liabilities	1,209		1,007
Deferred income taxes	621		776
Long-term Debt and Capital Lease Obligations	2,280	[1]	1,911	[1]
Derivative liabilities	5		12
Asset retirement obligations	198		305
Other noncurrent liabilities	57		208
Contingent liabilities and commitments (Note 9)
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares issued)	0		0
Common stock (2 billion shares authorized at $0.01 par value; 203.7 million shares issued at December 31, 2014 and 201 million shares issued at December 31, 2013)	2		2
Additional paid-in-capital	5,562		5,516
Accumulated deficit	-1,244		-1,408
Accumulated other comprehensive income (loss)	-1		-1
Total stockholders’ equity	4,319		4,109
Noncontrolling interests in consolidated subsidiaries	109		101
Total equity	4,428		4,210
Total liabilities and equity	$8,798		$8,429
[1]	Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$7	$11
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued	203,700,000	201,000,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Product revenues:
Natural gas sales	$1,002		$896		$1,193
Oil and condensate sales	724		534		376
Natural gas liquid sales	205		228		297
Total product revenues	1,931		1,658		1,866
Gas management	1,120		891		949
Net gain (loss) on derivatives not designated as hedges (Note 14)	434		-124		78
Other	8		6		7
Total revenues	3,493		2,431		2,900
Costs and expenses:
Lease and facility operating	244		227		202
Gathering, processing and transportation	328		350		434
Taxes other than income	126		102		68
Gas management, including charges for unutilized pipeline capacity	987		931		996
Exploration (Note 4)	173		423		71
Depreciation, depletion and amortization	810		858		884
Impairment of producing properties and costs of acquired unproved reserves	20	[1]	860	[1]	123	[1]
Loss On Sale Of Working Interests	196		0		0
General and administrative	271		269		265
Other—net	12		12		14
Total costs and expenses	3,167		4,032		3,057
Operating income (loss)	326		-1,601		-157
Interest expense	-123		-108		-102
Investment income, impairment of equity method investment and other	1		-19		1
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	204		-1,728		-258
Provision (benefit) for income taxes	75		-624		-84
Income (loss) from continuing operations	129		-1,104		-174
Income (loss) from discontinued operations	42		-87		-37
Net income (loss)	171		-1,191		-211
Less: Net income (loss) attributable to noncontrolling interests	7		-6		12
Net income (loss) attributable to WPX Energy, Inc.	164		-1,185		-223
Income (Loss) from Continuing Operations Attributable to WPX	129		-1,092		-174
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX	$35		($93)		($49)
Basic earnings (loss) per common share (Note 3):
Income (Loss) from Continuing Operations, Per Basic Share	$0.63		($5.45)		($0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	$0.18		($0.46)		($0.25)
Earnings Per Share, Basic	$0.81		($5.91)		($1.12)
Basic weighted-average shares	202.7		200.5		198.8
Income (Loss) from Continuing Operations, Per Diluted Share	$0.62		($5.45)		($0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	$0.18		($0.46)		($0.25)
Earnings Per Share, Diluted	$0.80		($5.91)		($1.12)
Diluted weighted-average shares	206.3		200.5	[2]	198.8	[2]
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.
[2]	For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options 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.

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Condensed Statement of Income Captions [Line Items]
Comprehensive income (loss) attributable to WPX Energy, Inc.	$164		($1,188)		($440)
Other comprehensive income (loss):
Change in fair value of cash flow hedges, net of tax	0	[1]	0	[1]	57	[1]
Net reclassifications into earnings of net cash flow hedge gains, net of tax	0	[2]	-3	[2]	-274	[2]
Other comprehensive income (loss), net of tax	0		-3		-217
Net income (loss) attributable to WPX Energy, Inc.	($164)		$1,185		$223
[1]	Change in fair value of cash flow hedges is net of income tax of $33 million for 2012. 2012 includes a $15 million before tax unrealized gain that was recognized in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations, as the underlying transaction was no longer probable of occurring (see Note 14).
[2]	Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million and $159 million of income tax for 2013 and 2012, respectively. Before tax amounts realized and reclassified to product revenues, primarily natural gas sales revenues, on the Consolidated Statements of Operations were $5 million and $434 million for 2013 and 2012, respectively.

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Statement of Partners' Capital [Abstract]
Unrealized gains recognized for hedge transactions		$33
Derivative Instruments Not Designated as Hedging Instruments, Gain		15
Income tax provision for cash flow hedge gains	2	159
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$5	$434

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)		Total	Total Stockholders’ Equity	Common Stock	Capital in Excess of Par Value	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
In Millions, unless otherwise specified
Balance at beginning of period at Dec. 31, 2011		$5,759	$5,678	$2	$5,457	$0	$219	$81	[1]
Comprehensive income:
Net income (loss)		-211	-223			-223		12	[1]
Other comprehensive income (loss)		-217	-217				-217
Comprehensive income (loss)		-428
Contribution from noncontrolling interest		10
Contribution from noncontrolling interest	[1]							10
Stock based compensation, net of tax benefit		30	30		30
Balance at end 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						4	[1]
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]
[1]	Primarily represents the 31 percent of Apco Oil and Gas International Inc. owned by others.

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Equity (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Noncontrolling interest, ownership percentage by noncontrolling owners	31.00%	31.00%	31.00%

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating Activities
Net income (loss)	$171		($1,191)		($211)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	863		940		973
Deferred income tax provision (benefit)	46		-645		-160
Provision for impairment of properties and equipment (including certain exploration expenses) and investments	236		1,483		288
Amortization of stock-based awards	36		32		28
Gain (loss) on sales of assets	-196	[1]	41	[1]	42	[1]
Cash provided (used) by operating assets and liabilities:
Accounts receivable	51		-43		68
Inventories	19		-5		7
Margin deposits and customer margin deposits payable	-10		-18		-5
Other current assets	8		-7		7
Accounts payable	4		41		-128
Accrued and other current liabilities	-1		-21		12
Changes in current and noncurrent derivative assets and liabilities	-559		106		-32
Other, including changes in other noncurrent assets and liabilities	10		5		-9
Net cash provided by operating activities	1,070		636		796
Investing Activities
Capital expenditures	-1,807	[2]	-1,154	[2]	-1,521	[2]
Proceeds from sales of assets	374		49		310
Other	-4		-6		7
Net cash used in investing activities	-1,437		-1,111		-1,204
Financing Activities
Proceeds from common stock	16		6		3
Proceeds from long-term debt	500		0		6
Borrowings on credit facility	1,947		970		50
Payments on credit facility	-2,077		-560		-50
Excess tax benefit of stock based awards	0		0		13
Payments for long-term debt issuance costs	-13		0		0
Other	-29		10		15
Net cash provided by financing activities	344		426		37
Net increase (decrease) in cash and cash equivalents	-23		-49		-371
Effect of Exchange Rate on Cash and Cash Equivalents	-6		-5		-2
Cash and cash equivalents at beginning of period	99	[3]	153	[3]	526	[3]
Cash and cash equivalents at end of period	$70	[3]	$99	[3]	$153	[3]
[1]	2014 includes $196 million loss on the sale of working interests in the Piceance Basin (Note 4), 2013 includes a $36 million gain on sale of Powder River Basin deep rights leasehold (Note 2) and 2012 includes a $38 million gain on the sale of our holdings in Barnett Shale and Arkoma Basin (Note 2).
[2]	Increase to properties and equipment$(1,934) $(1,207) $(1,449)Changes in related accounts payable127 53 (72)Capital expenditures$(1,807) $(1,154) $(1,521)
[3]	(c) Amounts include cash associated with our international operations which represent the difference between amounts reported as cash on the Consolidated Balance Sheets.

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Loss On Sale Of Working Interests	$196		$0		$0
Gain (Loss) on Disposition of Assets					38
Gain on sale of Powder River Basin deep rights leasehold			36
Increase to properties and equipment	-1,934		-1,207		-1,449
Changes in related accounts payable and accounts receivable	127		53		-72
Capital expenditures	($1,807)	[1]	($1,154)	[1]	($1,521)	[1]
[1]	Increase to properties and equipment$(1,934) $(1,207) $(1,449)Changes in related accounts payable127 53 (72)Capital expenditures$(1,807) $(1,154) $(1,521)

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations
	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. During January 2015 we completed the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol. Together, these non-operated international holding comprised our international segment. We expect to book a gain of approximately $40 million related to this transaction during first quarter 2015.
	During the third quarter of 2014, our management signed an agreement to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million, subject to closing adjustments such as net revenues from effective date to closing date. We continue to negotiate the divestiture. The original sales agreement was scheduled to terminate February 13, 2015, but both parties agreed to extend the timetable. If the agreement does not successfully close in March, WPX has the option to terminate the transaction. Additionally, we have recorded a $45 million impairment of the net assets to a probability weighted-average of expected sales prices. The Company has not actively drilled in the basin since 2011. The Powder River operations have firm gathering and treating agreements with total commitments of $128 million through 2020. These commitments have been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2015 and beyond totaling $172 million. Depending on the final terms upon closing of the Powder River sale, we may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Powder River Basin.
	During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.
	Summarized Results of Discontinued Operations
	For the year ended December 31, 2014	Domestic			International			Total
					(Millions)
	Total revenues	$	189		$	163		$	352
	Costs and expenses:
	Lease and facility operating	$	41		$	37		$	78
	Gathering, processing and transportation	70			1			71
	Taxes other than income	16			28			44
	Exploration	—			4			4
	Depreciation, depletion and amortization	11			42			53
	Impairment of assets held for sale	45			—			45
	General and administrative	4			16			20
	Other—net	—			12			12
	Total costs and expenses	187			140			327
	Operating income (loss)	2			23			25
	Interest capitalized	1			—			1
	Investment income and other	6			19			25
	Income (loss) from discontinued operations before income taxes	9			42			51
	Provision (benefit) for income taxes(a)	2			7			9
	Income (loss) from discontinued operations	$	7		$	35		$	42
	__________
	(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	$	178		$	152		$	330
	Costs and expenses:
	Lease and facility operating	$	44		$	37		$	81
	Gathering, processing and transportation	80			3			83
	Taxes other than income	15			24			39
	Exploration	1			7			8
	Depreciation, depletion and amortization	48			34			82
	Impairment of producing properties and costs of acquired unproved reserves	192			3			195
	Gain on sale of Powder River Basin deep rights leasehold	(36		)	—			(36		)
	General and administrative	6			14			20
	Other—net	5			—			5
	Total costs and expenses	355			122			477
	Operating income (loss)	(177		)	30			(147		)
	Interest capitalized	4			—			4
	Investment income and other	4			21			25
	Income (loss) from discontinued operations before income taxes	(169		)	51			(118		)
	Provision (benefit) for income taxes(a)	(62		)	31			(31		)
	Income (loss) from discontinued operations	$	(107	)	$	20		$	(87	)
	__________
	(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.
	For the year ended December 31, 2012	Domestic			International			Total
					(Millions)
	Total revenues	$	180		$	137		$	317
	Costs and expenses:
	Lease and facility operating	$	65		$	32		$	97
	Gathering, processing and transportation	74			2			76
	Taxes other than income	19			24			43
	Gas management, including charges for unutilized pipeline capacity	1			—			1
	Exploration	1			11			12
	Depreciation, depletion and amortization	62			27			89
	Impairment of producing properties and costs of acquired unproved reserves	102			—			102
	Gain on sale of Barnett Shale and Arkoma Basin holdings	(38		)	—			(38		)
	General and administrative	10			14			24
	Other—net	(1		)	—			(1		)
	Total costs and expenses	295			110			405
	Operating income (loss)	(115		)	27			(88		)
Interest capitalized	6			—			6
Investment income and other	4			27			31
Income (loss) from discontinued operations before income taxes	(105		)	54			(51		)
Provision (benefit) for income taxes	(38		)	24			(14		)
Income (loss) from discontinued operations	$	(67	)	$	30		$	(37	)
Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
December 31, 2014	Domestic			International			Total
				(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—		$	29		$	29
Accounts receivable	—			25			25
Inventories	1			7			8
Other	—			14			14
Total current assets	1			75			76
Investments	18			134			152
Properties and equipment (successful efforts method of accounting)(a)	132			445			577
Less—accumulated depreciation, depletion and amortization	(10		)	(228		)	(238		)
Properties and equipment, net	122			217			339
Other noncurrent assets	—			6			6
Total assets classified as held for sale—discontinued operations	$	141		$	432		$	573
Total assets classified as held for sale—continuing operations (Note 4)	200			—			200
Total assets classified as held for sale on the Consolidated Balance Sheets	$	341		$	432		$	773
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—		$	34		$	34
Accrued and other current liabilities	3			23			26
Total current liabilities	3			57			60
Deferred income taxes	—			13			13
Long-term debt	—			2			2
Asset retirement obligations	45			7			52
Other noncurrent liabilities	—			3			3
Total liabilities associated with assets held for sale—discontinued operations	$	48		$	82		$	130
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	$	50		$	82		$	132
__________
(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.
December 31, 2013	Domestic			International			Total
				(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—		$	51		$	51
Accounts receivable	—			18			18
Inventories	1			5			6
Other	—			17			17
Total current assets	1			91			92
Investments	17			125			142
Properties and equipment (successful efforts method of accounting)	166			360			526
Less—accumulated depreciation, depletion and amortization	—			(194		)	(194		)
Properties and equipment, net	166			166			332
Total assets classified as held for sale—discontinued operations(a)	$	184		$	382		$	566
Total assets classified as held for sale—continuing operations (Note 4)(a)	148			—			148
Total assets classified as held for sale on the Consolidated Balance Sheets(a)	$	332		$	382		$	714
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—		$	18		$	18
Accrued and other current liabilities	3			20			23
Total current liabilities	3			38			41
Deferred income taxes	—			12			12
Long-term debt	—			5			5
Asset retirement obligations	47			4			51
Total liabilities associated with assets held for sale—discontinued operations(a)	$	50		$	59		$	109
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(a)	$	52		$	59		$	111
__________
(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.
Noncontrolling interests in consolidated subsidiaries of $109 million and $101 million as of December 31, 2014 and 2013, respectively, related to assets classified as held for sale.
Cash Flows Attributable to Discontinued Operations
Excluding taxes and changes to working capital related to Powder River Basin, total cash provided by operating activities related to discontinued operations was $65 million, $36 million and $18 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related to Powder River Basin discontinued operations was $11 million, $3 million and $20 million for 2014, 2013 and 2012, respectively. Cash provided by operating activities related to our international operations was $65 million, $56 million and $50 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related our international operations was $85 million, $43 million and $56 million for 2014, 2013 and 2012, respectively.

Earnings_Loss_Per_Common_Share

Earnings (Loss) Per Common Share from Continuing Operations	12 Months Ended
	Dec. 31, 2014
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,
		2014		2013			2012
		(Millions, except per-share amounts)
	Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	129	$	(1,092	)	$	(174	)
	Basic weighted-average shares	202.7		200.5			198.8
	Effect of dilutive securities(a):
	Nonvested restricted stock units and awards	2.7
	Stock options	0.9
	Diluted weighted-average shares	206.3		200.5			198.8
	Earnings (loss) per common share from continuing operations:
	Basic	$	0.63	$	(5.45	)	$	(0.87	)
	Diluted	$	0.62	$	(5.45	)	$	(0.87	)
	__________
	(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options 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.
	The table below includes information related to stock options that were outstanding at December 31, 2014, 2013 and 2012 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.
		2014		2013			2012
	Options excluded (millions)	1.4		0.4			1.3
	Weighted-average exercise price of options excluded	$	18.42	$	20.24		$	18.17
	Exercise price range of options excluded	$16.46 - $21.81		$20.21  - $20.97			$16.46  - $20.97
	Fourth quarter weighted-average market price	$	15.96	$	19.97		$	16.15

Asset_Sales_Impairments_and_Ex

Asset Sales, Impairments and Exploration Expenses	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Asset Sales, Impairments and Exploration Expenses	Asset Sales, Impairments and Exploration Expenses
	In 2014, we recorded a total of $87 million in impairment charges associated with exploratory well costs and producing properties of which approximately $20 million is recorded as a separate line on the Consolidated Statements of Operations and $67 million is included in exploration expenses. In 2013, we recorded a total of $1.2 billion in impairment charges of which $860 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 June 2014, we sold portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP (“Legacy”) for $325 million cash with an effective date of January 1, 2014. The terms of the sale also provided us with a 10 percent ownership in a newly created class of incentive distribution rights (“IDR”) of Legacy. The working interests represented approximately 300 Bcfe of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. Production related to these working interests for January 2014 through May 2014 approximated 70 MMcfe per day of our production. Based on an estimated total value received of $329 million, which represents estimated final cash proceeds and an estimated fair value of the IDRs, we recorded a $195 million loss on the sale in second quarter 2014. In the third quarter of 2014, we recorded an additional loss on sale of $1 million related to this transaction.
	On December 3, 2014, we announced that we have agreed to sell our operations in northeast Pennsylvania and release certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $300 million in cash. Net property, plant and equipment related to this transaction, as of December 31,2014, was $200 million and asset retirement obligation liability was $2 million. The transaction includes physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 operated horizontal wells. The assets are primarily located in Susquehanna County, Pennsylvania. The transaction also includes the release of firm transportation capacity that we have under contract in the northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we will be released from approximately $24 million per year in annual demand obligations associated with the transport. The transaction subsequently closed on January 30, 2015 and we estimate a net gain of at least $75 million will be recorded in first quarter 2015.
	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,
		2014		2013		2012
		(Millions)
	Impairment of producing properties and costs of acquired unproved reserves(a)	$	20	$	860	$	123
	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
	•	$9 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 the following impairments during 2013:
	•	$772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin; and
	•	$88 million impairment 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.
	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.
	As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded the following impairments during 2012:
	•	$75 million impairment of capitalized costs of acquired unproved reserves in the Piceance Basin; and
	•	$48 million impairment of proved producing oil and gas properties in the Green River Basin.
	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 13).
	Exploration Expenses
	The following table presents a summary of exploration expenses.
		Years Ended December 31,
		2014		2013		2012
		(Millions)
	Geologic and geophysical costs	$	11	$	18	$	12
	Impairments of exploratory area well costs and dry hole costs	88		3		1
	Unproved leasehold property impairments, amortization and expiration	74		402		58
	Total exploration expenses	$	173	$	423	$	71
	Impairments of exploratory well and dry hole costs for 2014 include $67 million of impairment related to our Niobrara Shale well costs in the Piceance Basin and $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities. The remaining amount represents dry hole costs associated with exploratory wells where hydrocarbons were not detected. The $67 million Niobrara Shale impairment relates to carrying costs on producing and science wells in excess of estimated discounted cash flows of the exploratory play. We continue to evaluate the potential of our Niobrara Shale exploratory play and plan to drill additional wells in 2015. As of December 31, 2014, our total domestic capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $37 million.
	Unproved leasehold impairment, amortization and expiration in 2014 includes impairments of $41 million for unproved leasehold costs in exploratory areas where the company no longer intends 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, 2014
Property, Plant and Equipment [Abstract]
Properties and Equipment	Properties and Equipment
	Properties and equipment is carried at cost and consists of the following:
		Estimated		December 31,
		Useful
		Life(a)
		(Years)		2014				2013
				(Millions)
	Proved properties	(b)		$	10,386			$	10,955
	Unproved properties	(c)		394				316
	Gathering, processing and other facilities	15-25		251				209
	Construction in progress	(c)		541				353
	Other	Mar-40		181				178
	Total properties and equipment, at cost			11,753				12,011
	Accumulated depreciation, depletion and amortization			(4,911		)		(5,251		)
	Properties and equipment—net			$	6,842			$	6,760
	__________
	(a)	Estimated useful lives are presented as of December 31, 2014.
	(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.
	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.
	Also during 2014, we closed an agreement to farmout a portion of our Trail Ridge properties in the Piceance Basin with TRDC LLC, a subsidiary of G2X Energy. We received $50 million in cash for 49 percent of our working interests in approximately 100 proved developed wells and certain incurred drilling costs. TRDC LLC has committed to a $170 million drilling carry on nearly 400 future wells and will make additional investments for its 49 percent working interest.
	Unproved properties consist primarily of non-producing leasehold in the San Juan, Williston and Piceance 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 2014 and 2013 is presented below.
		2014				2013
		(Millions)
	Balance, January 1	$	308			$	261
	Liabilities incurred	19				11
	Liabilities settled	(2		)		(1		)
	Liabilities associated with assets sold	(65		)		—
	Estimate revisions	(78		)		17
	Accretion expense(a)	19				20
	Balance, December 31	$	201			$	308
	Amount reflected as current	$	3			$	3
	__________
	(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_a

Accounts Payable and Accrued and Other Current Liabilities	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Accounts Payable and Accrued and Other Current Liabilities	Accounts Payable and Accrued and Other Current Liabilities
	Accounts Payable
		December 31,
		2014		2013
		(Millions)
	Trade	$	215	$	208
	Accrual for capital expenditures	313		225
	Royalties	125		130
	Cash overdrafts	—		35
	Other	59		36
		$	712	$	634
	Accrued and other current liabilities
		December 31,
		2014		2013
		(Millions)
	Taxes other than income taxes	$	41	$	41
	Accrued interest	53		43
	Compensation and benefit related accruals	55		52
	Other, including other loss contingencies	28		31
		$	177	$	167

Debt_and_Banking_Arrangements

Debt and Banking Arrangements	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt and Banking Arrangements	Debt and Banking Arrangements
	As of the indicated dates, our debt consisted of the following:
		December 31,
		2014 (a)		2013 (a)
		(Millions)
	5.250% Senior Notes due 2017	$	400	$	400
	6.000% Senior Notes due 2022	1,100		1,100
	5.250% Senior Notes due 2024	500		—
	Credit facility agreement	280		410
	Other	1		2
	Total debt	$	2,281	$	1,912
	Less: Current portion of long-term debt	1		1
	Total long-term debt	$	2,280	$	1,911
	__________
	(a)	Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.
	Senior Notes
	In November 2011, we issued $400 million aggregate principal amount of 5.25% Senior Notes due 2017 (the “2017 Notes”) and $1.1 billion aggregate principal amount of 6.00% 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.
	In September 2014, we issued $500 million aggregate principal amount of 5.25% 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.
	The terms of the indentures governing our 2017 Notes, 2022 Notes and 2024 Notes are substantially identical.
	Optional Redemption. We have the option prior to maturity for the 2017 Notes, prior to October 15, 2021 for the 2022 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 October 15, 2021 to redeem the 2022 Notes, 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.
	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
	In October 2014, we amended and restated our $1.5 billion five-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility Agreement matures on October 28, 2019. As of December 31, 2014, the weighted average variable interest rate was 3.01% on the $280 million outstanding under the Credit Facility Agreement. As of February 25, 2015, we did not have any outstanding borrowings under the Credit Facility Agreement as proceeds from asset sales were used to repay all outstanding amounts.
	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) Citibank, N.A.'s 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, 2014, 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, 2014, the commitment fee rate was 0.30%.
	Under the Credit Facility Agreement, when our long-term unsecured debt rating is not BBB- or better by S&P or Baa3 or better by Moody’s and the other of the two ratings is not less than BB+ by S&P or Ba1 by Moody's, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the Credit Facility Agreement) to Consolidated EBITDAX (as defined in the Credit Facility Agreement) of not greater than 3.75 to 1.00. Consolidated Net Indebtedness includes a reduction attributable to unrestricted cash and cash equivalents not to exceed $50 million. Consolidated EBITDAX will be calculated for the four fiscal quarters ending on the last day of any fiscal quarter for which financial statements have been or were required to be delivered. Additionally, the ratio of Consolidated Indebtedness (defined as Indebtedness of us and our consolidated subsidiaries determined on a consolidated basis) to Consolidated Total Capitalization (defined as Consolidated Indebtedness plus Consolidated Net Worth) will not be permitted to be greater than 60 percent and will be applicable for the life of the agreement.
	When our long-term unsecured debt rating is BB or worse by S&P and Ba2 or worse by Moody's or BB- or worse by S&P or Ba3 or worse by Moody's, we will also 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 Agreement, to Consolidated Indebtedness ratio of at least 1.25 to 1.00 for fiscal periods ending on or prior to December 31, 2015, and 1.50 to 1.00 for fiscal periods ending after December 31, 2015. Based on our current long-term unsecured debt ratings, as of the date of this filing, we are not required to comply with this covenant. In addition, this covenant will not apply at any time after the occurrence of the Investment Grade Date, which is the first date after closing on which our long-term unsecured debt is rated BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or watch by either agency), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
	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. 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, 2014 a total of $320 million in letters of credit have been issued.

Provision_Benefit_for_Income_T

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes
	The provision (benefit) for income taxes from continuing operations includes:
		Years Ended December 31,
		2014			2013			2012
		(Millions)
	Provision (benefit):
	Current:
	Federal	$	(3	)	$	(29	)	$	49
	State	1			1			4
		(2		)	(28		)	53
	Deferred:
	Federal	76			(549		)	(125		)
	State	1			(47		)	(12		)
		77			(596		)	(137		)
	Total provision (benefit)	$	75		$	(624	)	$	(84	)
	Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
		Years Ended December 31,
		2014			2013			2012
		(Millions)
	Provision (benefit) at statutory rate	$	71		$	(604	)	$	(90	)
	Increases (decreases) in taxes resulting from:
	State income taxes (net of federal benefit)	3			(111		)	(6		)
	State income tax change in valuation allowance (net of federal benefit)	(1		)	80			—
	State income tax legislation change (net of federal benefit)	9			—			—
	Effective state income tax rate change (net of federal benefit)	(9		)	(3		)	—
	Alternative minimum tax credits	—			—			11
	Other	2			14			1
	Provision (benefit) for income taxes	$	75		$	(624	)	$	(84	)
	Significant components of deferred tax liabilities and deferred tax assets are as follows:
		December 31,
		2014			2013
		(Millions)
	Deferred tax liabilities:
	Properties and equipment	$	738		$	961
	Derivatives, net	170			—
	Other, net	17			23
	Total deferred tax liabilities	925			984
	Deferred tax assets:
	Accrued liabilities and other	124			176
	Alternative minimum tax credits	60			76
	Loss carryovers	51			83
	Derivatives, net	—			21
	Other, net	32			—
	Total deferred tax assets	267			356
	Less: valuation allowance	114			99
	Total net deferred tax assets	153			257
	Net deferred tax liabilities	$	772		$	727
	Net cash payments for domestic income taxes were $9 million and $40 million in 2014 and 2012, respectively, while net cash refunds were $26 million in 2013.
	We had federal net operating loss (“NOL”) carryovers of approximately $114 million at December 31, 2013, which were fully utilized in 2014. The Company has state NOL carryovers, primarily in Pennsylvania, of approximately $875 million and $825 million at 2014 and 2013, respectively, of which more than 90 percent expire after 2029.
	Tax reform legislation was enacted by the state of New York on March, 31, 2014, and 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 to accrue for the impact of this new legislation. However, due to announced asset sales in fourth-quarter 2014, our state effective tax rate decreased resulting in a $9 million deferred tax benefit.
	We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania. In addition, we have recorded a valuation allowance against a portion of the excess tax basis in our investment in Apco, which have been included in discontinued operations (see Note 2). In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. As a result of our assessment of available evidence, a valuation allowance was recorded to reduce recognized tax assets, net of federal tax, to an amount that will more likely than not be realized by the Company.
	Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the excess tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. At December 31, 2013, $7 million of excess tax benefit was not included in the Company’s loss carryovers deferred tax asset. The $7 million excess tax benefit was recognized in 2014 due to the utilization of loss carryovers.
	Through the effective date of our spin-off from The Williams Companies, Inc. (“Williams”), December 31, 2011, our domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. Effective with the spin-off, we entered into a tax sharing agreement with Williams which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off. Pursuant to the tax sharing agreement, we remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. 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. We are not aware of any significant adjustments related to our business, but 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 to 2011 unrelated to our business. Williams previously notified us of certain corrections that resulted in reductions in the alternative minimum tax credit allocated to us, of which $11 million was a reduction of a benefit for income taxes in 2012.
	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, 2014, 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_Com

Contingent Liabilities and Commitments	12 Months Ended
	Dec. 31, 2014
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 seek a stay of 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 seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. 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, 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 other states 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 2008 through December 2014, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $113 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 the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, 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 on the Western States Antitrust Litigation. The panel held that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims, reversing the summary judgment entered in favor of the defendants. The panel further held that the district court did not abuse its discretion in denying the plaintiffs’ motions for leave to amend complaints. The U.S. Supreme Court granted Defendants' writ of certiorari. 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, 2014, 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 have 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, 2014 and December 31, 2013, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
	Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
	Commitments
	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, 2014 are as follows:
		(Millions)
	2015	$	177
	2016	162
	2017	149
	2018	138
	2019	126
	Thereafter	389
	Total	$	1,141
	Also, in conjunction with the closing of the Powder River sale and current terms therein, we may record certain pipeline capacity obligations held by our marketing company associated with our exiting the Powder River Basin. Our total commitments related to these pipeline agreements for 2015 and beyond total $172 million.
	We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services, which total $305 million over approximately six years.
	Excluded from the pipeline capacity and natural gas gathering and treating services commitments discussed above are commitments totaling $88 million and $43 million, respectively, which have been or are assumed to be assigned to the buyers of assets held for sale.
	In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
	Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:
		(Millions)
	2015	$	37
	2016	32
	2017	11
	2018	7
	2019	7
	Thereafter	15
	Total	$	109
	Leases totaling $0.5 million associated with assets held for sale are excluded from the operating lease commitments discussed above.
	Total rent expense, excluding amounts capitalized, was $27 million, $27 million and $19 million in 2014, 2013 and 2012, 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, 2014
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 $17 million, $16 million and $6 million for 2014, 2013 and 2012, respectively. Approximately $10 million and $11 million were included in accrued and other current liabilities at December 31, 2014 and December 31, 2013 respectively, related to the non-matching annual employer contribution.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2014
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 19.8 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 124 thousand shares at an average price of $12.56 per share during 2014.
	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 reflected in general and administrative expense for the years ended December 31, 2014, 2013 and 2012 was $35 million, $31 million and $28 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2014 was $41 million. This amount is comprised of $1 million related to stock options and $40 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, 2014.
		WPX Plan
	Stock Options	Options			Weighted-				Aggregate
					Average				Intrinsic
					Exercise				Value
					Price
		(Millions)							(Millions)
	Outstanding at December 31, 2013(a)	4.1			$	13.27			$	29
	Granted	0.4			$	19.03
	Exercised	(1.3	)		$	11.11
	Forfeited	(0.1	)		$	15.39
	Outstanding at December 31, 2014(a)	3.1			$	14.8			$	2
	Exercisable at December 31, 2014	2.7			$	14.26			$	2
	__________
	(a)	Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.
	The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $13 million, $5 million and $5 million, respectively.
	The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2014.
		WPX Plan
		Stock Options Outstanding									Stock Options Exercisable
	Range of Exercise Prices	Options			Weighted-				Weighted-		Options		Weighted-		Weighted-
					Average				Average				Average		Average
					Exercise				Remaining				Exercise		Remaining
					Price				Contractual				Price		Contractual
									Life						Life
		(Millions)							(Years)		(Millions)				(Years)
	$ 6.02 to $10.68	0.5			$	7.59			2.8		0.5		$	7.59	2.8
	$ 11.32 to $13.46	0.6			$	11.82			4		0.6		$	11.82	4
	$14.41 to $18.23	1.5			$	16.39			6.1		1.2		$	16.36	5.6
	$19.95 to $21.81	0.5			$	20.61			5		0.4		$	20.24	3.2
	Total	3.1			$	14.8			5		2.7		$	14.26	4.4
	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
		2014				2013				2012
	Weighted-average grant date fair value of options granted	$	18.94			$	6.04			$	7.79
	Weighted-average assumptions:
	Dividend yield	—				—				—
	Volatility	43		%		42.8		%		43.8		%
	Risk-free interest rate	1.85		%		1.06		%		1.17		%
	Expected life (years)	5.9				6				6
	For 2014, 2013 and 2012, 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 $14 million, $4 million and $2 million during 2014, 2013 and 2012, respectively.
	Nonvested Restricted Stock Units
	The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.
		WPX Plan
	Restricted Stock Units	Shares			Weighted-
					Average
					Fair Value(a)
		(Millions)
	Nonvested at December 31, 2013	5.2			$	16.97
	Granted	2.5			$	18.37
	Forfeited	(0.7	)		$	16.92
	Vested	(1.9	)		$	16.92
	Nonvested at December 31, 2014	5.1			$	17.58
	__________
(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
	2014				2013				2012
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.37			$	14.97			$	17.35
Total fair value of restricted stock units vested during the year (millions)	$	33			$	18			$	14
Performance-based shares granted represent 15 percent of nonvested restricted stock units outstanding at December 31, 2014. 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, 2014
Equity [Abstract]
Stockholders' Equity	Stockholders’ Equity
	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 were declared or paid for 2014, 2013 or 2012. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
	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.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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 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 and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
		31-Dec-14											31-Dec-13
		Level 1		Level 2				Level 3			Total		Level 1		Level 2		Level 3		Total
				(Millions)											(Millions)
	Energy derivative assets	$	14	$	517			$	5		$	536	$	30	$	26	$	1	$	57
	Energy derivative liabilities	$	32	$	10			$	—		$	42	$	83	$	38	$	1	$	122
	Total debt(a)	$	—	$	2,218			$	—		$	2,218	$	—	$	1,938	$	—	$	1,938
	__________
	(a)	The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.
	Energy derivatives include commodity based exchange-traded contracts and 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 and option 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 or as 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 to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions 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 is relatively short with 100 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. 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 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, 2014, 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, 2014 or 2013.
	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,
		2014		2013				2012
		(Millions)
	Beginning balance	$	—	$	(1	)		$	1
	Realized and unrealized gains (losses):
	Included in income (loss) from continuing operations	5		(2		)		3
	Included in other comprehensive income (loss)	—		—				—
	Purchases, issuances, and settlements	—		3				(5		)
	Transfers out of Level 3	—		—				—
	Ending balance	$	5	$	—			$	(1	)
	Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	5	$	(1	)		$	(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, 2014, 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,
		2014 (a)				2013 (b)					2012 (c)
		(Millions)
	Impairments:
	Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)	$	20			$	1,055				$	225
	Unproved leasehold	—				317					—
	Equity method investment (Note 4)	—				20					—
		$	20			$	1,392				$	225
	__________
	(a)	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.
	(b)	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. 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.
	(c)	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:
	•	$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. 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.
	•	$48 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 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

Derivatives_and_Concentration_

Derivatives and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2014
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 natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
	We produce, buy and sell natural gas, crude oil 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 natural gas, crude oil 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 options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.
	We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity 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 and storage contracts 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, 2014.
	Commodity		Period		Contract Type (a)		Location		Notional Volume (b)			Weighted Average
												Price (c)
	Natural Gas
	Natural Gas		2015		Fixed Price Swaps		Henry Hub		(442	)		$	4.1
	Natural Gas		2015		Costless Collars		Henry Hub		(50	)		$ 4.00 - 4.50
	Natural Gas		2015		Basis Swaps		NGPL		(13	)		$	(0.16	)
	Natural Gas		2015		Basis Swaps		Rockies		(150	)		$	(0.11	)
	Natural Gas		2015		Basis Swaps		San Juan		(85	)		$	(0.10	)
	Natural Gas		2015		Basis Swaps		SoCal		(20	)		$	0.18
	Natural Gas		2016		Fixed Price Swaps		Henry Hub		(200	)		$	3.98
	Natural Gas		2016		Swaptions		Henry Hub		(90	)		$	4.23
	Natural Gas		2017		Swaptions		Henry Hub		(65	)		$	4.19
	Crude Oil
	Crude Oil		2015		Fixed Price Swaps		WTI		(20,236	)		$	94.88
	Crude Oil		2015		Swaptions		WTI		(882	)		$	97.29
	Crude Oil		2016		Swaptions		WTI		(5,250	)		$	97.55
	__________
	(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, 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 grant the counterparty the option to enter into future swaps with us.
	(b)	Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
	(c)	The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.
	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 storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. 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		2015		Basis Swaps		Multiple		(3	)
	Natural Gas		2015		Index		Multiple		(118	)
	Natural Gas		2016		Index		Multiple		(70	)
	Natural Gas		2017		Index		Multiple		(70	)
	Natural Gas		2018+		Index		Multiple		(379	)
	__________
	(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, storage and asset management agreements.
	(c)	Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/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,
		2014								2013
		Assets				Liabilities				Assets				Liabilities
		(Millions)
	Derivatives related to production not designated as hedging instruments	$	517			$	10			$	26			$	39
	Derivatives related to physical marketing agreements not designated as hedging instruments	19				32				31				83
	Total derivatives not designated as hedging instruments	$	536			$	42			$	57			$	122
	The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.
		Years Ended												Classification
		December 31,
		2014				2013				2012
						(Millions)
	Net gain recognized in other comprehensive income (loss) (effective portion)	$	—			$	—			$	90			AOCI
	Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	—			$	5			$	434			Revenues
	__________
	(a)	Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
	There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
	The following table presents the net gain (loss) related to our energy commodity derivatives.
		Years Ended December 31,
		2014				2013				2012
	Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515			$	(57	)		$	66
	Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)		(67		)		12
Net gain (loss) on derivatives not designated as hedges	$	434			$	(124	)		$	78
__________
(a)	Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
(b)	Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.
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
31-Dec-14	(Millions)
Derivative assets with right of offset or master netting agreements	$	536			$	(25	)		$	—			$	511
Derivative liabilities with right of offset or master netting agreements	$	(42	)		$	25			$	17			$	—
31-Dec-13
Derivative assets with right of offset or master netting agreements	$	57			$	(50	)		$	—			$	7
Derivative liabilities with right of offset or master netting agreements	$	(122	)		$	50			$	52			$	(20	)
__________
(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, 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 includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2013, we had collateral totaling $71 million posted to derivative counterparties, which includes $19 million of initial margin to clearinghouses or exchanges to enter into positions and $52 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $72 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 December 31, 2014 and $20 million at December 31, 2013.
Cash flow hedges
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark-to-market value. As of December 31, 2012, we had hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) were expected to be reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Actual gains or losses realized in the first quarter of 2013 matched these values. These gains substantially offset net losses that were realized in earnings from previous unfavorable market movements associated with underlying hedged transactions.
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:
	2014				2013
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	340			$	339
Joint interest owners	106				168
Other	13				11
Total	$	459			$	518
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 credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2014, 2013 and 2012, 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 gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:
Counterparty Type	Gross Total				Net Total
	(Millions)
Gas and electric utilities, integrated oil and gas companies, and other	$	4			$	4
Financial institutions (Investment Grade) (a)	533				508
	537				512
Credit reserves	(1		)		(1		)
Credit exposure from derivatives	$	536			$	511
__________
(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 nine largest net counterparty positions represent approximately 96 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, 2014, we held collateral support of approximately $32 million, either in the form of cash or letters of credit, related to our gas management sale agreements.
The customer margin deposits payable as of December 31, 2014 related to our commodity agreements. Collateral support for our commodity agreements could also include letters of credit and guarantees of payment by credit worthy parties.
Revenues
During 2014, 2013 and 2012, BP Energy Company, a domestic segment customer, accounted for 13 percent, 16 percent and 11 percent of our consolidated revenues, respectively. During 2014 and 2013, Southern California Gas Company accounted for 8 percent and 11 percent of our consolidated revenues, respectively. Williams accounted for 14 percent of our consolidated revenue for 2012. 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.

Quarterly_Financial_Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA	WPX Energy, Inc.
	QUARTERLY FINANCIAL DATA
	(Unaudited)
	Summarized quarterly financial data are as follows:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(Millions, except per-share amounts)
	2014
	Revenues	$	894		$	727		$	747		$	1,125
	Operating costs and expenses	$	783		$	659		$	570		$	656
	Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
	Income (loss) from discontinued operations	19			11			20			(8		)
	Net income (loss)	$	19		$	(133	)	$	66		$	219
	Amounts attributable to WPX Energy, Inc.:
	Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
	Income (loss) from discontinued operations	18			9			16			(8		)
	Net income (loss)	$	18		$	(135	)	$	62		$	219
	Basic earnings (loss) per common share:
	Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.11
	Income (loss) from discontinued operations	0.09			0.05			0.07			(0.03		)
	Net income (loss)	$	0.09		$	(0.66	)	$	0.3		$	1.08
	Diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.1
	Income (loss) from discontinued operations	0.09			0.05			0.07			(0.04		)
	Net income (loss)	$	0.09		$	(0.66	)	$	0.3		$	1.06
	2013
	Revenues	$	552		$	722		$	581		$	576
	Operating costs and expenses	$	634		$	612		$	621		$	1,024
	Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(890	)
	Income (loss) from discontinued operations	2			16			(11		)	(94		)
	Net income (loss)	$	(113	)	$	22		$	(116	)	$	(984	)
	Amounts attributable to WPX Energy, Inc.:
	Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(878	)
	Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
	Net income (loss)	$	(116	)	$	18		$	(114	)	$	(973	)
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.57	)	$	0.03		$	(0.52	)	$	(4.37	)
	Income (loss) from discontinued operations	(0.01		)	0.06			(0.05		)	(0.48		)
	Net income (loss)	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)
	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 loss 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 Note 4).
	•	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.
	Net income for third-quarter 2014 includes the following pre-tax items:
	•	$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 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.
	•	$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 first-quarter 2014 includes the following pre-tax items:
	•	$9 million deferred tax expense to accrue for the impact of new legislation (see Note 8.)
	Net loss for fourth-quarter 2013 includes the following pre-tax items:
	•	$1,178 million of impairments of costs of producing properties, acquired unproved reserves, leasehold and equity method investment (see Note 4).
	•	$9 million buyout of a transportation agreement.
	Net loss for third-quarter 2013 includes the following pre-tax items:
	•	$19 million of impairments of costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin (see Note 4).
	Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter (a)			Quarter
		(Millions, except per-share amounts)
		(Increase, (Decrease))
	2014
	Revenues	$	(93	)	$	(87	)	$	47		N/A
	Operating costs and expenses	$	(62	)	$	62		$	31		N/A
Income (loss) from continuing operations	$	(19	)	$	(11	)	$	(15	)	N/A
Income (loss) from discontinued operations	19			11			15			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(18	)	$	(9	)	$	(16	)	N/A
Income (loss) from discontinued operations	18			9			16			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
2013
Revenues	$	(79	)	$	(93	)	$	35		$	(81	)
Operating costs and expenses	$	(76	)	$	(77	)	$	22		$	(74	)
Income (loss) from continuing operations	$	(2	)	$	(16	)	$	3		$	94
Income (loss) from discontinued operations	2			16			(3		)	(94		)
Net income (loss)	$	—		$	—		$	—		$	—
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	1		$	(12	)	$	9		$	95
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	—		$	—		$	—		$	—
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.01		$	(0.06	)	$	0.01		$	0.48
Income (loss) from discontinued operations	(0.01		)	0.06			(0.01		)	(0.48		)
Net income (loss)	$	—		$	—		$	—		$	—
__________
(a)	Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures	We have significant continuing oil and gas producing activities primarily in the Piceance and San Juan Basins in the Rocky Mountain region and the Williston Basin in North Dakota, all of which are located in the United States. Until January 2015, we had international oil and gas producing activities, primarily in Argentina which were previously reported as a segment. The international activities were held for sale as of December 31, 2014 and as such, our international results of operations were reported as discontinued operations (see Note 2 of Notes to Consolidated Financial Statements). International net proved reserves, including amounts related to an equity method investment, were approximately 213 Bcfe 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 for the Powder River Basin and, through the date of sale in 2012, the holdings in the Barnett Shale and Arkoma Basin both of which have been reported as discontinued operations in our consolidated financial statements. The Powder River Basin operations represent less than 5 percent of our total domestic proved reserves at December 31, 2014. Additionally, capitalized costs exclude amounts related to assets in our Appalachian Basin which were held for sale as of December 31, 2014. Our Appalachian Basin assets held for sale represented less than 5 percent of our total domestic proved reserves.
	Capitalized Costs
		As of December 31,
		2014				2013
		(Millions)
	Proved Properties	$	10,717			$	11,132
	Unproved properties	394				324
		11,111				11,456
	Accumulated depreciation, depletion and amortization and valuation provisions	(4,698		)		(5,070		)
	Net capitalized costs	$	6,413			$	6,386
	•	Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $385 million and $328 million, net, for 2014 and 2013, respectively.
	•	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,
		2014				2013				2012
		(Millions)
	Acquisition	$	294			$	57			$	111
	Exploration	92				104				23
	Development	1,376				939				1,130
		$	1,762			$	1,100			$	1,264
	•	Costs incurred include capitalized and expensed items.
	•	Acquisition costs are as follows: Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include 28 Bcfe of proved reserves. The 2013 and 2012 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.
	•	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.
	Results of Operations
		For the years ended December 31,
		2014				2013				2012
		(Millions)
	Revenues:
	Natural gas sales	$	1,002			$	896			$	1,193
	Oil and condensate sales	724				534				376
	Natural gas liquid sales	205				228				297
	Net gain (loss) on derivatives not designated as hedges	515				(57		)		66
	Other revenues	8				6				7
	Total revenues	2,454				1,607				1,939
	Costs:
	Lease and facility operating	244				227				202
	Gathering, processing and transportation	328				350				434
	Taxes other than income	126				102				68
	Exploration	173				423				71
	Depreciation, depletion and amortization	810				858				884
	Impairment of certain proved properties	15				772				48
	Impairment of costs of acquired unproved reserves	5				88				75
	Loss on sale of working interests in the Piceance Basin	196				—				—
	General and administrative	264				262				259
	Other (income) expense	12				12				16
	Total costs	2,173				3,094				2,057
	Results of operations	281				(1,487		)		(118		)
	Provision (benefit) for income taxes	103				(543		)		(43		)
	Exploration and production net income (loss)	$	178			$	(944	)		$	(75	)
	•	Amounts for all years exclude the equity losses from our equity method investees. Net equity losses from these investees were $1 million, $21 million and $1 million in 2014, 2013 and 2012, respectively.
	•	Natural gas revenues consist of natural gas production sold and 2012 includes realized gains (losses) of derivatives that were designated as cash flow hedges.
	•	For derivative instruments that were entered into after January 1, 2012, we did not designate those as cash flow hedges. Any gain (loss) related to these derivatives is included in net gain on derivatives not designated as hedges.
	•	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 2014 include impairments of certain exploratory well costs (see Note 4 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.
	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. Proved reserves related to Powder River were approximately 200 Bcfe, 244.6 Bcfe and 235.9 Bcfe at December 31, 2014, 2013 and 2012, respectively. Excluded from the table are our international reserves that are primarily attributable to a consolidated subsidiary (Apco) which represented less than five percent of our total reserves. The international interests were sold in January 2015.
		Natural Gas (Bcf)			Oil (MMBbls)			NGLs (MMBbls)			All Products (Bcfe)
	Proved reserves at December 31, 2011	3,982.90			47.1			134			5,070.10
	Revisions	(404.8	)		5.6			(21.1	)		(498.6	)
Purchases	5.8			—			—			5.8
Divestitures	(217.0	)		(0.3	)		(1.0	)		(224.8	)
Extensions and discoveries	409.2			28.5			8.9			633.8
Production	(407.0	)		(4.4	)		(10.4	)		(495.8	)
Proved reserves at December 31, 2012	3,369.10			76.5			110.4			4,490.50
Revisions	308.3			3.5			(25.4	)		177.2
Divestitures	(0.2	)		—			—			(0.5	)
Extensions and discoveries	312			28.8			8.1			533.8
Production	(359.4	)		(5.9	)		(7.4	)		(439.4	)
Proved reserves at December 31, 2013	3,629.80			102.9			85.7			4,761.60
Revisions	(198.3	)		(7.7	)		(13.4	)		(324.8	)
Purchases	6			4.2			0.8			36.5
Divestitures	(314.6	)		(1.8	)		(8.5	)		(376.6	)
Extensions and discoveries	362.1			42.4			12.5			691.3
Production	(335.4	)		(9.2	)		(6.3	)		(428.4	)
Proved reserves at December 31, 2014	3,149.60			130.8			70.8			4,359.60
Proved developed reserves:
December 31, 2012	2,170.70			23.7			64.9			2,702.60
December 31, 2013	2,265.20			36.8			48.6			2,777.70
December 31, 2014	2,090.00			60			43.9			2,713.80
Proved undeveloped reserves:
31-Dec-12	1,198.40			52.8			45.5			1,787.90
31-Dec-13	1,364.60			66.1			37.1			1,983.90
31-Dec-14	1,059.60			70.8			26.9			1,645.80
__________
(a)	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
•	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
•	Revisions in 2014 primarily reflect 97 Bcfe of net positive revisions to developed reserves and 422 Bcfe of net negative revisions to undeveloped reserves. The 422 Bcfe 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 133 Bcfe related to developed reserves and 44 Bcfe related to undeveloped reserves. Revisions in 2012 primarily resulted from the lower 12-month average price as compared to the 12-month average price used in 2011.
•	Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (See Note 4 of Notes to Consolidated Financial Statements). Divestitures in 2012 primarily relate to the sale of our holdings in the Barnett Shale and the Arkoma Basin (see Note 2 of Notes to Consolidated Financial Statements).
•	Extensions and discoveries in 2014 reflect 189 Bcfe added for drilled locations and 502 Bcfe added for new proved undeveloped locations. Extensions and discoveries in 2013 reflects 127 Bcfe added for drilled locations and 407 Bcfe 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. Extensions and discoveries in 2012 reflect 225 Bcfe added for drilled locations and 405 Bcfe added for new undeveloped locations. The 2012 extensions and discoveries were primarily in the Williston Basin, Appalachian Basin and Piceance 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, 2014, 2013 and 2012, the average domestic combined natural gas and NGL equivalent price was $4.34, $3.63 and $3.01 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2014, 2013 and 2012 was $83.62, $92.16 and $82.32 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,
	2014				2013
	(Millions)
Future cash inflows	$	26,444			$	24,547
Less:
Future production costs	12,641				12,148
Future development costs	3,426				3,789
Future income tax provisions	2,519				2,147
Future net cash flows	7,858				6,463
Less 10 percent annual discount for estimated timing of cash flows	3,975				3,499
Standardized measure of discounted future net cash inflows	$	3,883			$	2,964
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
	For the years ended December 31,
	2014				2013				2012
	(Millions)
Beginning of year	$	2,964			$	1,949			$	3,591
Sales of oil and gas produced, net of operating costs	(1,324		)		(1,040		)		(778		)
Net change in prices and production costs	303				1,198				(3,601		)
Extensions, discoveries and improved recovery, less estimated future costs	1,761				1,282				1,154
Development costs incurred during year	592				414				333
Changes in estimated future development costs	143				(736		)		50
Purchase of reserves in place, less estimated future costs	147				—				4
Sale of reserves in place, less estimated future costs	(391		)		(3		)		(272		)
Revisions of previous quantity estimates	(536		)		239				(232		)
Accretion of discount	383				225				481
Net change in income taxes	(142		)		(540		)		1,194
Other	(17		)		(24		)		25
Net changes	919				1,015				(1,642		)
End of year	$	3,883			$	2,964			$	1,949

Schedule_II_Valuation_And_Qual

Schedule II - Valuation And Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS	WPX Energy, Inc.
	SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
		Beginning		Charged			Other		Deductions			Ending
		Balance		(Credited)								Balance
				to Costs and
				Expenses
	2014:00:00
	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
	2013:00:00
	Allowance for doubtful accounts—accounts and notes receivable(a)	11		(3		)	—		(1		)	7
	Deferred tax asset valuation allowance(b)	19		80			3		—			102
	2012:00:00
	Allowance for doubtful accounts—accounts and notes receivable(a)	13		(2		)	—		—			11
	Deferred tax asset valuation allowance(b)	16		3			—		—			19
	__________
	(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_Basis_

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
	Description of Business
	Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. 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, storage and related derivatives coupled with the sale of our commodity volumes.
	In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of 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 natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
	Discontinued operations
	On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. 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 Sheets.
	During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin 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 Sheets.
	Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.
	Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
	See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
	Recently Issued Accounting Standards
	In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).
	In May 2014, the FASB issued ASU 2014-09, 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 is effective for annual reporting periods beginning after December 15, 2016, 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 No. 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. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.
	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 natural gas and oil reserves;
	•	assessments of litigation-related contingencies; and
	•	asset retirement obligations.
	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 $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.
	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 except for production equipment which is on the specific identification method. The following table presents a summary of inventories.
		Years ended December 31,
		2014			2013
		(Millions)
	Material, supplies and other	$	43		$	43
	Crude oil production in transit	2			10
	Natural gas in underground storage	—			13
		$	45		$	66
	During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.
	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.
For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
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;
•	the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
•	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 natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas 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, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423 million in 2013 and 2012, respectively, 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, storage and related hedges. The Company also sells natural gas, oil 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 $57 million, $61 million and $46 million in 2014, 2013 and 2012, 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 7).
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.
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.
Foreign exchange
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
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 3).
Description of Business	Description of Business
	Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. 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, storage and related derivatives coupled with the sale of our commodity volumes.
	In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of 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	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 natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
Discontinued operations	Discontinued operations
	On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. 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 Sheets.
	During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin 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 Sheets.
	Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.
	Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
	See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards
	In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).
	In May 2014, the FASB issued ASU 2014-09, 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 is effective for annual reporting periods beginning after December 15, 2016, 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 No. 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. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.
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 natural gas and oil reserves;
	•	assessments of litigation-related contingencies; and
	•	asset retirement obligations.
	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 $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.
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 except for production equipment which is on the specific identification method. The following table presents a summary of inventories.
		Years ended December 31,
		2014			2013
		(Millions)
	Material, supplies and other	$	43		$	43
	Crude oil production in transit	2			10
	Natural gas in underground storage	—			13
		$	45		$	66
	During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.
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.
	For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
	For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
	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;
	•	the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
	•	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 natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas 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, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423 million in 2013 and 2012, respectively, 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, storage and related hedges. The Company also sells natural gas, oil 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 $57 million, $61 million and $46 million in 2014, 2013 and 2012, 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 7).
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.
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.
Foreign exchange	Foreign exchange
	Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
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 3).

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards
	In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).
	In May 2014, the FASB issued ASU 2014-09, 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 is effective for annual reporting periods beginning after December 15, 2016, 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 No. 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. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.

Description_of_Business_Basis_1

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Tables)	12 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Schedule of Inventory, Current [Table Text Block]	The following table presents a summary of inventories.
		Years ended December 31,
		2014		2013
		(Millions)
	Material, supplies and other	$	43	$	43
	Crude oil production in transit	2		10
	Natural gas in underground storage	—		13
		$	45	$	66

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]	Summarized Results of Discontinued Operations
	For the year ended December 31, 2014	Domestic			International			Total
					(Millions)
	Total revenues	$	189		$	163		$	352
	Costs and expenses:
	Lease and facility operating	$	41		$	37		$	78
	Gathering, processing and transportation	70			1			71
	Taxes other than income	16			28			44
	Exploration	—			4			4
	Depreciation, depletion and amortization	11			42			53
	Impairment of assets held for sale	45			—			45
	General and administrative	4			16			20
	Other—net	—			12			12
	Total costs and expenses	187			140			327
	Operating income (loss)	2			23			25
	Interest capitalized	1			—			1
	Investment income and other	6			19			25
	Income (loss) from discontinued operations before income taxes	9			42			51
	Provision (benefit) for income taxes(a)	2			7			9
	Income (loss) from discontinued operations	$	7		$	35		$	42
	__________
	(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	$	178		$	152		$	330
	Costs and expenses:
	Lease and facility operating	$	44		$	37		$	81
	Gathering, processing and transportation	80			3			83
	Taxes other than income	15			24			39
	Exploration	1			7			8
	Depreciation, depletion and amortization	48			34			82
	Impairment of producing properties and costs of acquired unproved reserves	192			3			195
	Gain on sale of Powder River Basin deep rights leasehold	(36		)	—			(36		)
	General and administrative	6			14			20
	Other—net	5			—			5
	Total costs and expenses	355			122			477
	Operating income (loss)	(177		)	30			(147		)
	Interest capitalized	4			—			4
	Investment income and other	4			21			25
	Income (loss) from discontinued operations before income taxes	(169		)	51			(118		)
	Provision (benefit) for income taxes(a)	(62		)	31			(31		)
	Income (loss) from discontinued operations	$	(107	)	$	20		$	(87	)
	__________
	(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.
	For the year ended December 31, 2012	Domestic			International			Total
					(Millions)
	Total revenues	$	180		$	137		$	317
	Costs and expenses:
	Lease and facility operating	$	65		$	32		$	97
	Gathering, processing and transportation	74			2			76
	Taxes other than income	19			24			43
	Gas management, including charges for unutilized pipeline capacity	1			—			1
	Exploration	1			11			12
	Depreciation, depletion and amortization	62			27			89
	Impairment of producing properties and costs of acquired unproved reserves	102			—			102
	Gain on sale of Barnett Shale and Arkoma Basin holdings	(38		)	—			(38		)
	General and administrative	10			14			24
	Other—net	(1		)	—			(1		)
	Total costs and expenses	295			110			405
	Operating income (loss)	(115		)	27			(88		)
	Interest capitalized	6			—			6
	Investment income and other	4			27			31
	Income (loss) from discontinued operations before income taxes	(105		)	54			(51		)
	Provision (benefit) for income taxes	(38		)	24			(14		)
Income (loss) from discontinued operations	$	(67	)	$	30		$	(37	)
Summarized Results of Discontinued Operations	.
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block]	Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
	December 31, 2014	Domestic			International			Total
					(Millions)
	Assets classified as held for sale
	Current assets:
	Cash and cash equivalents	$	—		$	29		$	29
	Accounts receivable	—			25			25
	Inventories	1			7			8
	Other	—			14			14
	Total current assets	1			75			76
	Investments	18			134			152
	Properties and equipment (successful efforts method of accounting)(a)	132			445			577
	Less—accumulated depreciation, depletion and amortization	(10		)	(228		)	(238		)
	Properties and equipment, net	122			217			339
	Other noncurrent assets	—			6			6
	Total assets classified as held for sale—discontinued operations	$	141		$	432		$	573
	Total assets classified as held for sale—continuing operations (Note 4)	200			—			200
	Total assets classified as held for sale on the Consolidated Balance Sheets	$	341		$	432		$	773
	Liabilities associated with assets held for sale
	Current liabilities:
	Accounts payable	$	—		$	34		$	34
	Accrued and other current liabilities	3			23			26
	Total current liabilities	3			57			60
	Deferred income taxes	—			13			13
	Long-term debt	—			2			2
	Asset retirement obligations	45			7			52
	Other noncurrent liabilities	—			3			3
	Total liabilities associated with assets held for sale—discontinued operations	$	48		$	82		$	130
	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	$	50		$	82		$	132
	__________
	(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.
	December 31, 2013	Domestic			International			Total
					(Millions)
	Assets classified as held for sale
	Current assets:
	Cash and cash equivalents	$	—		$	51		$	51
	Accounts receivable	—			18			18
	Inventories	1			5			6
	Other	—			17			17
	Total current assets	1			91			92
	Investments	17			125			142
	Properties and equipment (successful efforts method of accounting)	166			360			526
	Less—accumulated depreciation, depletion and amortization	—			(194		)	(194		)
	Properties and equipment, net	166			166			332
	Total assets classified as held for sale—discontinued operations(a)	$	184		$	382		$	566
	Total assets classified as held for sale—continuing operations (Note 4)(a)	148			—			148
	Total assets classified as held for sale on the Consolidated Balance Sheets(a)	$	332		$	382		$	714
	Liabilities associated with assets held for sale
	Current liabilities:
	Accounts payable	$	—		$	18		$	18
	Accrued and other current liabilities	3			20			23
	Total current liabilities	3			38			41
	Deferred income taxes	—			12			12
	Long-term debt	—			5			5
	Asset retirement obligations	47			4			51
	Total liabilities associated with assets held for sale—discontinued operations(a)	$	50		$	59		$	109
	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(a)	$	52		$	59		$	111
	__________
	(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.

Earnings_Loss_Per_Common_Share1

Earnings (Loss) Per Common Share from Continuing Operations (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014		2013			2012
		(Millions, except per-share amounts)
	Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	129	$	(1,092	)	$	(174	)
	Basic weighted-average shares	202.7		200.5			198.8
	Effect of dilutive securities(a):
	Nonvested restricted stock units and awards	2.7
	Stock options	0.9
	Diluted weighted-average shares	206.3		200.5			198.8
	Earnings (loss) per common share from continuing operations:
	Basic	$	0.63	$	(5.45	)	$	(0.87	)
	Diluted	$	0.62	$	(5.45	)	$	(0.87	)
	__________
	(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options 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.
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, 2014, 2013 and 2012 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.
		2014		2013			2012
	Options excluded (millions)	1.4		0.4			1.3
	Weighted-average exercise price of options excluded	$	18.42	$	20.24		$	18.17
	Exercise price range of options excluded	$16.46 - $21.81		$20.21  - $20.97			$16.46  - $20.97
	Fourth quarter weighted-average market price	$	15.96	$	19.97		$	16.15

Asset_Sales_Impairments_and_Ex1

Asset Sales, Impairments and Exploration Expenses (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014		2013		2012
		(Millions)
	Impairment of producing properties and costs of acquired unproved reserves(a)	$	20	$	860	$	123
	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,
		2014		2013		2012
		(Millions)
	Geologic and geophysical costs	$	11	$	18	$	12
	Impairments of exploratory area well costs and dry hole costs	88		3		1
	Unproved leasehold property impairments, amortization and expiration	74		402		58
	Total exploration expenses	$	173	$	423	$	71

Properties_and_Equipment_Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Properties and Equipment, at Cost	Properties and equipment is carried at cost and consists of the following:
		Estimated		December 31,
		Useful
		Life(a)
		(Years)		2014				2013
				(Millions)
	Proved properties	(b)		$	10,386			$	10,955
	Unproved properties	(c)		394				316
	Gathering, processing and other facilities	15-25		251				209
	Construction in progress	(c)		541				353
	Other	Mar-40		181				178
	Total properties and equipment, at cost			11,753				12,011
	Accumulated depreciation, depletion and amortization			(4,911		)		(5,251		)
	Properties and equipment—net			$	6,842			$	6,760
	__________
	(a)	Estimated useful lives are presented as of December 31, 2014.
	(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 2014 and 2013 is presented below.
		2014				2013
		(Millions)
	Balance, January 1	$	308			$	261
	Liabilities incurred	19				11
	Liabilities settled	(2		)		(1		)
	Liabilities associated with assets sold	(65		)		—
	Estimate revisions	(78		)		17
	Accretion expense(a)	19				20
	Balance, December 31	$	201			$	308
	Amount reflected as current	$	3			$	3
	__________
	(a)	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Accounts_Payable_and_Accrued_a1

Accounts Payable and Accrued and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Accounts Payable	Accounts Payable
		December 31,
		2014		2013
		(Millions)
	Trade	$	215	$	208
	Accrual for capital expenditures	313		225
	Royalties	125		130
	Cash overdrafts	—		35
	Other	59		36
		$	712	$	634
Accrued and Other Current Liabilities	Accrued and other current liabilities
		December 31,
		2014		2013
		(Millions)
	Taxes other than income taxes	$	41	$	41
	Accrued interest	53		43
	Compensation and benefit related accruals	55		52
	Other, including other loss contingencies	28		31
		$	177	$	167

Debt_and_Banking_Arrangements_

Debt and Banking Arrangements (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	As of the indicated dates, our debt consisted of the following:
		December 31,
		2014 (a)		2013 (a)
		(Millions)
	5.250% Senior Notes due 2017	$	400	$	400
	6.000% Senior Notes due 2022	1,100		1,100
	5.250% Senior Notes due 2024	500		—
	Credit facility agreement	280		410
	Other	1		2
	Total debt	$	2,281	$	1,912
	Less: Current portion of long-term debt	1		1
	Total long-term debt	$	2,280	$	1,911
	__________
	(a)	Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

Provision_Benefit_for_Income_T1

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes from Continuing Operations	The provision (benefit) for income taxes from continuing operations includes:
		Years Ended December 31,
		2014			2013			2012
		(Millions)
	Provision (benefit):
	Current:
	Federal	$	(3	)	$	(29	)	$	49
	State	1			1			4
		(2		)	(28		)	53
	Deferred:
	Federal	76			(549		)	(125		)
	State	1			(47		)	(12		)
		77			(596		)	(137		)
	Total provision (benefit)	$	75		$	(624	)	$	(84	)
Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate	Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
		Years Ended December 31,
		2014			2013			2012
		(Millions)
	Provision (benefit) at statutory rate	$	71		$	(604	)	$	(90	)
	Increases (decreases) in taxes resulting from:
	State income taxes (net of federal benefit)	3			(111		)	(6		)
	State income tax change in valuation allowance (net of federal benefit)	(1		)	80			—
	State income tax legislation change (net of federal benefit)	9			—			—
	Effective state income tax rate change (net of federal benefit)	(9		)	(3		)	—
	Alternative minimum tax credits	—			—			11
	Other	2			14			1
	Provision (benefit) for income taxes	$	75		$	(624	)	$	(84	)
Significant Components of Deferred Tax Liabilities and Deferred Tax Assets	Significant components of deferred tax liabilities and deferred tax assets are as follows:
		December 31,
		2014			2013
		(Millions)
	Deferred tax liabilities:
	Properties and equipment	$	738		$	961
	Derivatives, net	170			—
	Other, net	17			23
	Total deferred tax liabilities	925			984
	Deferred tax assets:
	Accrued liabilities and other	124			176
	Alternative minimum tax credits	60			76
	Loss carryovers	51			83
	Derivatives, net	—			21
	Other, net	32			—
	Total deferred tax assets	267			356
	Less: valuation allowance	114			99
	Total net deferred tax assets	153			257
	Net deferred tax liabilities	$	772		$	727

Contingent_Liabilities_and_Com1

Contingent Liabilities and Commitments (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitment Under Contracts	Our commitments under these contracts as of December 31, 2014 are as follows:
		(Millions)
	2015	$	177
	2016	162
	2017	149
	2018	138
	2019	126
	Thereafter	389
	Total	$	1,141
Future Minimum Annual Rentals Under Noncancelable Operating Leases	Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:
		(Millions)
	2015	$	37
	2016	32
	2017	11
	2018	7
	2019	7
	Thereafter	15
	Total	$	109

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock Option Activity and Related Information	The following summary reflects stock option activity and related information for the year ended December 31, 2014.
		WPX Plan
	Stock Options	Options			Weighted-				Aggregate
					Average				Intrinsic
					Exercise				Value
					Price
		(Millions)							(Millions)
	Outstanding at December 31, 2013(a)	4.1			$	13.27			$	29
	Granted	0.4			$	19.03
	Exercised	(1.3	)		$	11.11
	Forfeited	(0.1	)		$	15.39
	Outstanding at December 31, 2014(a)	3.1			$	14.8			$	2
	Exercisable at December 31, 2014	2.7			$	14.26			$	2
	__________
	(a)	Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.
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, 2014.
		WPX Plan
		Stock Options Outstanding									Stock Options Exercisable
	Range of Exercise Prices	Options			Weighted-				Weighted-		Options		Weighted-		Weighted-
					Average				Average				Average		Average
					Exercise				Remaining				Exercise		Remaining
					Price				Contractual				Price		Contractual
									Life						Life
		(Millions)							(Years)		(Millions)				(Years)
	$ 6.02 to $10.68	0.5			$	7.59			2.8		0.5		$	7.59	2.8
	$ 11.32 to $13.46	0.6			$	11.82			4		0.6		$	11.82	4
	$14.41 to $18.23	1.5			$	16.39			6.1		1.2		$	16.36	5.6
	$19.95 to $21.81	0.5			$	20.61			5		0.4		$	20.24	3.2
	Total	3.1			$	14.8			5		2.7		$	14.26	4.4
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
		2014				2013				2012
	Weighted-average grant date fair value of options granted	$	18.94			$	6.04			$	7.79
	Weighted-average assumptions:
	Dividend yield	—				—				—
	Volatility	43		%		42.8		%		43.8		%
	Risk-free interest rate	1.85		%		1.06		%		1.17		%
	Expected life (years)	5.9				6				6
Summary of Nonvested Restricted Stock Unit Activity and Related Information	The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.
		WPX Plan
	Restricted Stock Units	Shares			Weighted-
					Average
					Fair Value(a)
		(Millions)
	Nonvested at December 31, 2013	5.2			$	16.97
	Granted	2.5			$	18.37
	Forfeited	(0.7	)		$	16.92
	Vested	(1.9	)		$	16.92
	Nonvested at December 31, 2014	5.1			$	17.58
	__________
	(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
		2014				2013				2012
	Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.37			$	14.97			$	17.35
	Total fair value of restricted stock units vested during the year (millions)	$	33			$	18			$	14

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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 and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
		31-Dec-14											31-Dec-13
		Level 1		Level 2				Level 3			Total		Level 1		Level 2		Level 3		Total
				(Millions)											(Millions)
	Energy derivative assets	$	14	$	517			$	5		$	536	$	30	$	26	$	1	$	57
	Energy derivative liabilities	$	32	$	10			$	—		$	42	$	83	$	38	$	1	$	122
	Total debt(a)	$	—	$	2,218			$	—		$	2,218	$	—	$	1,938	$	—	$	1,938
	__________
	(a)	The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, 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,
		2014		2013				2012
		(Millions)
	Beginning balance	$	—	$	(1	)		$	1
	Realized and unrealized gains (losses):
	Included in income (loss) from continuing operations	5		(2		)		3
	Included in other comprehensive income (loss)	—		—				—
	Purchases, issuances, and settlements	—		3				(5		)
	Transfers out of Level 3	—		—				—
	Ending balance	$	5	$	—			$	(1	)
	Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	5	$	(1	)		$	(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,
		2014 (a)				2013 (b)					2012 (c)
		(Millions)
	Impairments:
	Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)	$	20			$	1,055				$	225
	Unproved leasehold	—				317					—
	Equity method investment (Note 4)	—				20					—
		$	20			$	1,392				$	225
	__________
	(a)	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.
	(b)	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. 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.
	(c)	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:
	•	$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. 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.
	•	$48 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 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

Derivatives_and_Concentration_1

Derivatives and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2014
DerivativeGainLoss [Line Items]
DerivativeGainLoss [Table Text Block]	The following table presents the net gain (loss) related to our energy commodity derivatives.
		Years Ended December 31,
		2014				2013				2012
	Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515			$	(57	)		$	66
	Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)		(67		)		12
	Net gain (loss) on derivatives not designated as hedges	$	434			$	(124	)		$	78
	__________
	(a)	Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
	(b)	Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.
	The following table presents the net gain (loss) related to our energy commodity derivatives.
		Years Ended December 31,
		2014				2013				2012
	Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515			$	(57	)		$	66
	Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)		(67		)		12
	Net gain (loss) on derivatives not designated as hedges	$	434			$	(124	)		$	78
	__________
	(a)	Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
	(b)	Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.
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, 2014.
	Commodity		Period		Contract Type (a)		Location		Notional Volume (b)			Weighted Average
												Price (c)
	Natural Gas
	Natural Gas		2015		Fixed Price Swaps		Henry Hub		(442	)		$	4.1
	Natural Gas		2015		Costless Collars		Henry Hub		(50	)		$ 4.00 - 4.50
	Natural Gas		2015		Basis Swaps		NGPL		(13	)		$	(0.16	)
	Natural Gas		2015		Basis Swaps		Rockies		(150	)		$	(0.11	)
	Natural Gas		2015		Basis Swaps		San Juan		(85	)		$	(0.10	)
	Natural Gas		2015		Basis Swaps		SoCal		(20	)		$	0.18
	Natural Gas		2016		Fixed Price Swaps		Henry Hub		(200	)		$	3.98
	Natural Gas		2016		Swaptions		Henry Hub		(90	)		$	4.23
	Natural Gas		2017		Swaptions		Henry Hub		(65	)		$	4.19
	Crude Oil
	Crude Oil		2015		Fixed Price Swaps		WTI		(20,236	)		$	94.88
	Crude Oil		2015		Swaptions		WTI		(882	)		$	97.29
	Crude Oil		2016		Swaptions		WTI		(5,250	)		$	97.55
	__________
	(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, 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 grant the counterparty the option to enter into future swaps with us.
	(b)	Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
	(c)	The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.
	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 storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. 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		2015		Basis Swaps		Multiple		(3	)
	Natural Gas		2015		Index		Multiple		(118	)
	Natural Gas		2016		Index		Multiple		(70	)
	Natural Gas		2017		Index		Multiple		(70	)
	Natural Gas		2018+		Index		Multiple		(379	)
	__________
	(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, storage and asset management agreements.
	(c)	Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/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,
		2014								2013
		Assets				Liabilities				Assets				Liabilities
		(Millions)
	Derivatives related to production not designated as hedging instruments	$	517			$	10			$	26			$	39
	Derivatives related to physical marketing agreements not designated as hedging instruments	19				32				31				83
	Total derivatives not designated as hedging instruments	$	536			$	42			$	57			$	122
Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues	The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.
		Years Ended												Classification
		December 31,
		2014				2013				2012
						(Millions)
	Net gain recognized in other comprehensive income (loss) (effective portion)	$	—			$	—			$	90			AOCI
	Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	—			$	5			$	434			Revenues
	__________
	(a)	Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
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
	31-Dec-14	(Millions)
	Derivative assets with right of offset or master netting agreements	$	536			$	(25	)		$	—			$	511
	Derivative liabilities with right of offset or master netting agreements	$	(42	)		$	25			$	17			$	—
	31-Dec-13
	Derivative assets with right of offset or master netting agreements	$	57			$	(50	)		$	—			$	7
	Derivative liabilities with right of offset or master netting agreements	$	(122	)		$	50			$	52			$	(20	)
	__________
	(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:
		2014				2013
		(Millions)
	Receivables by product or service:
	Sale of natural gas, crude and related products and services	$	340			$	339
	Joint interest owners	106				168
	Other	13				11
	Total	$	459			$	518
Gross and Net Credit Exposure from Derivative Contracts	The gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:
	Counterparty Type	Gross Total				Net Total
		(Millions)
	Gas and electric utilities, integrated oil and gas companies, and other	$	4			$	4
	Financial institutions (Investment Grade) (a)	533				508
		537				512
	Credit reserves	(1		)		(1		)
	Credit exposure from derivatives	$	536			$	511
	__________
	(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, 2014
Quarterly Financial Data Adjustments [Line Items]
Summarized Quarterly Financial Data	Summarized quarterly financial data are as follows:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(Millions, except per-share amounts)
	2014
	Revenues	$	894		$	727		$	747		$	1,125
	Operating costs and expenses	$	783		$	659		$	570		$	656
	Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
	Income (loss) from discontinued operations	19			11			20			(8		)
	Net income (loss)	$	19		$	(133	)	$	66		$	219
	Amounts attributable to WPX Energy, Inc.:
	Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
	Income (loss) from discontinued operations	18			9			16			(8		)
	Net income (loss)	$	18		$	(135	)	$	62		$	219
	Basic earnings (loss) per common share:
	Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.11
	Income (loss) from discontinued operations	0.09			0.05			0.07			(0.03		)
	Net income (loss)	$	0.09		$	(0.66	)	$	0.3		$	1.08
	Diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.1
	Income (loss) from discontinued operations	0.09			0.05			0.07			(0.04		)
	Net income (loss)	$	0.09		$	(0.66	)	$	0.3		$	1.06
	2013
	Revenues	$	552		$	722		$	581		$	576
	Operating costs and expenses	$	634		$	612		$	621		$	1,024
	Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(890	)
	Income (loss) from discontinued operations	2			16			(11		)	(94		)
	Net income (loss)	$	(113	)	$	22		$	(116	)	$	(984	)
	Amounts attributable to WPX Energy, Inc.:
	Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(878	)
	Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
	Net income (loss)	$	(116	)	$	18		$	(114	)	$	(973	)
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.57	)	$	0.03		$	(0.52	)	$	(4.37	)
	Income (loss) from discontinued operations	(0.01		)	0.06			(0.05		)	(0.48		)
	Net income (loss)	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)
Quarterly Financial Data Adjustments [Table Text Block]	Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter (a)			Quarter
		(Millions, except per-share amounts)
		(Increase, (Decrease))
	2014
	Revenues	$	(93	)	$	(87	)	$	47		N/A
	Operating costs and expenses	$	(62	)	$	62		$	31		N/A
	Income (loss) from continuing operations	$	(19	)	$	(11	)	$	(15	)	N/A
	Income (loss) from discontinued operations	19			11			15			N/A
	Net income (loss)	$	—		$	—		$	—		N/A
	Amounts attributable to WPX Energy, Inc.:
	Income (loss) from continuing operations	$	(18	)	$	(9	)	$	(16	)	N/A
	Income (loss) from discontinued operations	18			9			16			N/A
	Net income (loss)	$	—		$	—		$	—		N/A
	Basic earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
	Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
	Net income (loss)	$	—		$	—		$	—		N/A
	Diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
	Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
	Net income (loss)	$	—		$	—		$	—		N/A
	2013
	Revenues	$	(79	)	$	(93	)	$	35		$	(81	)
	Operating costs and expenses	$	(76	)	$	(77	)	$	22		$	(74	)
	Income (loss) from continuing operations	$	(2	)	$	(16	)	$	3		$	94
	Income (loss) from discontinued operations	2			16			(3		)	(94		)
	Net income (loss)	$	—		$	—		$	—		$	—
	Amounts attributable to WPX Energy, Inc.:
	Income (loss) from continuing operations	$	1		$	(12	)	$	9		$	95
	Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
	Net income (loss)	$	—		$	—		$	—		$	—
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	0.01		$	(0.06	)	$	0.01		$	0.48
	Income (loss) from discontinued operations	(0.01		)	0.06			(0.01		)	(0.48		)
	Net income (loss)	$	—		$	—		$	—		$	—
	__________
	(a)	Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Capitalized Costs	Capitalized Costs
		As of December 31,
		2014				2013
		(Millions)
	Proved Properties	$	10,717			$	11,132
	Unproved properties	394				324
		11,111				11,456
	Accumulated depreciation, depletion and amortization and valuation provisions	(4,698		)		(5,070		)
	Net capitalized costs	$	6,413			$	6,386
Cost Incurred	Cost Incurred
		For the years ended December 31,
		2014				2013				2012
		(Millions)
	Acquisition	$	294			$	57			$	111
	Exploration	92				104				23
	Development	1,376				939				1,130
		$	1,762			$	1,100			$	1,264
Results of Operations	Results of Operations
		For the years ended December 31,
		2014				2013				2012
		(Millions)
	Revenues:
	Natural gas sales	$	1,002			$	896			$	1,193
	Oil and condensate sales	724				534				376
	Natural gas liquid sales	205				228				297
	Net gain (loss) on derivatives not designated as hedges	515				(57		)		66
	Other revenues	8				6				7
	Total revenues	2,454				1,607				1,939
	Costs:
	Lease and facility operating	244				227				202
	Gathering, processing and transportation	328				350				434
	Taxes other than income	126				102				68
	Exploration	173				423				71
	Depreciation, depletion and amortization	810				858				884
	Impairment of certain proved properties	15				772				48
	Impairment of costs of acquired unproved reserves	5				88				75
	Loss on sale of working interests in the Piceance Basin	196				—				—
	General and administrative	264				262				259
	Other (income) expense	12				12				16
	Total costs	2,173				3,094				2,057
	Results of operations	281				(1,487		)		(118		)
	Provision (benefit) for income taxes	103				(543		)		(43		)
	Exploration and production net income (loss)	$	178			$	(944	)		$	(75	)
Proved Reserves
		Natural Gas (Bcf)			Oil (MMBbls)			NGLs (MMBbls)			All Products (Bcfe)
	Proved reserves at December 31, 2011	3,982.90			47.1			134			5,070.10
	Revisions	(404.8	)		5.6			(21.1	)		(498.6	)
	Purchases	5.8			—			—			5.8
	Divestitures	(217.0	)		(0.3	)		(1.0	)		(224.8	)
	Extensions and discoveries	409.2			28.5			8.9			633.8
	Production	(407.0	)		(4.4	)		(10.4	)		(495.8	)
	Proved reserves at December 31, 2012	3,369.10			76.5			110.4			4,490.50
	Revisions	308.3			3.5			(25.4	)		177.2
	Divestitures	(0.2	)		—			—			(0.5	)
	Extensions and discoveries	312			28.8			8.1			533.8
	Production	(359.4	)		(5.9	)		(7.4	)		(439.4	)
	Proved reserves at December 31, 2013	3,629.80			102.9			85.7			4,761.60
	Revisions	(198.3	)		(7.7	)		(13.4	)		(324.8	)
	Purchases	6			4.2			0.8			36.5
	Divestitures	(314.6	)		(1.8	)		(8.5	)		(376.6	)
	Extensions and discoveries	362.1			42.4			12.5			691.3
	Production	(335.4	)		(9.2	)		(6.3	)		(428.4	)
	Proved reserves at December 31, 2014	3,149.60			130.8			70.8			4,359.60
	Proved developed reserves:
	December 31, 2012	2,170.70			23.7			64.9			2,702.60
	December 31, 2013	2,265.20			36.8			48.6			2,777.70
	December 31, 2014	2,090.00			60			43.9			2,713.80
	Proved undeveloped reserves:
	31-Dec-12	1,198.40			52.8			45.5			1,787.90
	31-Dec-13	1,364.60			66.1			37.1			1,983.90
	31-Dec-14	1,059.60			70.8			26.9			1,645.80
	__________
	(a)	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
Standardized Measure of Discounted Future Net Cash Flows	Standardized Measure of Discounted Future Net Cash Flows
		As of December 31,
		2014				2013
		(Millions)
	Future cash inflows	$	26,444			$	24,547
	Less:
	Future production costs	12,641				12,148
	Future development costs	3,426				3,789
	Future income tax provisions	2,519				2,147
	Future net cash flows	7,858				6,463
	Less 10 percent annual discount for estimated timing of cash flows	3,975				3,499
	Standardized measure of discounted future net cash inflows	$	3,883			$	2,964
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,
		2014				2013				2012
		(Millions)
	Beginning of year	$	2,964			$	1,949			$	3,591
	Sales of oil and gas produced, net of operating costs	(1,324		)		(1,040		)		(778		)
	Net change in prices and production costs	303				1,198				(3,601		)
	Extensions, discoveries and improved recovery, less estimated future costs	1,761				1,282				1,154
	Development costs incurred during year	592				414				333
	Changes in estimated future development costs	143				(736		)		50
	Purchase of reserves in place, less estimated future costs	147				—				4
	Sale of reserves in place, less estimated future costs	(391		)		(3		)		(272		)
	Revisions of previous quantity estimates	(536		)		239				(232		)
	Accretion of discount	383				225				481
	Net change in income taxes	(142		)		(540		)		1,194
	Other	(17		)		(24		)		25
	Net changes	919				1,015				(1,642		)
	End of year	$	3,883			$	2,964			$	1,949

Description_of_Business_Basis_2

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Line Items]
Buyout of Transportation Agreement	$9	$14
Natural Gas Storage Revenue		4
Equity Method Investment, Ownership Percentage		69.00%
Share Based Compensation Arrangement By Share Based Payment Award Minimum Exercisable Period For Stock Options		3 years
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%
Hedge gains realized from natural gas revenues			5	423
Charges for unutilized transportation capacity included in gas management expenses		57	61	46
Projects with construction periods, minimum		3 months
Total estimated project cost		1
Share Based Compensation Arrangement By Share Based Payment Award Award Term		10 years
Natural Gas
Accounting Policies [Line Items]
Inventory writedowns		1	1	11
Domestic Segment
Accounting Policies [Line Items]
Restricted cash related to escrow accounts to settle agreement	21	6	21
International
Accounting Policies [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds		$294

Description_of_Business_Basis_3

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Inventory [Line Items]
Material Supplies And Other	$43	$43
Crude Inventory In Transit	2	10
Energy Related Inventory, Natural Gas in Storage	0	13
Inventories	$45	$66

Discontinued_Operations_Additi

Discontinued Operations - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets			$38
Equity Method Investment, Ownership Percentage	69.00%
Impairment of Oil and Gas Properties, Disposal Group	45	195	102
Contractual Obligation	1,141
Noncontrolling interests in consolidated subsidiaries	109	101
Proceeds from Divestiture of Businesses			306
Domestic
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	155
Impairment of Oil and Gas Properties, Disposal Group	45
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities	65	36	18
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities	11	3	20
International
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets			0
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	294
Impairment of Oil and Gas Properties, Disposal Group	0	3	0
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities	65	56	50
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities	85	43	56
Gathering and Treating [Member] | Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation	128
Capacity [Member] | Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation	172
Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets				$40

Discontinued_Operations_Summar

Discontinued Operations - Summarized Results of Discontinued Operations (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred Tax Asset, Parent's Basis in Discontinued Operation	$18								$18
DeferredForeignIncomeTaxExpenseBenefit-Argentina											10
Total revenues									352		330		317
Disposal Group, Including Discontinued Operation, Lease Operating Expense									78		81		97
Gathering, processing and transportation									71		83		76
Disposal Group, Including Discontinued Operation Taxes other than income									44		39		43
GasManagementExpenseDisposalGroup													1
Exploration									4		8		12
Depreciation, depletion and amortization									53		82		89
Impairment of Oil and Gas Properties, Disposal Group									45		195		102
Gain on sale of Powder River Basin deep rights leasehold											-36
Gain (Loss) on Disposition of Assets													-38
General and administrative									20		20		24
Other—net									12		5		-1
Total costs and expenses									327		477		405
Operating income (loss)									25		-147		-88
Disposal Group including Discontinued Operation Interest Costs Capitalized									1		4		6
Disposal Group Including Discontinued Operation Investment Income									25		25		31
Disposal Group Including Discontinued Operation Income before Tax									51		-118		-51
Discontinued Operation, Tax Effect of Discontinued Operation									9		-31		-14
Income (loss) from discontinued operations	-8	20	11	19	-94	-11	16	2	42		-87		-37
Domestic
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									189		178		180
Disposal Group, Including Discontinued Operation, Lease Operating Expense									41		44		65
Gathering, processing and transportation									70		80		74
Disposal Group, Including Discontinued Operation Taxes other than income									16		15		19
GasManagementExpenseDisposalGroup													1
Exploration									0		1		1
Depreciation, depletion and amortization									11		48		62
Impairment of Oil and Gas Properties, Disposal Group									45		192		102
Gain on sale of Powder River Basin deep rights leasehold											-36
Gain (Loss) on Disposition of Assets													-38
General and administrative									4		6		10
Other—net									0		5		-1
Total costs and expenses									187		355		295
Operating income (loss)									2		-177		-115
Disposal Group including Discontinued Operation Interest Costs Capitalized									1		4		6
Disposal Group Including Discontinued Operation Investment Income									6		4		4
Disposal Group Including Discontinued Operation Income before Tax									9		-169		-105
Discontinued Operation, Tax Effect of Discontinued Operation									2		-62		-38
Income (loss) from discontinued operations									7		-107		-67
International
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									163		152		137
Disposal Group, Including Discontinued Operation, Lease Operating Expense									37		37		32
Gathering, processing and transportation									1		3		2
Disposal Group, Including Discontinued Operation Taxes other than income									28		24		24
GasManagementExpenseDisposalGroup													0
Exploration									4		7		11
Depreciation, depletion and amortization									42		34		27
Impairment of Oil and Gas Properties, Disposal Group									0		3		0
Gain on sale of Powder River Basin deep rights leasehold											0
Gain (Loss) on Disposition of Assets													0
General and administrative									16		14		14
Other—net									12		0		0
Total costs and expenses									140		122		110
Operating income (loss)									23		30		27
Disposal Group including Discontinued Operation Interest Costs Capitalized									0		0		0
Disposal Group Including Discontinued Operation Investment Income									19		21		27
Disposal Group Including Discontinued Operation Income before Tax									42		51		54
Discontinued Operation, Tax Effect of Discontinued Operation									7	[1]	31	[2]	24
Income (loss) from discontinued operations									$35		$20		$30
[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]	(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.

Discontinued_Operations_Discon

Discontinued Operations Discontinued Operations- Balance Sheet Disclosures by Disposal Groups (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
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		$51
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net	25		18
Disposal Group, Including Discontinued Operation, Inventory	8		6
Disposal Group, Including Discontinued Operation, Other Assets, Current	14		17
Disposal Group Assets, Current	76		92
Disposal Group, Including Discontinued Operation, Investment	152		142
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	577		526
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization	-238		-194
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net (Deprecated 2014-01-31)	339		332
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent	6
Disposal Group, Including Discontinued Operation, Assets	573		566	[1]
Assets Held for Sale, Continuing Operations	200		148	[1]
Assets of disposal group classified as held for sale	773		714	[1]
Disposal Group, Including Discontinued Operation, Accounts Payable	34		18
Disposal Group, Including Discontinued Operation, Accrued Liabilities	26		23
Disposal Group Liabilities, Current	60		41
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities	13		12
long term debt noncurrent disposal group	2		5
Disposal Group Asset Retirement Obligation Noncurrent	52		51
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent	3
Disposal Group, Including Discontinued Operation, Liabilities	130		109	[1]
Liabilities of Disposal Group in Continuing Operations	2		2
Liabilities of disposal group associated with assets held for sale	132		111	[1]
International
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities of Disposal Group in Continuing Operations			0
Continuing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets Held for Sale, Continuing Operations	200		148	[1]
Liabilities of Disposal Group in Continuing Operations			2
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	29		51
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net	25		18
Disposal Group, Including Discontinued Operation, Inventory	7		5
Disposal Group, Including Discontinued Operation, Other Assets, Current	14		17
Disposal Group Assets, Current	75		91
Disposal Group, Including Discontinued Operation, Investment	134		125
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	445		360
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization	-228		-194
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net (Deprecated 2014-01-31)	217		166
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent	6
Disposal Group, Including Discontinued Operation, Assets	432		382	[1]
Assets Held for Sale, Continuing Operations	0		0	[1]
Assets of disposal group classified as held for sale	432		382	[1]
Disposal Group, Including Discontinued Operation, Accounts Payable	34		18
Disposal Group, Including Discontinued Operation, Accrued Liabilities	23		20
Disposal Group Liabilities, Current	57		38
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities	13		12
long term debt noncurrent disposal group	2		5
Disposal Group Asset Retirement Obligation Noncurrent	7		4
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent	3
Disposal Group, Including Discontinued Operation, Liabilities	82		59	[1]
Liabilities of Disposal Group in Continuing Operations	0
Liabilities of disposal group associated with assets held for sale	82		59	[1]
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		0
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net	0		0
Disposal Group, Including Discontinued Operation, Inventory	1		1
Disposal Group, Including Discontinued Operation, Other Assets, Current	0		0
Disposal Group Assets, Current	1		1
Disposal Group, Including Discontinued Operation, Investment	18		17
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	132	[2]	166
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization	-10		0
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net (Deprecated 2014-01-31)	122		166
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent	0
Disposal Group, Including Discontinued Operation, Assets	141		184	[1]
Assets of disposal group classified as held for sale	341		332	[1]
Disposal Group, Including Discontinued Operation, Accounts Payable	0		0
Disposal Group, Including Discontinued Operation, Accrued Liabilities	3		3
Disposal Group Liabilities, Current	3		3
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities	0		0
long term debt noncurrent disposal group	0		0
Disposal Group Asset Retirement Obligation Noncurrent	45		47
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent	0
Disposal Group, Including Discontinued Operation, Liabilities	48		50	[1]
Liabilities of Disposal Group in Continuing Operations	2
Liabilities of disposal group associated with assets held for sale	$50		$52	[1]
[1]	(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.
[2]	(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

Earnings_Loss_Per_Common_Share2

Earnings (Loss) Per Common Share from Continuing Operations (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$227	$46	($144)	$0	($878)	($105)	$6	($115)	$129	($1,092)		($174)
Basic weighted-average shares									202.7	200.5		198.8
Diluted weighted-average shares									206.3	200.5	[1]	198.8	[1]
Earnings (loss) per common share from continuing operations:
Basic (in dollars per share)	$1.11	$0.23	($0.71)	$0					$0.63	($5.45)		($0.87)
Diluted (in dollars per share)	$1.10	$0.23	($0.71)	$0					$0.62	($5.45)		($0.87)
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									2.7	2.5		1.1
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									0.9	1.9		1
[1]	For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options 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.

Earnings_Loss_Per_Common_Share3

Earnings (Loss) Per Common Share from Continuing Operations - Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Option (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Stock Options Outstanding Excluded From Computation Of Weighted Average Stock Option [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1.4	0.4	1.3
Weighted-average exercise price of options excluded	$18.42	$20.24	$18.17
Exercise price range of options excluded, lower limit	$16.46	$20.21	$16.46
Exercise price range of options excluded, upper limit	$21.81	$20.97	$20.97
Fourth quarter weighted-average market price	$15.96	$19.97	$16.15

Asset_Sales_Impairments_and_Ex2

Asset Sales, Impairments and Exploration Expenses - Significant Adjustments with Domestic Operations (Detail) (USD $)	3 Months Ended		12 Months Ended						3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2014	Mar. 31, 2015
			Well
			acre
			MMcf
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets			$374		$49		$310
Percentage Ownership Of Incentive Distribution Rights			10.00%						10.00%
Proved Developed and Undeveloped Reserves, Net			300,000						300,000
Percentage of proved reserves attributed to sale of producing assets			6.00%
Production Related To The Sale Of Working Interests			70
Impairment of producing properties and costs of acquired unproved reserves			20	[1]	860	[1]	123	[1]
Impairment Equity method investment			0		20	[2]	0
Gain on sale of Powder River Basin deep rights leasehold					36
Loss On Sale Of Working Interests	1	195	196		0		0
Property, Plant and Equipment, Net			6,842		6,760				6,842
Asset Retirement Obligation			201		308		261		201
Oil and Gas Property, Deep Rights, Acres Sold During Period			46,700
Production related to sale			50
Proved developed wells related to sale			63
Oil and Gas Delivery Commitments and Contracts, Daily Production			260
Cost Of Oil And Gas Services			24
Other Property
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Impairment Charge			9
Legacy [Member] | Piceance Basin [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets			325
Pennsylvania [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets									300
Post Closing [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets			329
Marcellus Shale
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property, Plant and Equipment, Net			200						200
Asset Retirement Obligation			2						2
Subsequent Event
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Gain (Loss) on Disposition of Proved Property										$75
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.
[2]	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. 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_Ex3

Asset Sales, Impairments and Exploration Expenses (Details) (USD $)	12 Months Ended						3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Impairment Costs [Line Items]
Asset impairment charges	$87		$1,200
Impairment of producing properties and costs of acquired unproved reserves	20	[1]	860	[1]	123	[1]
Gain on sale of Powder River Basin deep rights leasehold			36
Dry hole costs	88		3		1
Unproved leasehold property impairment, amortization and expiration	74		402		58
Investment income, impairment of equity method investment and other	1		-19		1
Piceance Basin [Member]
Impairment Costs [Line Items]
Dry hole costs	67
Appalachian Basin
Impairment Costs [Line Items]
Impairment Charge			772
Unproved leasehold property impairment, amortization and expiration			317
Powder River Basin
Impairment Costs [Line Items]
Impairment of producing properties and costs of acquired unproved reserves			85
Impairment Charge			107		102
Piceance
Impairment Costs [Line Items]
Impairment of producing properties and costs of acquired unproved reserves			88		75
Kokopelli area of Piceance Basin
Impairment Costs [Line Items]
Impairment of producing properties and costs of acquired unproved reserves							69	19	19
Green River Basin
Impairment Costs [Line Items]
Impairment Charge	11
Impairment of proved oil and gas properties					48
Other Property
Impairment Costs [Line Items]
Dry hole costs	16
Unproved leasehold property impairment, amortization and expiration	41
Impairment of Equity Method Investment in Appalachian Basin [Member]
Impairment Costs [Line Items]
Investment income, impairment of equity method investment and other			$20
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.

Asset_Sales_Impairments_and_Ex4

Asset Sales, Impairments and Exploration Expenses - Summary of Exploration Expenses (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Geologic and geophysical costs	$11	$18	$12
Dry hole costs	88	3	1
Unproved leasehold property impairment, amortization and expiration	74	402	58
Capitalized Exploratory Well Costs	37
Total exploration expense	173	423	71
Other Property
Extractive Industries [Abstract]
Dry hole costs	16
Unproved leasehold property impairment, amortization and expiration	$41

Properties_and_Equipment_Carri

Properties and Equipment - Carried at Cost (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	11,753		$12,011
Accumulated depreciation, depletion and amortization	-4,911		-5,251
Properties and equipment-net	6,842		6,760
Proved properties
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	10,386	[1],[2]	10,955	[1],[2]
Unproved Properties
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	394	[1],[3]	316	[1],[3]
Gathering, Processing and Other Facilities
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	251	[1]	209	[1]
Gathering, Processing and Other Facilities | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	15 years	[1]
Gathering, Processing and Other Facilities | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	25 years	[1]
Construction in Progress
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	541	[1],[3]	353	[1],[3]
Other
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	181	[1]	$178	[1]
Other | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	3 years	[1]
Other | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	40 years	[1]
[1]	Estimated useful lives are presented as of December 31, 2014.
[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_Addit

Properties and Equipment - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Well
Property, Plant and Equipment [Line Items]
Payments to Acquire Oil and Gas Property	$150
Proceeds from sales of assets	374	49	310
Percentage of working interest sold	49.00%
Proved developed wells related to sale	63
Funding commitment associated with joint development agreement	170
Future wells associated with joint development agreement	400
Piceance Basin [Member]
Property, Plant and Equipment [Line Items]
Proved developed wells related to sale	100
Proved Developed Reserves [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Oil and Gas Property	50
Piceance Basin [Member] | TRDC LLC (G2X) [Member]
Property, Plant and Equipment [Line Items]
Proceeds from sales of assets	$50

Properties_and_Equipment_Rollf

Properties and Equipment - Rollforward Asset Retirement Obligation (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$308		$261
Liabilities incurred during the period	19		11
Liabilities settled during the period	-2		-1
Asset Retirement Obligation, Liabilities associated with assets sold	65		0
Estimate revisions	-78		17
Accretion expense	19	[1]	20	[1]
Ending Balance	201		308
Amount reflected as current	$3		$3
[1]	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Accounts_Payable_and_Accrued_a2

Accounts Payable and Accrued and Other Current Liabilities - Accounts Payable (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Payables and Accruals [Abstract]
Trade	$215	$208
Accrual for capital expenditures	313	225
Royalties	125	130
Cash overdrafts	0	35
Other	59	36
Accounts payable	$712	$634

Accounts_Payable_and_Accrued_a3

Accounts Payable and Accrued and Other Current Liabilities - Accrued and Other Current Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Payables and Accruals [Abstract]
Taxes other than income taxes	$41	$41
Accrued interest	53	43
Compensation and benefit related accruals	55	52
Other, including other loss contingencies	28	31
Accrued And Other Current Liabilities	$177	$167

Debt_and_Banking_Arrangements_1

Debt and Banking Arrangements - Debt (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]
Total debt	$2,281	[1]	$1,912	[1]
Less: Current portion of long-term debt	1	[1]	1	[1]
Total long-term debt	2,280	[1]	1,911	[1]
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Total debt	400	[1]	400	[1]
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Total debt	1,100	[1]	1,100	[1]
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Total debt	500	[1]	0
Credit Facility Agreement
Debt Instrument [Line Items]
Total debt	280	[1]	410	[1]
Other
Debt Instrument [Line Items]
Total debt	$1	[1]	$2	[1]
[1]	Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

Debt_and_Banking_Arrangements_2

Debt and Banking Arrangements - Debt - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt, interest expense	$97	$91
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.25%	5.25%
Debt Instrument Maturity Year	2017	2017
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt instrument stated interest rate	6.00%	6.00%
Debt Instrument Maturity Year	2022	2022
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.25%	5.25%
Debt Instrument Maturity Year	2024	2024

Debt_and_Banking_Arrangements_3

Debt and Banking Arrangements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Nov. 30, 2011	Sep. 30, 2014
	Contract
Debt Instrument [Line Items]
Debt redemption price as percentage of principal amount	100.00%
Debt Instrument, Description of Variable Rate Basis	0.01875
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.88%
Line of Credit Facility, Commitment Fee Percentage	0.30%
Limit On Consolidated Indebtedness to Consolidated EBITDAX	3.75
Reduction Attributable to Cash Maximum	$50,000,000
Maximum ratio of debt to capitalization	60.00%
Number of letter of credit agreements	3
Letters of credit issued	320,000,000
Unsecured Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility agreement	1,500,000,000
Debt instrument maturity period	5 years
Debt instrument additional borrowing capacity	300,000,000
Weighted average interest rate	3.01%
Outstanding amount	280,000,000
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, Long-term and Short-term, Combined Amount		400,000,000
Senior Notes
Debt Instrument [Line Items]
Net proceeds from debt offering			494,000,000
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		1,100,000,000
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount			$500,000,000
Change of Control
Debt Instrument [Line Items]
Percentage of repurchase of notes on principal amount of notes	101.00%
Prior to December 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness	1.25
After December 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness	1.5

Provision_Benefit_for_Income_T2

Provision (Benefit) for Income Taxes - Provision (Benefit) for Income Taxes from Continuing Operations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	($3)	($29)	$49
State	1	1	4
Total current	-2	-28	53
Deferred:
Federal	76	-549	-125
State	1	-47	-12
Total Deferred	77	-596	-137
Total provision (benefit)	$75	($624)	($84)

Provision_Benefit_for_Income_T3

Provision (Benefit) for Income Taxes - Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Provision (benefit) at statutory rate	$71	($604)	($90)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	3	-111	-6
State income tax change in valuation allowance (net of federal benefit)	-1	80	0
Effective Income Tax Rate Reconciliation, Tax Contingency, State and Local, Amount	9
Effective state income tax rate change (net of federal benefit)	-9	-3	0
Alternative minimum tax credits	0	0	11
Other	2	14	1
Total provision (benefit)	$75	($624)	($84)

Provision_Benefit_for_Income_T4

Provision (Benefit) for Income Taxes - Additional Information (Detail) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Provision For Income Taxes [Line Items]
State net operating loss carryovers expire percent			90.00%
State net operating loss carryovers expiration year			2029
Deferred Other Tax Expense (Benefit)	$9	$9
Excess Tax Benefit from Share-based Compensation, Financing Activities			7
Alternative minimum tax credits			0	0	11
Federal
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards	114		114
State
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards	875		875	825
Domestic
Provision For Income Taxes [Line Items]
Income tax cash paid (refund)			$9	($26)	$40

Provision_Benefit_for_Income_T5

Provision (Benefit) for Income Taxes - Significant Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Deferred tax liabilities:
Properties and equipment	$738	$961
Deferred Tax Liabilities, Derivatives	170	0
Other, net	17	23
Total deferred tax liabilities	925	984
Deferred tax assets:
Accrued liabilities and other	124	176
Alternative minimum tax credits	60	76
Loss carryovers	51	83
Deferred Tax Assets, Derivative Instruments	0	21
Other, net	32	0
Total deferred tax assets	267	356
Less: valuation allowance	114	99
Total net deferred tax assets	153	257
Net deferred tax liabilities	$772	$727

Contingent_Liabilities_and_Com2

Contingent Liabilities and Commitments - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended	97 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2006	Jul. 31, 2008
				Claim
Loss Contingencies [Line Items]
Processing, treating and transportation costs used in the calculation of federal royalties	$113
Commitments to provide service to an equity investee and others	305
Service commitment period	6 years
Contractual Obligation	1,141
Volume of natural gas production per day	260
Total rent expenses	27	27	19
Purchase agreement | Marcellus Shale
Loss Contingencies [Line Items]
Volume of natural gas production per day	200,000
Contract term	12 years
Royalty Litigation
Loss Contingencies [Line Items]
Number of claims reserved for court resolution				2
Loss Contingency, Damages Sought, Value					20
Loss contingencies associated with royalty litigation	16	16
Assets Held-for-sale [Member]
Loss Contingencies [Line Items]
Contractual Obligation	88
Discontinued Operations [Member] | Capacity [Member]
Loss Contingencies [Line Items]
Contractual Obligation	172
Discontinued Operations [Member] | Assets Held-for-sale [Member]
Loss Contingencies [Line Items]
Contractual Obligation	$43

Contingent_Liabilities_and_Com3

Contingent Liabilities and Commitments - Commitments Under Contracts (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
2015	$177
2016	162
2017	149
2018	138
2019	126
Thereafter	389
Total	$1,141

Contingent_Liabilities_and_Com4

Contingent Liabilities and Commitments - Future Minimum Annual Rentals Under Noncancelable Operating Leases (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
2015	$37
2016	32
2017	11
2018	7
2019	7
Thereafter	15
Total	$109

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer contribution	$17	$16	$6
Postretirement Defined Benefit Plans, Liabilities	$10	$11
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%

StockBased_Compensation_Additi

Stock-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Based Compensation Activity [Line Items]
Common stock share authorized	2,000,000,000	2,000,000,000
Employee stock purchase plan purchase price first offering start date	1-Mar-12
Employee stock purchase plan purchase price first offering end date	30-Jun-12
Stock option exercisable period	3 years
Stock option term	10 years
Restricted stock units vesting period	3 years
Unrecognized stock based compensation	$41
Value of stock option exercised during year	13	5	5
Cash received from stock option exercises	14	4	2
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	15.00%
Administrative expenses
Stock Based Compensation Activity [Line Items]
Stock based compensation expense	35	31	28
Stock Options
Stock Based Compensation Activity [Line Items]
Unrecognized stock based compensation	1
Unrecognized stock based compensation, weighted average period of recognition	1 year 9 months 18 days
Restricted Stock Units
Stock Based Compensation Activity [Line Items]
Unrecognized stock based compensation	$40
Two Thousand Thirteen Incentive Plan [Member]
Stock Based Compensation Activity [Line Items]
Common stock share authorized	19,800,000
Discount allowed on employee stock purchase plan	15.00%
Number of share purchased under stock option plan	124,000
Stock option plan, average purchase price	$12.56
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

StockBased_Compensation_Summar

Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014
Option Outstanding
Beginning Balance (in shares)	4.1
Granted (in shares)	0.4
Exercised (in shares)	-1.3
Forfeited (in shares)	-0.1
Ending Balance (in shares)	3.1
Exercisable at end of period (in shares)	2.7
Weighted Average Exercise price
Beginning Balance (in dollars per share)	$13.27
Granted (in dollars per share)	$19.03
Exercised (in dollars per share)	$11.11
Forfeited (in dollars per share)	$15.39
Ending Balance (in dollars per share)	$14.80
Exercisable at end of period (in dollars per share)	$14.26
Aggregate Intrinsic value
Beginning Balance	$29
Ending Balance	2
Exercisable at end of period	$2

StockBased_Compensation_Summar1

Stock-Based Compensation - Summary of Stock Option Activity and Related Information - Additional Information (Detail) (Williams Employees, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Williams Employees
Schedule Of Stock Options [Line Items]
Share held by Williams' employees	137	344
Weighted average price of share held by Williams' employee	$10.64	$9.24

StockBased_Compensation_Summar2

Stock-Based Compensation - Summary of Stock Option Outstanding and Exercisable (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$16.46	$20.21	$16.46
Range of Exercise Prices, Upper Limit	$21.81	$20.97	$20.97
Options outstanding (in shares)	3.1	4.1
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$14.80	$13.27
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	5 years
Options exercisable (in shares)	2.7
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$14.26
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	4 years 4 months 24 days
$ 6.02 to $10.68
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	$10.68
Options outstanding (in shares)	0.5
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$7.59
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	2 years 9 months 18 days
Options exercisable (in shares)	0.5
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$7.59
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	2 years 9 months 18 days
$11.32 to $13.46
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
Range of Exercise Prices, Lower Limit	$11.32
Range of Exercise Prices, Upper Limit	$13.46
Options outstanding (in shares)	0.6
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$11.82
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	4 years
Options exercisable (in shares)	0.6
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$11.82
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	4 years
$14.41 to $18.23
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	$18.23
Options outstanding (in shares)	1.5
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$16.39
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	6 years 1 month 6 days
Options exercisable (in shares)	1.2
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$16.36
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	5 years 7 months 6 days
$19.95 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	$19.95
Range of Exercise Prices, Upper Limit	$21.81
Options outstanding (in shares)	0.5
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$20.61
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	5 years
Options exercisable (in shares)	0.4
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$20.24
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	3 years 2 months 12 days

StockBased_Compensation_Estima

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) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted-average or grant date fair value of options granted	$18.94	$6.04	$7.79
Dividend yield	0.00%	0.00%	0.00%
Volatility	43.00%	42.80%	43.80%
Risk-free interest rate	1.85%	1.06%	1.17%
Expected life	5 years 10 months 24 days	6 years	6 years

StockBased_Compensation_Summar3

Stock-Based Compensation - Summary of Nonvested Restricted Stock Unit Activity and Related Information (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014
Nonvested Shares
Beginning Balance	5.2
Granted	2.5
Forfeited	-0.7
Vested	-1.9
Ending balance	5.1
Weighted-Average Fair Value
Nonvested, Beginning Balance	$16.97	[1]
Granted	$18.37	[1]
Forfeited	$16.92	[1]
Vested	$16.92	[1]
Nonvested, Ending Balance	$17.58	[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.

StockBased_Compensation_Other_

Stock-Based Compensation - Other Restricted Stock Unit (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
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	$18.37	[1]
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	$18.37		$14.97	$17.35
Total fair value of restricted stock units vested during the year (millions)	$33		$18	$14
[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_Additional

Stockholders' Equity - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Vote
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Number of votes per share for common stockholders	1
Dividends declared (in dollars per share)	$0	$0	$0
Dividends paid (in dollars per share)	$0	$0	$0
Common Stock Subject to Mandatory Redemption
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Shares subject to redemption	0

Fair_Value_Measurements_Assets

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	$2,218	[1]	$1,938	[1]
Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets	536		57
Energy derivative liabilities	42		122
Level 1 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets	14		30
Energy derivative liabilities	32		83
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,218	[1]	1,938	[1]
Level 2 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets	517		26
Energy derivative liabilities	10		38
Level 3 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets	5		1
Energy derivative liabilities	$0		$1
[1]	The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of net fair value of derivatives portfolio expiring	100.00%
Expiry of net fair value of derivatives portfolio	24 months
Long-term Debt, Excluding Current Maturities	$2,280	$1,910

Fair_Value_Measurements_Level_

Fair Value Measurements - Level 3 Fair Value Measurements Using Significant Unobservable Inputs (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$0	($1)	$1
Realized and unrealized gains (losses) included in income (loss) from continuing operations	5	-2	3
Realized and unrealized gains (losses) included in other comprehensive income (loss)	0	0	0
Purchases, issuances, and settlements	0	3	-5
Transfers out of Level 3	0	0	0
Ending balance	5	0	-1
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$5	($1)	($1)

Fair_Value_Measurements_Impair

Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Fair Value Disclosures [Abstract]
Impairment of producing properties and costs of acquired unproved reserves (Note 4)	$20	[1]	$1,055	[2]	$225	[3]
Unproved leasehold	0		317	[2]	0
Equity method investment (Note 4)	$0		$20	[2]	$0
[1]	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.
[2]	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. 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.
[3]	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:•$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. 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.•$48 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 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

Fair_Value_Measurements_Impair1

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) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of producing properties and costs of acquired unproved reserves	$11	$365		$351
Weighted average natural gas price	4.34	3.63		3.01
Unproved leasehold property impairment, amortization and expiration	74	402		58
Unproved Leasehold Property Impairment	0	317	[1]	0
Equity method investment (Note 4)	0	20	[1]	0
Asset Impairment Charges Including Discontinued Operations	20	1,392		225
Probable Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax				13.00%
Possible Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax				15.00%
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]
Impairment Charge				48
Weighted average natural gas price	4.77			5.87
Percentage of discount rate after-tax				11.00%
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	23,000,000			29,000,000
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		3.6
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		299,000,000
Powder River Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge		107		102
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		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		294,000,000
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		75
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]	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. 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_2

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) (Short)	12 Months Ended
	Dec. 31, 2014
2015 [Member] | Derivatives related to production | Crude Oil Commodity Contract One | Fixed Priced Swaps | WTI
Derivative [Line Items]
Notional Volume	-20,236	[1],[2]
Underlying, Derivative	94.88	[1],[3]
2015 [Member] | Derivatives related to production | Crude Oil Commodity Contract Two | Swaptions | WTI
Derivative [Line Items]
Notional Volume	-882	[1],[2]
Underlying, Derivative	97.29	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract One | Fixed Priced Swaps | Henry Hub
Derivative [Line Items]
Notional Volume	-442,000	[1],[2]
Underlying, Derivative	4.1	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub
Derivative [Line Items]
Notional Volume	-50,000	[1],[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Minimum
Derivative [Line Items]
Underlying, Derivative	4
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Maximum
Derivative [Line Items]
Underlying, Derivative	4.5	[1],[4]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Five | Basis Swap | NGPL [Member]
Derivative [Line Items]
Notional Volume	-13,000	[1],[2]
Underlying, Derivative	-0.16	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Six | Basis Swap | Rockies
Derivative [Line Items]
Notional Volume	-150,000	[1],[2]
Underlying, Derivative	-0.11	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Seven | Basis Swap | San Juan [Member]
Derivative [Line Items]
Notional Volume	-85,000	[1],[2]
Underlying, Derivative	-0.1	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Seven | Basis Swap | Southern California Gas [Member]
Derivative [Line Items]
Notional Volume	-20,000	[1],[2]
Underlying, Derivative	0.18	[1],[3]
2015 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Two | Basis Swap | Multiple Location
Derivative [Line Items]
Notional Volume	-3,000	[4],[5],[6]
2015 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Three | Index | Multiple Location
Derivative [Line Items]
Notional Volume	-118,000	[4],[5],[6]
2016 [Member] | Derivatives related to production | Crude Oil Commodity Contract Two | Swaptions | WTI
Derivative [Line Items]
Notional Volume	-5,250	[1],[2]
Underlying, Derivative	97.55	[1],[3]
2016 [Member] | Derivatives related to production | Natural Gas Commodity Contract Eight | Fixed Priced Swaps | Henry Hub
Derivative [Line Items]
Notional Volume	-200,000	[1],[2]
Underlying, Derivative	3.98	[1],[3]
2016 [Member] | Derivatives related to production | Natural Gas Commodity Contract Nine | Swaptions | Henry Hub
Derivative [Line Items]
Notional Volume	-90,000	[1],[2]
Underlying, Derivative	4.23	[1],[3]
2016 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Five | Index | Multiple Location
Derivative [Line Items]
Notional Volume	-70,000	[4],[5],[6]
2017 [Member] | Derivatives related to production | Natural Gas Commodity Contract Nine | Swaptions | Henry Hub
Derivative [Line Items]
Notional Volume	-65,000	[1],[2]
Underlying, Derivative	4.19	[1],[3]
2017 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Six | Index | Multiple Location
Derivative [Line Items]
Notional Volume	-70,000	[4],[5],[6]
2018 and beyond [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Seven | Index | Multiple Location
Derivative [Line Items]
Notional Volume	-379,000	[4],[5],[6]
[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, 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 grant the counterparty the option to enter into future swaps with us.
[2]	(b)Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
[3]	(c)The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.
[4]	(c)Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
[5]	(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.
[6]	(b)We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.

Derivatives_and_Concentration_3

Derivatives and Concentration of Credit Risk - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net		$0
Collateral posted to derivative		26,000,000		71,000,000
Initial margin		9,000,000		19,000,000
Maintenance margin		17,000,000		52,000,000
Net derivative liability position		17,000,000		72,000,000
Additional collateral posted		1,000,000		20,000,000
Unrealized gains recognized for hedge transactions	15,000,000		33,000,000
Unearned Non Cash Stock Based Compensation Expected To Recognize As Expense Over Period			3 years
Net gains reclassified into earnings within the next year			3,000,000
Net of income tax provision			2,000,000
Net credit exposure percentage		96.00%
Collateral support		32,000,000
Domestic Segment | BP Energy
Derivative [Line Items]
Percentage of consolidated revenue		13.00%	11.00%	16.00%
Domestic Segment | Southern California Gas
Derivative [Line Items]
Percentage of consolidated revenue		8.00%		11.00%
Domestic Segment | Williams [Member]
Derivative [Line Items]
Percentage of consolidated revenue			14.00%
Maximum
Derivative [Line Items]
Reduction in derivative liabilities		$1,000,000		1,000,000

Derivatives_and_Concentration_4

Derivatives and Concentration of Credit Risk - Fair Value of Energy Commodity Derivatives (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	$536	$57
Total derivatives, Liabilities	42	122
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	536	57
Total derivatives, Liabilities	42	122
Not Designated as Hedging Instrument | Derivatives related to production
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	517	26
Total derivatives, Liabilities	10	39
Not Designated as Hedging Instrument | Derivatives Related to Physical Marketing Agreements
Derivatives, Fair Value [Line Items]
Total derivatives, Assets	19	31
Total derivatives, Liabilities	$32	$83

Derivatives_and_Concentration_5

Derivatives and Concentration of Credit Risk - Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)			$5		$434
Cash Flow Hedging | Accumulated Other Comprehensive Income
Derivative Instruments, Gain (Loss) [Line Items]
Net gain recognized in other comprehensive income (loss) (effective portion)	0		0		90
Cash Flow Hedging | Revenues
Derivative Instruments, Gain (Loss) [Line Items]
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$0	[1]	$5	[1]	$434	[1]
[1]	Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.

Derivatives_and_Concentration_6

Derivatives and Concentration of Credit Risk - Offsetting of Derivative Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Asset [Abstract]
Gross Amount Presented on Balance Sheet	$536		$57
Netting Adjustment	-25	[1]	-50	[1]
Cash Collateral Posted(Received)	0		0
Net Amount	511		7
Derivative Liability [Abstract]
Gross Amount Presented on Balance Sheet	-42		-122
Netting adjustment	25	[1]	50	[1]
Cash Collateral Posted(Received)	17		52
Net Amount	$0		($20)
[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_Concentration_7

Derivatives and Concentration of Credit Risk - Concentration of Receivables, Net of Allowances, by Product or Service (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Receivables [Line Items]
Account receivables	$459	$518
Sale of natural gas and related products and services
Receivables [Line Items]
Account receivables	340	339
Joint interest owners
Receivables [Line Items]
Account receivables	106	168
Other
Receivables [Line Items]
Account receivables	$13	$11

Derivatives_and_Concentration_8

Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Credit Exposure From Derivatives [Line Items]
Total gross credit exposure from derivative contracts before credit reserve	$537
Gross credit reserves	-1
Gross credit exposure from derivatives	536
Total net credit exposure from derivative contracts before credit reserve	512
Net credit reserves	-1
Net credit exposure from derivatives	511
Gas And Electric Utilities And Integrated Oil And Gas Companies [Member]
Credit Exposure From Derivatives [Line Items]
Total gross credit exposure from derivative contracts before credit reserve	4
Total net credit exposure from derivative contracts before credit reserve	4
Financial institutions
Credit Exposure From Derivatives [Line Items]
Total gross credit exposure from derivative contracts before credit reserve	533	[1]
Total net credit exposure from derivative contracts before credit reserve	$508	[1]
[1]	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.

Derivatives_and_Concentration_9

Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
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

Recovered_Sheet1

Derivatives and Concentration of Credit Risk Derivatives and concentration of credit risk Gain (Loss) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
DerivativeGainLoss [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$434		($124)		$78
Energy Related Derivative
DerivativeGainLoss [Line Items]
Payment Made for Settlement of Derivatives	4		11
Payment Received for Settlement of Derivatives					29
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	515	[1]	-57	[1]	66	[1]
Derivatives Related to Physical Marketing Agreements
DerivativeGainLoss [Line Items]
Payment Made for Settlement of Derivatives	120		6
Payment Received for Settlement of Derivatives					17
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	($81)	[2]	($67)	[2]	$12	[2]
[1]	(a)Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
[2]	(b)Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.

Quarterly_Financial_Data_Quart

Quarterly Financial Data Quarterly Financial Data-Summarized Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Line Items]
Revenues	$1,125	$747	$727	$894	$576	$581	$722	$552	$3,493	$2,431	$2,900
Operating costs and expenses	656	570	659	783	1,024	621	612	634
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	227	46	-144	0	-890	-105	6	-115	129	-1,104	-174
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	-8	20	11	19	-94	-11	16	2	42	-87	-37
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	219	66	-133	19	-984	-116	22	-113	171	-1,191	-211
Income (Loss) from Continuing Operations Attributable to WPX	227	46	-144	0	-878	-105	6	-115	129	-1,092	-174
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX	-8	16	9	18	-95	-9	12	-1	35	-93	-49
Net Income (Loss) Attributable to Parent	$219	$62	($135)	$18	($973)	($114)	$18	($116)	$164	($1,185)	($223)
Income (Loss) from Continuing Operations, Per Basic Share	$1.11	$0.23	($0.71)	$0					$0.63	($5.45)	($0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	($0.03)	$0.07	$0.05	$0.09					$0.18	($0.46)	($0.25)
Earnings Per Share, Basic	$1.08	$0.30	($0.66)	$0.09					$0.81	($5.91)	($1.12)
Income (Loss) from Continuing Operations, Per Diluted Share	$1.10	$0.23	($0.71)	$0					$0.62	($5.45)	($0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	($0.04)	$0.07	$0.05	$0.09					$0.18	($0.46)	($0.25)
Earnings Per Share, Diluted	$1.06	$0.30	($0.66)	$0.09					$0.80	($5.91)	($1.12)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share					($4.37)	($0.52)	$0.03	($0.57)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share					($0.48)	($0.05)	$0.06	($0.01)
Earnings Per Share, Basic and Diluted					($4.85)	($0.57)	$0.09	($0.58)

Quarterly_Financial_Data_Adjus

Quarterly Financial Data -Adjusted Quarterly Financial Data (Detail) (USD $)	3 Months Ended										12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data Adjustments [Line Items]
Revenues	$1,125	$747		$727	$894	$576	$581		$722	$552	$3,493	$2,431	$2,900
Operating costs and expenses	656	570		659	783	1,024	621		612	634
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	227	46		-144	0	-890	-105		6	-115	129	-1,104	-174
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	-8	20		11	19	-94	-11		16	2	42	-87	-37
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	219	66		-133	19	-984	-116		22	-113	171	-1,191	-211
Income (Loss) from Continuing Operations Attributable to WPX	227	46		-144	0	-878	-105		6	-115	129	-1,092	-174
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX	-8	16		9	18	-95	-9		12	-1	35	-93	-49
Net Income (Loss) Attributable to Parent	219	62		-135	18	-973	-114		18	-116	164	-1,185	-223
Income (Loss) from Continuing Operations, Per Basic Share	$1.11	$0.23		($0.71)	$0						$0.63	($5.45)	($0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	($0.03)	$0.07		$0.05	$0.09						$0.18	($0.46)	($0.25)
Earnings Per Share, Basic	$1.08	$0.30		($0.66)	$0.09						$0.81	($5.91)	($1.12)
Income (Loss) from Continuing Operations, Per Diluted Share	$1.10	$0.23		($0.71)	$0						$0.62	($5.45)	($0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	($0.04)	$0.07		$0.05	$0.09						$0.18	($0.46)	($0.25)
Earnings Per Share, Diluted	$1.06	$0.30		($0.66)	$0.09						$0.80	($5.91)	($1.12)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share						($4.37)	($0.52)		$0.03	($0.57)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share						($0.48)	($0.05)		$0.06	($0.01)
Earnings Per Share, Basic and Diluted						($4.85)	($0.57)		$0.09	($0.58)
Quarterly [Member]
Quarterly Financial Data Adjustments [Line Items]
Revenues		47	[1]	-87	-93	-81	35	[1]	-93	-79
Operating costs and expenses		31	[1]	62	-62	-74	22	[1]	-77	-76
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		-15	[1]	-11	-19	94	3	[1]	-16	-2
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		15	[1]	11	19	-94	-3	[1]	16	2
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		0	[1]	0	0	0	0	[1]	0	0
Income (Loss) from Continuing Operations Attributable to WPX		-16	[1]	-9	-18	95	9	[1]	-12	1
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX		16	[1]	9	18	-95	-9	[1]	12	-1
Net Income (Loss) Attributable to Parent		$0	[1]	$0	$0	$0	$0	[1]	$0	$0
Income (Loss) from Continuing Operations, Per Basic Share		($0.05)	[1]	($0.05)	($0.09)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share		$0.05	[1]	$0.05	$0.09
Earnings Per Share, Basic		$0	[1]	$0	$0
Income (Loss) from Continuing Operations, Per Diluted Share		($0.05)	[1]	($0.05)	($0.09)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share		$0.05	[1]	$0.05	$0.09
Earnings Per Share, Diluted		$0	[1]	$0	$0
Income (Loss) from Continuing Operations, Per Basic and Diluted Share						$0.48	$0.01	[1]	($0.06)	$0.01
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share						($0.48)	($0.01)	[1]	$0.06	($0.01)
Earnings Per Share, Basic and Diluted						$0	$0	[1]	$0	$0
[1]	Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

Quarterly_Financial_Data_Addit

Quarterly Financial Data - Additional Information (Detail) (USD $)	3 Months Ended					12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Line Items]
Impairment Of Costs Of Producing Properties, Acquired Unproved Reserves, leasehold, and equity method investment	$87				$1,178
Proceeds from Sale of Other Assets	18
Exploration Abandonment and Impairment Expense		22	40
Gas Management Expense, Other			11
Deferred Other Tax Expense (Benefit)	9			9
Loss On Sale Of Working Interests		1	195			196	0	0
Buyout of Transportation Agreement					9	14
Powder River Basin
Quarterly Financial Data [Line Items]
Impairment of producing properties and costs of acquired unproved reserves							85
Kokopelli area of Piceance Basin
Quarterly Financial Data [Line Items]
Impairment of producing properties and costs of acquired unproved reserves	$69	$19			$19

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	Mcfe		Mcfe		Mcfe		Mcfe
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserves, Net	300,000
Equipment and facilities in support of oil and gas production excluded from capitalization	385		328
Equity earnings from the international equity method investee	1		21		1
Impairment of oil and gas properties	20	[1]	1,055	[2]	225	[3]
Computation of natural gas reserves	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
Weighted average natural gas price	4.34		3.63		3.01
Weighted average oil per barrel price	83.62		92.16		82.32
Discount rate	10.00%
Powder River Basin
Supplementary Information [Line Items]
Operations representing total domestic and international proved reserves	5.00%
International
Supplementary Information [Line Items]
Operations representing total domestic and international proved reserves	5.00%
Appalachian Basin
Supplementary Information [Line Items]
Operations representing total domestic and international proved reserves	5.00%
Impairment of oil and gas properties	317
Oil and Condensate Sales | Domestic
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserves, Net	130.8		102.9		76.5		47.1
Oil and Condensate Sales | San Juan [Member]
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserves, Net	28,000
All products | Domestic
Supplementary Information [Line Items]
Proved developed reserves, revisions	97,000		133,000
Proved undeveloped reserves, revisions	422,000		44,000
Additions due to added drill locations	189,000		127,000		225,000
Additions due to new undeveloped locations	502,000		407,000		405,000
Proved Developed And Undeveloped Reserves Net Equivalent	4,359,600	[4]	4,761,600	[4]	4,490,500	[4]	5,070,100	[4]
All products | Powder River Basin
Supplementary Information [Line Items]
Proved Developed And Undeveloped Reserves Net Equivalent	200,000	[4]	244,600	[4]	235,900	[4]
[1]	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.
[2]	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. 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.
[3]	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:•$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. 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.•$48 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 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
[4]	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Supplemental_Oil_and_Gas_Discl3

Supplemental Oil and Gas Disclosures - Capitalization Cost (Detail) (Domestic, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Domestic
Capitalized Expedition Cost Related To Specific Assets [Line Items]
Proved Properties	$10,717	$11,132
Unproved properties	394	324
Total property costs	11,111	11,456
Accumulated depreciation, depletion and amortization and valuation provisions	-4,698	-5,070
Net capitalized costs	$6,413	$6,386

Supplemental_Oil_and_Gas_Discl4

Supplemental Oil and Gas Disclosures - Cost Incurred (Detail) (Domestic, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Domestic
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	$294	$57	$111
Exploration	92	104	23
Development	1,376	939	1,130
Total costs incurred	$1,762	$1,100	$1,264

Supplemental_Oil_and_Gas_Discl5

Supplemental Oil and Gas Disclosures - Results of Operation (Detail) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment of certain natural gas properties			$20	[1]	$860	[1]	$123	[1]
Loss On Sale Of Working Interests	1	195	196		0		0
Domestic
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			2,454		1,607		1,939
Net gain (loss) on derivatives not designated as hedges			515		-57		66
Other revenues			8		6		7
Lease and facility operating			244		227		202
Gathering, processing and transportation			328		350		434
Taxes other than income			126		102		68
Exploration			173		423		71
Depreciation, depletion and amortization			810		858		884
Impairment of certain natural gas properties			15		772		48
Impairment of costs of acquired unproved reserves			5		88		75
Loss On Sale Of Working Interests			196		0		0
General and administrative			264		262		259
Other (income) expense			12		12		16
Total costs			2,173		3,094		2,057
Results of operations			281		-1,487		-118
Provision (benefit) for income taxes			103		-543		-43
Exploration and production net income (loss)			178		-944		-75
Domestic | Natural Gas
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			1,002		896		1,193
Domestic | Oil and Condensate Sales
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			724		534		376
Domestic | Natural Gas Liquids
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues			$205		$228		$297
[1]	Excludes related impairments of unproved leasehold included in exploration expenses.

Supplemental_Oil_and_Gas_Discl6

Supplemental Oil and Gas Disclosures - Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	MMcf		MMcf		MMcf
Supplementary Information [Line Items]
Proved reserves ending balance	300,000
Domestic | Natural Gas
Supplementary Information [Line Items]
Proved reserves beginning balance	3,629,800		3,369,100		3,982,900
Revisions	-198,300		308,300		-404,800
Purchases	-6,000				-5,800
Divestitures	-314,600		-200		-217,000
Extensions and discoveries	362,100		312,000		409,200
Production	-335,400		-359,400		-407,000
Proved reserves ending balance	3,149,600		3,629,800		3,369,100
Proved developed reserves	2,090,000		2,265,200		2,170,700
Proved undeveloped reserves	1,059,600		1,364,600		1,198,400
Domestic | Oil and Condensate Sales
Supplementary Information [Line Items]
Proved reserves beginning balance	102.9		76.5		47.1
Revisions	-7.7		3.5		5.6
Purchases	-4.2				0
Divestitures	-1.8		0		-0.3
Extensions and discoveries	42.4		28.8		28.5
Production	-9.2		-5.9		-4.4
Proved reserves ending balance	130.8		102.9		76.5
Proved developed reserves	60		36.8		23.7
Proved undeveloped reserves	70.8		66.1		52.8
Domestic | Natural Gas Liquids
Supplementary Information [Line Items]
Proved reserves beginning balance	85.7		110.4		134
Revisions	-13.4		-25.4		-21.1
Purchases	-0.8		0		0
Divestitures	-8.5				-1
Extensions and discoveries	12.5		8.1		8.9
Production	-6.3		-7.4		-10.4
Proved reserves ending balance	70.8		85.7		110.4
Proved developed reserves	43.9		48.6		64.9
Proved undeveloped reserves	26.9		37.1		45.5
Domestic | All products
Supplementary Information [Line Items]
Proved reserves beginning balance	4,761,600	[1]	4,490,500	[1]	5,070,100	[1]
Revisions	-324,800	[1]	177,200	[1]	-498,600	[1]
Purchases	36,500	[1]			5,800	[1]
Divestitures	-376,600	[1]	-500	[1]	-224,800	[1]
Extensions and discoveries	691,300	[1]	533,800	[1]	633,800	[1]
Production	-428,400	[1]	-439,400	[1]	-495,800	[1]
Proved reserves ending balance	4,359,600	[1]	4,761,600	[1]	4,490,500	[1]
Proved developed reserves	2,713,800	[1]	2,777,700	[1]	2,702,600	[1]
Proved undeveloped reserves	1,645,800	[1]	1,983,900	[1]	1,787,900	[1]
[1]	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Supplemental_Oil_and_Gas_Discl7

Supplemental Oil and Gas Disclosures - Proved Reserves - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
Disclosure Proved Reserves [Abstract]
Conversion Rate Of Oil And Ngl Quantities	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Supplemental_Oil_and_Gas_Discl8

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) (Domestic, USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Domestic
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$26,444	$24,547
Future production costs	12,641	12,148
Future development costs	3,426	3,789
Future income tax provisions	2,519	2,147
Future net cash flows	7,858	6,463
Less 10 percent annual discount for estimated timing of cash flows	-3,975	-3,499
Standardized measure of discounted future net cash inflows	$3,883	$2,964	$1,949	$3,591

Supplemental_Oil_and_Gas_Discl9

Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) (Domestic, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Domestic
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	$2,964	$1,949	$3,591
Sales of oil and gas produced, net of operating costs	-1,324	-1,040	-778
Net change in prices and production costs	303	1,198	-3,601
Extensions, discoveries and improved recovery, less estimated future costs	1,761	1,282	1,154
Development costs incurred during year	592	414	333
Changes in estimated future development costs	143	-736	50
Purchase of reserves in place, less estimated future costs	147	0	4
Sale of reserves in place, loss estimated future costs	-391	-3	-272
Revisions of previous quantity estimates	-536	239	-232
Accretion of discount	383	225	481
Net change in income taxes	-142	-540	1,194
Other	-17	-24	25
Net changes	919	1,015	-1,642
Standardized measure of discounted future net cash flows end of period	$3,883	$2,964	$1,949

Schedule_II_Valuation_And_Qual1

Schedule II - Valuation And Qualifying Accounts (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for doubtful accounts - accounts and notes receivable
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	$7	[1]	$11	[1]	$13	[1]
Charged (Credited) to Costs and Expenses	0	[1]	-3	[1]	-2	[1]
Deductions	-1	[1]	-1	[1]	0	[1]
Ending Balance	6	[1]	7	[1]	11	[1]
Deferred tax asset valuation allowance
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	102	[2]	19	[2]	16	[2]
Charged (Credited) to Costs and Expenses	-1	[2]	80	[2]	3	[2]
Other	17	[2]	3	[2]
Deductions	0	[2]	0	[2]	0	[2]
Ending Balance	118	[2]	102	[2]	19	[2]
Price-risk management credit reserves-assets
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	0	[1],[3]
Charged (Credited) to Costs and Expenses	0	[1],[3]
Other	1	[1],[3]
Deductions	0	[1],[3]
Ending Balance	$1	[1],[3]
[1]	Deducted from related assets.
[2]	Deducted from related assets, with a portion included in assets held for sale.
[3]	Included in revenues.