WPX Energy (WPX) 10-Q 5 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 04, 2014
Document Documentand Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'WPX	'
Entity Registrant Name	'WPX ENERGY, INC.	'
Entity Central Index Key	'0001518832	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	203,370,114

Consolidated_Balance_Sheet_Una

Consolidated Balance Sheet (Unaudited) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$65	$99
Accounts receivable, net of allowance of $6 million at September 30, 2014 and $7 million at December 31, 2013	465	536
Deferred income taxes	31	49
Derivative assets, current	107	50
Inventories	70	71
Margin deposits	52	71
Assets classified as held for sale, current	184	1
Other	31	45
Total current assets	1,005	922
Investments	135	129
Properties and equipment (successful efforts method of accounting)	11,993	12,519
Less—accumulated depreciation, depletion and amortization	-4,956	-5,445
Properties and equipment, net	7,037	7,074
Derivative assets, noncurrent	22	7
Other noncurrent assets	45	297
Total assets	8,244	8,429
Current liabilities:	'	'
Accounts payable	699	652
Accrued and other current liabilities	175	187
Liabilities associated with assets held for sale, current	50	3
Customer margin deposits payable	14	55
Deferred income taxes, current	1	0
Derivative liabilities, current	72	110
Total current liabilities	1,011	1,007
Deferred income taxes	713	788
Long-term debt	2,047	1,916
Derivative liabilities, noncurrent	15	12
Asset retirement obligations	199	310
Other noncurrent liabilities	57	186
Contingent liabilities and commitments (Note 8)	'	'
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; 203.4 million shares issued at September 30, 2014 and 201 million shares issued at December 31, 2013)	2	2
Additional paid-in-capital	5,556	5,516
Accumulated deficit	-1,463	-1,408
Accumulated other comprehensive income (loss)	-1	-1
Total stockholders’ equity	4,094	4,109
Noncontrolling interests in consolidated subsidiaries	108	101
Total equity	4,202	4,210
Total liabilities and equity	$8,244	$8,429

Consolidated_Balance_Sheet_Una1

Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Allowance for doubtful accounts	$6	$7
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	203,400,000	201,000,000

Consolidated_Statement_of_Oper

Consolidated Statement of Operations (Unaudited) (USD $)	3 Months Ended				9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014	Sep. 30, 2013
Product revenues:	'		'		'	'
Natural gas sales	$207		$210		$798	$699
Oil and condensate sales	240		183		638	473
Natural gas liquid sales	54		57		170	169
Total product revenues	501		450		1,606	1,341
Gas management	145		176		937	642
Net gain (loss) on derivatives not designated as hedges (Note 10)	148		-15		-64	-31
Other	0		5		6	16
Total revenues	794		616		2,485	1,968
Costs and expenses:	'		'		'	'
Lease and facility operating	73		70		208	196
Gathering, processing and transportation	82		88		250	264
Taxes other than income	40		33		121	95
Gas management, including charges for unutilized pipeline capacity	164		201		788	666
Exploration (Note 4)	29		21		101	59
Depreciation, depletion and amortization	213		230		627	662
Impairment of costs of acquired unproved reserves	0		19		0	19
Loss on sale of working interests in the Piceance Basin	1		0		196	0
General and administrative	75		67		219	209
Other—net	3		1		9	10
Total costs and expenses	680		730		2,519	2,180
Operating income (loss)	114		-114		-34	-212
Interest expense	-31		-28		-88	-82
Interest capitalized	1		1		1	1
Investment income and other	5		4		12	17
Income (loss) from continuing operations before income taxes	89		-137		-109	-276
Provision (benefit) for income taxes	28		-29		-31	-79
Income (Loss) from continuing operations	61		-108		-78	-197
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	5		-8		30	-10
Net income (loss)	66		-116		-48	-207
Less: Net income (loss) attributable to noncontrolling interests	4		-2		7	5
Net income (loss) attributable to WPX Energy, Inc.	$62		($114)		($55)	($212)
Basic and diluted earnings (loss) per common share:	'		'		'	'
Income (loss) from continuing operations	$0.28		($0.53)		($0.42)	($1.01)
Income (loss) from discontinued operations	$0.02		($0.04)		$0.15	($0.05)
Net income (loss)	$0.30		($0.57)		($0.27)	($1.06)
Weighted Average Number of Shares Outstanding, Basic	203.3		200.7		202.5	200.3
Weighted Average Number of Shares Outstanding, Diluted	207.5	[1]	200.7	[1]	202.5	200.3	[1]
[1]	For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.

Consolidated_Statement_of_Comp

Consolidated Statement of Comprehensive Income (Loss) (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
Net income (loss) attributable to WPX Energy, Inc.	$62	($114)	($55)	($212)
Other comprehensive income (loss):	'	'	'	'
Net reclassifications into earnings of net cash flow hedge realized gains, net of tax (a)	0	0	0	-3	[1]
Other comprehensive income (loss), net of tax	0	0	0	-3
Comprehensive income (loss) attributable to WPX Energy, Inc.	$62	($114)	($55)	($215)
[1]	Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million of income tax for the nine months ended September 30, 2013. Before tax amounts realized and reclassified to natural gas sales revenues on the Consolidated Statements of Operations were $5 million for the nine months ended September 30, 2013.

Consolidated_Statement_of_Comp1

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'
Reclassification adjustment on derivatives included in net income, tax	$2
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a)	$5

Consolidated_Statement_of_Chan

Consolidated Statement of Changes in Equity (Unaudited) (USD $)	Total	Common Stock	Additional Paid-In- Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Total Stockholders’ Equity	Noncontrolling Interests in Consolidated Subsidiaries
In Millions, unless otherwise specified
December 31, 2013 at Dec. 31, 2013	$4,210	$2	$5,516	($1,408)	($1)	$4,109	$101	[1]
Comprehensive income (loss):	'	'	'	'	'	'	'
Net income (loss)	-48	'	'	-55	'	-55	7	[1]
Other comprehensive loss	0	'	'	'	0	0	'
Comprehensive income (loss)	-48	'	'	'	'	'	'
Stock based compensation	40	'	40	'	'	40	'
Contributions from Noncontrolling Interests	0	'	'	'	'	'	0
September 30, 2014 at Sep. 30, 2014	$4,202	$2	$5,556	($1,463)	($1)	$4,094	$108	[1]
[1]	Primarily represents the 31 percent interest in Apco Oil and Gas International Inc. owned by others.

Consolidated_Statement_of_Chan1

Consolidated Statement of Changes in Equity (Parenthetical)	Sep. 30, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]	'	'
Noncontrolling interest, ownership percentage by noncontrolling owners	31.00%	31.00%

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013
Operating Activities	'		'
Net income (loss)	($48)		($207)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'		'
Depreciation Depletion And Amortization Including Discontinued Portion	638		699
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations	-55		-67
Provision for impairment of properties and equipment (including certain exploration expenses)	95		64
Amortization of stock-based awards	26		24
Gain (Loss) on Disposition of Assets	195		-5
Cash provided (used) by operating assets and liabilities:	'		'
Accounts receivable	71		55
Inventories	1		-5
Margin deposits and customer margin deposit payable	-22		-2
Other current assets	16		-11
Accounts payable	-15		-5
Accrued and other current liabilities	-22		-32
Changes in current and noncurrent derivative assets and liabilities	-106		18
Other, including changes in other noncurrent assets and liabilities	5		-6
Net cash provided by operating activities	779		520
Investing Activities	'		'
Capital expenditures	-1,325	[1]	-843	[1]
Proceeds from sale of assets	389	[2]	10	[2]
Other	-3		-3
Net cash used in investing activities	-939		-836
Financing Activities	'		'
Proceeds from common stock	15		4
Proceeds from long-term debt	500		0
Borrowings on credit facility	1,451		605
Payments on credit facility	-1,816		-335
Payments of Debt Issuance Costs	-6		'
Payments for debt issuance costs	'		0
Other	-12		-1
Net cash provided by financing activities	132		273
Net increase (decrease) in cash and cash equivalents	-28		-43
Effect of Exchange Rate on Cash and Cash Equivalents	-6		-2
Cash and cash equivalents at beginning of period	99		153
Cash and cash equivalents at end of period	65		108
Increase to properties and equipment	-1,389		-864
Changes in related accounts payable and accounts receivable	$64		$21
[1]	(a) Increase to properties and equipment(1,389) (864)Changes in related accounts payable and accounts receivable64 21Capital expenditures(1,325) (843)
[2]	(b) Proceeds in 2014 primarily relate to the sale of a portion of our working interests in the Piceance Basin and are subject to post-closing adjustments.

Basis_of_Presentation_and_Desc

Basis of Presentation and Description of Business	9 Months Ended
	Sep. 30, 2014
Accounting Policies [Abstract]	'
Basis of Presentation and Description of Business	'
	Basis of Presentation and Description of Business
	Basis of Presentation
	The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2013 in the Company’s Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2014, results of operations for the three and nine months ended September 30, 2014 and 2013, changes in equity for the nine months ended September 30, 2014 and cash flows for the nine months ended September 30, 2014 and 2013.
	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.
	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. As a result, we have reported the results of operations of the Powder River Basin as discontinued operations (see Note 2).
	Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
	Description of Business
	Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments.
	Domestic includes natural gas, oil and natural gas liquids (“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 and coalbed methane reserves 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.
	International primarily consists of our ownership 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. See Note 12 for a discussion of a recently announced agreement to sell our international interests.
	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”.
	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 have 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.

Discontinued_Operations_Discon

Discontinued Operations Discontinued Operations (Notes)	9 Months Ended
	Sep. 30, 2014
Discontinued operations [Abstract]	'
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	'
	Discontinued Operations
	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. The transaction is expected to close in the fourth quarter of 2014. The mid-year proved reserves in the basin were 222 Bcfe and third quarter production was 146 MMcf per day, which includes operated and non-operated working interests in approximately 5,000 wells. The Company has not actively drilled in the basin since 2011.
	Summarized Results of Discontinued Operations
		Three months						Nine months
		ended September 30,						ended September 30,
		2014			2013			2014		2013
		(Millions)
	Revenues	$	41		$	42		$	151	$	136
	Costs and expenses:
	Lease and facility operating	11			12			32		34
	Gathering, processing and transportation	16			18			51		60
	Taxes other than income	4			3			12		12
	Exploration	—			—			—		1
	Depreciation, depletion and amortization	3			11			11		37
	General and administrative	1			1			3		5
	Other—net	—			9			—		8
	Total costs and expenses	35			54			109		157
	Operating income (loss)	6			(12		)	42		(21		)
	Interest capitalized	—			1			1		3
	Investment income and other	1			—			4		3
	Income (loss) from discontinued operations before income taxes	7			(11		)	47		(15		)
	Provision (benefit) for income taxes	2			(3		)	17		(5		)
	Income (loss) from discontinued operations	$	5		$	(8	)	$	30	$	(10	)
	Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations
		September 30,			December 31, 2013 (a)
		2014
		(Millions)
	Assets
	Current assets:
	Inventories	$	1		$	1
	Total current assets	1			1
	Investments	18			16
	Properties and equipment (successful efforts method of accounting)	176			167
	Less—accumulated depreciation, depletion and amortization	(11		)	—
	Properties and equipment, net	165			167
	Total assets classified as held for sale (a)	$	184		$	184
	Liabilities and Equity
	Current liabilities:
	Accrued and other current liabilities	$	3		$	3
	Total current liabilities	3			3
	Asset retirement obligations	47			48
	Total liabilities associated with assets held for sale (a)	$	50		$	51
	__________
	(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.
	Cash Flows Attributable to Discontinued Operations
	Excluding taxes and changes to working capital related to Powder River, total cash provided by operating activities related to discontinued operations was $58 million and $23 million for the nine months ended September 30, 2014 and 2013, respectively. Total cash used in investing activities related to discontinued operations was $7 million and $3 million for the nine months ended September 30, 2014 and 2013, respectively.

Earnings_Loss_Per_Common_Share

Earnings (Loss) Per Common Share from Continuing Operations	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Earnings (Loss) Per Common Share from Continuing Operations	'
	Earnings (Loss) Per Common Share
	The following table summarizes the calculation of earnings per share.
		Three months					Nine months
		ended September 30,					ended September 30,
		2014		2013			2014			2013
		(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	$	57	$	(106	)	$	(85	)	$	(202	)
	Basic weighted-average shares	203.3		200.7			202.5			200.3
	Effect of dilutive securities (a):
	Nonvested restricted stock units and awards	3.2		—			—			—
	Stock options	1		—			—			—
	Diluted weighted-average shares	207.5		200.7			202.5			200.3
	Earnings (loss) per common share:
	Basic	$	0.28	$	(0.53	)	$	(0.42	)	$	(1.01	)
	Diluted	$	0.28	$	(0.53	)	$	(0.42	)	$	(1.01	)
	__________
	(a) For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.
	The table below includes information related to stock options that were outstanding as of September 30, 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.
		September 30,
		2014		2013
	Options excluded (millions)	—		0.4
	Weighted-average exercise price of options excluded	$	—	$	20.23
	Exercise price range of options excluded	—		$19.95 - $20.97
	Third quarter weighted-average market price	$	23.67	$	19.23

Asset_Sale_Impairments_and_Exp

Asset Sale, Impairments and Exploration Expense	9 Months Ended
	Sep. 30, 2014
Extractive Industries [Abstract]	'
Asset Sales Impairments Exploration Expenses And Other Accruals [Text Block]	'
	Asset Sale, Impairments and Exploration Expenses
	Asset Sale
	In May 2014, we agreed to the sale of portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP (“Legacy”) for $355 million cash, subject to closing adjustments and based on 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 represent approximately 300 billion cubic feet of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. Production related to these working interests for January through May approximated 70 MMcfe/day of our production. The sale closed at the beginning of June and we received proceeds of $337 million which were subject to post closing adjustments including settlement of production for April and May. We estimate the amount to be remitted to Legacy in the fourth quarter will be $12 million. 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.
	Impairment of Cost of Acquired Unproved Reserves
	As a result of declines in forward natural gas prices during the third quarter of 2013 as compared to prior periods, we performed impairment assessments of our capitalized cost of acquired unproved reserves. Accordingly, we recorded a $19 million impairment of capitalized costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin during the third quarter of 2013.
	Exploration Expenses
	The following table presents a summary of exploration expenses.
		Three months				Nine months
		ended September 30,				ended September 30,
		2014		2013		2014		2013
		(Millions)
	Geologic and geophysical costs	$	1	$	6	$	8	$	14
	Dry hole costs and impairments of exploratory area well costs	7		—		25		2
	Unproved leasehold property impairment, amortization and expiration	21		15		68		43
	Total exploration expenses	$	29	$	21	$	101	$	59
	Dry hole costs and impairments of exploratory area well costs for the three and nine months ended September 30, 2014 includes $6 million and $16 million, respectively, of impairments of well costs in exploratory areas in the United States where management has determined to cease exploratory activities. The remaining amount represents impairment of international well costs and dry hole costs associated with exploratory wells in the United States where hydrocarbons were not detected. As of September 30, 2014, our total domestic capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $70 million.
	Included in unproved leasehold property impairment, amortization and expiration for the three and nine months ended September 30, 2014, are impairments totaling $15 million and $41 million, respectively, for unproved leasehold costs in exploratory areas where the company no longer intends to continue exploration activities.

Inventories

Inventories	9 Months Ended
	Sep. 30, 2014
Inventory Disclosure [Abstract]	'
Inventories	'
	Inventories and Properties and Equipment
	Inventories
		September 30,			December 31,
		2014			2013
		(Millions)
	Natural gas in underground storage	$	14		$	13
	Crude oil production in transit	3			10
	Material, supplies and other	53			48
		$	70		$	71
	Properties and Equipment
	During the third quarter of 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 price is subject to post closing adjustments and therefore, the allocation is preliminary. The purchase is included within our capital expenditures on the Consolidated Statement of Cash Flows.
	Also during the third quarter of 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.
	Asset Retirement Obligation
	A rollforward of our asset retirement obligations for the current year is presented below.
		Nine months ended September 30, 2014
		(Millions)
	Balance, January 1, 2014	$	313
	Liabilities incurred	17
	Liabilities settled	(1		)
	Liabilities associated with assets sold	(65		)
	Estimate revisions (a)	(78		)
	Accretion expense	16
	Balance, September 30, 2014	202
	Amount reflected as current	$	3
	__________
	(a)	Estimate revisions are primarily associated with decreases in anticipated future plug and abandonment costs.

Debt_and_Banking_Arrangements

Debt and Banking Arrangements	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Debt and Banking Arrangements	'
	Debt and Banking Arrangements
	As of the indicated dates, our debt consisted of the following:
		September 30,		December 31,
		2014		2013
		(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	45		410
	Apco	6		8
	Other	1		1
	Total debt	$	2,052	$	1,919
	Less: Current portion of long-term debt	5		3
	Total long-term debt	$	2,047	$	1,916
	Senior Notes
	In September 2014, we issued $500 million in face value 5.25% Senior Notes due 2024 (the "Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 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 "Indenture"). The net proceeds from the offering of the 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 and for related transaction fees and expenses.
	Optional Redemption. We have the option, at any time or from time to time prior to June 15, 2024 (which is three months prior to the maturity date of the 2024 notes) to redeem some or all of the Notes at a specified "make whole" premium as described in the Indenture. We also have the option at any time or from time to time on or after June 15, 2024, to redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed.
	Change of Control. If we experience a change of control (as defined in the indenture governing the Notes) accompanied by a specified rating decline, we must offer to repurchase the Notes at 101% of their principal amount, plus accrued and unpaid interest.
	Covenants. The terms of the Indenture 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 Indenture also requires us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the Indenture. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The Indenture does 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 Indenture with respect to the Notes:
	(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
	At September 30, 2014 we had a $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”) that was set to expire in 2016. Under the terms of the Credit Facility Agreement and subject to certain requirements, we could 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. As of September 30, 2014, the variable interest rate was 4.13 percent on the $45 million outstanding under the Credit Facility Agreement.
	Subsequent to September 30, 2014, we amended and restated the Credit Facility Agreement, hereafter referred to as the "New Credit Facility Agreement". The terms of the New Credit Facility Agreement are materially the same as our Credit Facility Agreement, except that the New Credit Facility Agreement matures on October 28, 2019, the letters of credit sublimit is $750 million and we changed the Applicable Rates and revised our financial covenants as set forth below. As of November 4, 2014, we had $210 million outstanding under the New Credit Facility Agreement and approximately $1.3 billion of available capacity.
	Under the New Credit Facility Agreement, when our Index Debt is not rated BBB- or better by S&P or Baa3 or better by Moody’s and not less than BB+ or Ba1 by the other such agency, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the New Credit Facility Agreement) to Consolidated EBITDAX (as defined in the New 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 (as defined in the New Credit Facility Agreement) 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.  During a Downgrade Period (as defined in the New Credit Facility Agreement), we will be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the New 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 thereafter. This covenant will not apply after the occurrence of the Investment Grade Date, which is the first date after closing on which our Index Debt ratings are 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.
	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 New Credit Facility Agreement. At September 30, 2014, a total of $324 million in letters of credit have been issued.

Provision_Benefit_for_Income_T

Provision (Benefit) for Income Taxes	9 Months Ended
	Sep. 30, 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:
		Three months						Nine months
		ended September 30,						ended September 30,
		2014			2013			2014			2013
		(Millions)
	Current:
	Federal	$	(5	)	$	(31	)	$	12		$	(28	)
	State	(3		)	—			1			—
	Foreign	4			3			8			11
		(4		)	(28		)	21			(17		)
	Deferred:
	Federal	29			(27		)	(59		)	(84		)
	State	3			12			6			8
	Foreign	—			14			1			14
		32			(1		)	(52		)	(62		)
	Total provision (benefit)	$	28		$	(29	)	$	(31	)	$	(79	)
	The effective tax rate for all periods presented above differs from the federal statutory rate primarily due to the effects of state income taxes and taxes on foreign operations.
	Tax reform legislation was enacted by the state of New York on March 31, 2014, and has 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.
	As of September 30, 2014, the amount of unrecognized tax benefits is not material. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with domestic or international matters will result in a significant increase or decrease of our unrecognized tax benefit.
	In September 2013, the Argentine government enacted tax reform legislation related to dividends and capital gains which will apply to the Argentine operations of our consolidated investment in Apco, a Cayman Islands corporation. As a result, Apco recorded approximately $14 million of foreign deferred tax expense during third quarter 2013. This accrual was partially offset by approximately $4 million of U.S. deferred tax benefit recorded by WPX.
	Pursuant to our tax sharing agreement with The Williams Companies, Inc. (“Williams”), we remain responsible for the tax from audit adjustments related to our business for periods prior to 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 issues 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 unrelated to our business.

Contingent_Liabilities

Contingent Liabilities	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Contingent Liabilities	'
	Contingent Liabilities
	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 process under that standard of conducting an accounting, and the parties have jointly submitted the information to the court for approval. However, we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law.
	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 October 2007 through September 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.
	Matter 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 September 30, 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 September 30, 2014 and December 31, 2013, the Company had accrued approximately $20 million and $16 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
	Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	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.
		September 30, 2014								December 31, 2013
		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
		(Millions)								(Millions)
	Energy derivative assets	$	18	$	110	$	1	$	129	$	30	$	26	$	1	$	57
	Energy derivative liabilities	$	61	$	26	$	—	$	87	$	83	$	38	$	1	$	122
	Total debt (a)	$	—	$	2,081	$	—	$	2,081	$	—	$	1,945	$	—	$	1,945
	__________
	(a)	The carrying value of total debt, excluding capital leases, was $2,051 million and $1,918 million as of September 30, 2014 and December 31, 2013, respectively.
	Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
	Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
	The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
	Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
	Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars 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 at the end of 2015. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.
	Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 were a net asset of $1 million at September 30, 2014, and 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 occurred during the periods ended September 30, 2014 and 2013.
	There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

Derivatives_and_Concentration_

Derivatives and Concentration of Credit Risk	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Derivatives and Concentration of Credit Risk	'
	Derivatives and Concentration of Credit Risk
	Energy Commodity Derivatives
	Risk Management Activities
	We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of 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.
	The following table sets forth the derivative notional volumes that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2014.
	Derivatives related to production
	Commodity		Period		Contract Type (a)		Location		Notional Volume (b)			Weighted Average
												Price (c)
	Natural Gas
	Natural Gas		Oct-Dec 2014		Fixed Price Swaps		Henry Hub		(315	)		$	4.19
	Natural Gas		Oct-Dec 2014		Swaptions		Henry Hub		(50	)		$	4.24
	Natural Gas		Oct-Dec 2014		Costless Collars		Henry Hub		(190	)		$ 4.04 - 4.66
	Natural Gas		Oct-Dec 2014		Basis Swaps		Dominion		(39	)		$	(0.73	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		NGPL		(30	)		$	(0.19	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		Rockies		(143	)		$	(0.15	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		San Juan		(255	)		$	(0.15	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		SoCal		(73	)		$	0.13
	Natural Gas		2015		Fixed Price Swaps		Henry Hub		(272	)		$	4.31
	Natural Gas		2015		Swaptions		Henry Hub		(50	)		$	4.38
	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		Swaptions		Henry Hub		(90	)		$	4.23
	Crude Oil
	Crude Oil		Oct-Dec 2014		Fixed Price Swaps		WTI		(14,975	)		$	96.01
	Crude Oil		2015		Fixed Price Swaps		WTI		(20,236	)		$	94.88
	Crude Oil		2015		Swaptions		WTI		(8,382	)		$	94.9
	Crude Oil		2016		Swaptions		WTI		(5,250	)		$	97.55
	NGL
	NGL Ethane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(3,261	)		$	0.29
	NGL Propane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(489	)		$	1.17
	NGL Iso Butane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(652	)		$	1.37
	NGL Normal Butane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(652	)		$	1.34
	NGL Natural Gasoline		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(1,630	)		$	2.06
	__________
	(a)	Derivatives related to crude oil production are business day average swaps, basis swaps and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. 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, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
	(c)	The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon. All natural gas basis swaps are based on a differential to Henry Hub.
	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 September 30, 2014.
	Derivatives primarily related to storage and transportation
	Commodity		Period		Contract Type (a)		Location (b)		Notional Volume (c)			Weighted Average
												Price (d)
	Natural Gas		Oct-Dec 2014		Fixed Price Swaps		Multiple		8			—
	Natural Gas		Oct-Dec 2014		Basis Swaps		Multiple		(31	)		—
	Natural Gas		Oct-Dec 2014		Index		Multiple		(145	)		—
	Natural Gas		2015		Fixed Price Swaps		Multiple		(11	)		—
	Natural Gas		2015		Basis Swaps		Multiple		(12	)		—
	Natural Gas		2015		Index		Multiple		(118	)		—
	Natural Gas		2016		Index		Multiple		(70	)		—
	Natural Gas		2017+		Index		Multiple		(478	)		—
	__________
	(a)	WPX Marketing enters 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)	WPX Marketing transacts 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.
	(d)	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.
	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.
		30-Sep-14								31-Dec-13
		Assets				Liabilities				Assets				Liabilities
	(Millions)
Derivatives related to production not designated as hedging instruments	$	110			$	26			$	26			$	39
Derivatives related to physical marketing agreements not designated as hedging instruments	19				61				31				83
Total derivatives not designated as hedging instruments	$	129			$	87			$	57			$	122
During the first nine months of 2013, we reclassified $5 million of net gain on derivatives designated as cash flow hedges from accumulated other comprehensive income (loss) into income. These gains primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas 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.
	Three months								Nine months
	ended September 30,								ended September 30,
	2014				2013				2014				2013
	(Millions)
Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	150			$	(18	)		$	40			$	(29	)
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(2		)		3				(104		)		(2		)
Net gain (loss) on derivatives not designated as hedges	$	148			$	(15	)		$	(64	)		$	(31	)
__________
(a)	Includes receipts totaling $10 million and $1 million for settlements of derivatives during the three months ended September 30, 2014 and 2013, respectively; and payments totaling $57 million and $14 million for the nine months ended September 30, 2014 and 2013, respectively.
(b)	Includes receipts totaling $5 million for settlements of derivatives during the three months ended September 30, 2014 and payments totaling $2 million during the three months ended September 30, 2013; and payments totaling $114 million for the nine months ended September 30, 2014 and receipts of $1 million for the nine months ended September 30, 2013.
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
30-Sep-14	(Millions)
Derivative assets with right of offset or master netting agreements	$	129			$	(43	)		$	—			$	86
Derivative liabilities with right of offset or master netting agreements	$	(87	)		$	43			$	43			$	(1	)
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 Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of September 30, 2014, we had collateral totaling $51 million posted to derivative counterparties, which included $8 million of initial margin to clearinghouses or exchanges to enter into positions and $43 million of maintenance margin for changes in the fair value of those positions, to support the aggregate fair value of our net $44 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. 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 $1 million at September 30, 2014.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
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 and 2013, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
The gross and net credit exposure from our derivative contracts as of September 30, 2014, is summarized as follows:
Counterparty Type	Gross Investment				Gross Total				Net Investment				Net Total
	Grade  (a)								Grade  (a)
	(Millions)
Financial institutions	$	128			$	128			$	85			$	85
Utilities	—				1				—				1
	$	128			129				$	85			86
Credit reserves					—								—
Credit exposure from derivatives					$	129							$	86
__________
(a)	We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
Our nine largest net counterparty positions represent approximately 94 percent of our gross 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
The customer margin deposits payable as of September 30, 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.

Segment_Disclosures

Segment Disclosures	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Segment Disclosures	'
	Segment Disclosures
	Our reporting segments are domestic and international (see Note 1).
	Our segment presentation is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions. Domestic and international maintain separate capital and cash management structures. These factors, coupled with differences in the business environment associated with operating in different countries, serve to differentiate the management of this entity as a whole.
	Performance Measurement
	We evaluate performance based upon segment revenues and segment operating income (loss). There are no intersegment sales between domestic and international.
	The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statements of Operations.
		Domestic			International		Total
					(Millions)
	Three months ended September 30, 2014
	Total revenues	$	747		$	47	$	794
	Costs and expenses:
	Lease and facility operating	$	63		$	10	$	73
	Gathering, processing and transportation	82			—		82
	Taxes other than income	32			8		40
	Gas management, including charges for unutilized pipeline capacity	164			—		164
	Exploration (Note 4)	28			1		29
	Depreciation, depletion and amortization	201			12		213
	Loss on sale of working interests in the Piceance Basin	1			—		1
	General and administrative	71			4		75
	Other—net	3			—		3
	Total costs and expenses	$	645		$	35	$	680
	Operating income (loss)	$	102		$	12	$	114
	Interest expense	(31		)	—		(31		)
	Interest capitalized	1			—		1
	Investment income and other	(1		)	6		5
	Income (loss) from continuing operations before income taxes	$	71		$	18	$	89
	Three months ended September 30, 2013
	Total revenues	$	581		$	35	$	616
	Costs and expenses:
	Lease and facility operating	$	62		$	8	$	70
	Gathering, processing and transportation	88			—		88
	Taxes other than income	27			6		33
	Gas management, including charges for unutilized pipeline capacity	201			—		201
	Exploration (Note 4)	21			—		21
	Depreciation, depletion and amortization	222			8		230
	Impairment of costs of acquired unproved reserves (Note 4)	19			—		19
	General and administrative	64			3		67
	Other—net	(2		)	3		1
	Total costs and expenses	$	702		$	28	$	730
	Operating income (loss)	$	(121	)	$	7	$	(114	)
	Interest expense	(28		)	—		(28		)
	Interest capitalized	1			—		1
	Investment income and other	—			4		4
	Income (loss) from continuing operations before income taxes	$	(148	)	$	11	$	(137	)
		Domestic			International		Total
					(Millions)
	Nine months ended September 30, 2014
	Total revenues	$	2,368		$	117	$	2,485
	Costs and expenses:
	Lease and facility operating	$	182		$	26	$	208
	Gathering, processing and transportation	249			1		250
	Taxes other than income	100			21		121
	Gas management, including charges for unutilized pipeline capacity	788			—		788
	Exploration (Note 4)	97			4		101
	Depreciation, depletion and amortization	596			31		627
	Loss on sale of working interests in the Piceance Basin	196			—		196
	General and administrative	208			11		219
	Other—net	6			3		9
	Total costs and expenses	$	2,422		$	97	$	2,519
	Operating income (loss)	$	(54	)	$	20	$	(34	)
	Interest expense	(88		)	—		(88		)
	Interest capitalized	1			—		1
	Investment income and other	(1		)	13		12
Income (loss) from continuing operations before income taxes	$	(142	)	$	33	$	(109	)
Nine months ended September 30, 2013
Total revenues	$	1,855		$	113	$	1,968
Costs and expenses:
Lease and facility operating	$	170		$	26	$	196
Gathering, processing and transportation	262			2		264
Taxes other than income	77			18		95
Gas management, including charges for unutilized pipeline capacity	666			—		666
Exploration (Note 4)	55			4		59
Depreciation, depletion and amortization	637			25		662
Impairment of costs of acquired unproved reserves (Note 4)	19			—		19
General and administrative	198			11		209
Other—net	10			—		10
Total costs and expenses	$	2,094		$	86	$	2,180
Operating income (loss)	$	(239	)	$	27	$	(212	)
Interest expense	(82		)	—		(82		)
Interest capitalized	1			—		1
Investment income and other	1			16		17
Income (loss) from continuing operations before income taxes	$	(319	)	$	43	$	(276	)
Total assets
Total assets as of September 30, 2014	$	7,838		$	406	$	8,244
Total assets as of December 31, 2013	$	8,046		$	383	$	8,429

Subsequent_Events_Notes

Subsequent Events (Notes)	9 Months Ended
	Sep. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Events [Text Block]	'
	Subsequent Events
	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 Oil and Gas International ("APCO"). Our international interests include a 69 percent controlling equity interest in APCO, additional non-material assets in wholly-owned Northwest Argentina and a 5 percent interest in Apco Argentina. Our international interests did not qualify as assets held for sale as of September 30, 2014. Therefore, the results of operations and financial position of our international segment will be reported in discontinued operations in future filings.

Discontinued_Operations_Discon1

Discontinued Operations Discontinued Operation (Tables)	9 Months Ended
	Sep. 30, 2014
Discontinued Operations and Disposal Groups [Abstract]	'
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]	'
	Summarized Results of Discontinued Operations
		Three months						Nine months
		ended September 30,						ended September 30,
		2014			2013			2014		2013
		(Millions)
	Revenues	$	41		$	42		$	151	$	136
	Costs and expenses:
	Lease and facility operating	11			12			32		34
	Gathering, processing and transportation	16			18			51		60
	Taxes other than income	4			3			12		12
	Exploration	—			—			—		1
	Depreciation, depletion and amortization	3			11			11		37
	General and administrative	1			1			3		5
	Other—net	—			9			—		8
	Total costs and expenses	35			54			109		157
	Operating income (loss)	6			(12		)	42		(21		)
	Interest capitalized	—			1			1		3
	Investment income and other	1			—			4		3
	Income (loss) from discontinued operations before income taxes	7			(11		)	47		(15		)
	Provision (benefit) for income taxes	2			(3		)	17		(5		)
	Income (loss) from discontinued operations	$	5		$	(8	)	$	30	$	(10	)
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block]	'
	Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations
		September 30,			December 31, 2013 (a)
		2014
		(Millions)
	Assets
	Current assets:
	Inventories	$	1		$	1
	Total current assets	1			1
	Investments	18			16
	Properties and equipment (successful efforts method of accounting)	176			167
	Less—accumulated depreciation, depletion and amortization	(11		)	—
	Properties and equipment, net	165			167
	Total assets classified as held for sale (a)	$	184		$	184
	Liabilities and Equity
	Current liabilities:
	Accrued and other current liabilities	$	3		$	3
	Total current liabilities	3			3
	Asset retirement obligations	47			48
	Total liabilities associated with assets held for sale (a)	$	50		$	51
	__________
	(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)	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Earnings (Loss) Per Common Share from Continuing Operations	'
	The following table summarizes the calculation of earnings per share.
		Three months					Nine months
		ended September 30,					ended September 30,
		2014		2013			2014			2013
		(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	$	57	$	(106	)	$	(85	)	$	(202	)
	Basic weighted-average shares	203.3		200.7			202.5			200.3
	Effect of dilutive securities (a):
	Nonvested restricted stock units and awards	3.2		—			—			—
	Stock options	1		—			—			—
	Diluted weighted-average shares	207.5		200.7			202.5			200.3
	Earnings (loss) per common share:
	Basic	$	0.28	$	(0.53	)	$	(0.42	)	$	(1.01	)
	Diluted	$	0.28	$	(0.53	)	$	(0.42	)	$	(1.01	)
	__________
	(a) For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.
Schedule of Stock Options Outstanding Excluded from Computation of weighted-average stock	'
	The table below includes information related to stock options that were outstanding as of September 30, 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.
		September 30,
		2014		2013
	Options excluded (millions)	—		0.4
	Weighted-average exercise price of options excluded	$	—	$	20.23
	Exercise price range of options excluded	—		$19.95 - $20.97
	Third quarter weighted-average market price	$	23.67	$	19.23

Exploration_Expense_Tables

Exploration Expense (Tables)	9 Months Ended
	Sep. 30, 2014
Extractive Industries [Abstract]	'
Exploration Expenses	'
	The following table presents a summary of exploration expenses.
		Three months				Nine months
		ended September 30,				ended September 30,
		2014		2013		2014		2013
		(Millions)
	Geologic and geophysical costs	$	1	$	6	$	8	$	14
	Dry hole costs and impairments of exploratory area well costs	7		—		25		2
	Unproved leasehold property impairment, amortization and expiration	21		15		68		43
	Total exploration expenses	$	29	$	21	$	101	$	59

Inventories_Tables

Inventories (Tables)	9 Months Ended
	Sep. 30, 2014
Inventory Disclosure [Abstract]	'
Inventories	'
		September 30,			December 31,
		2014			2013
		(Millions)
	Natural gas in underground storage	$	14		$	13
	Crude oil production in transit	3			10
	Material, supplies and other	53			48
		$	70		$	71
Schedule of Asset Retirement Obligations [Table Text Block]	'
	A rollforward of our asset retirement obligations for the current year is presented below.
		Nine months ended September 30, 2014
		(Millions)
	Balance, January 1, 2014	$	313
	Liabilities incurred	17
	Liabilities settled	(1		)
	Liabilities associated with assets sold	(65		)
	Estimate revisions (a)	(78		)
	Accretion expense	16
	Balance, September 30, 2014	202
	Amount reflected as current	$	3
	__________
	(a)	Estimate revisions are primarily associated with decreases in anticipated future plug and abandonment costs.

Debt_and_Banking_Arrangements_

Debt and Banking Arrangements (Tables)	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Schedule of Long-term Debt Instruments	'
	As of the indicated dates, our debt consisted of the following:
		September 30,		December 31,
		2014		2013
		(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	45		410
	Apco	6		8
	Other	1		1
	Total debt	$	2,052	$	1,919
	Less: Current portion of long-term debt	5		3
	Total long-term debt	$	2,047	$	1,916

Provision_Benefit_for_Income_T1

Provision (Benefit) for Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Provision (Benefit) for Income Taxes from Continuing Operations	'
	The provision (benefit) for income taxes from continuing operations includes:
		Three months						Nine months
		ended September 30,						ended September 30,
		2014			2013			2014			2013
		(Millions)
	Current:
	Federal	$	(5	)	$	(31	)	$	12		$	(28	)
	State	(3		)	—			1			—
	Foreign	4			3			8			11
		(4		)	(28		)	21			(17		)
	Deferred:
	Federal	29			(27		)	(59		)	(84		)
	State	3			12			6			8
	Foreign	—			14			1			14
		32			(1		)	(52		)	(62		)
	Total provision (benefit)	$	28		$	(29	)	$	(31	)	$	(79	)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 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.
		September 30, 2014								December 31, 2013
		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
		(Millions)								(Millions)
	Energy derivative assets	$	18	$	110	$	1	$	129	$	30	$	26	$	1	$	57
	Energy derivative liabilities	$	61	$	26	$	—	$	87	$	83	$	38	$	1	$	122
	Total debt (a)	$	—	$	2,081	$	—	$	2,081	$	—	$	1,945	$	—	$	1,945
	__________
	(a)	The carrying value of total debt, excluding capital leases, was $2,051 million and $1,918 million as of September 30, 2014 and December 31, 2013, respectively.

Derivatives_and_Concentration_1

Derivatives and Concentration of Credit Risk (Tables)	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Derivative Volume that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production	'
	The following table sets forth the derivative notional volumes that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2014.
	Derivatives related to production
	Commodity		Period		Contract Type (a)		Location		Notional Volume (b)			Weighted Average
												Price (c)
	Natural Gas
	Natural Gas		Oct-Dec 2014		Fixed Price Swaps		Henry Hub		(315	)		$	4.19
	Natural Gas		Oct-Dec 2014		Swaptions		Henry Hub		(50	)		$	4.24
	Natural Gas		Oct-Dec 2014		Costless Collars		Henry Hub		(190	)		$ 4.04 - 4.66
	Natural Gas		Oct-Dec 2014		Basis Swaps		Dominion		(39	)		$	(0.73	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		NGPL		(30	)		$	(0.19	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		Rockies		(143	)		$	(0.15	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		San Juan		(255	)		$	(0.15	)
	Natural Gas		Oct-Dec 2014		Basis Swaps		SoCal		(73	)		$	0.13
	Natural Gas		2015		Fixed Price Swaps		Henry Hub		(272	)		$	4.31
	Natural Gas		2015		Swaptions		Henry Hub		(50	)		$	4.38
	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		Swaptions		Henry Hub		(90	)		$	4.23
	Crude Oil
	Crude Oil		Oct-Dec 2014		Fixed Price Swaps		WTI		(14,975	)		$	96.01
	Crude Oil		2015		Fixed Price Swaps		WTI		(20,236	)		$	94.88
	Crude Oil		2015		Swaptions		WTI		(8,382	)		$	94.9
	Crude Oil		2016		Swaptions		WTI		(5,250	)		$	97.55
	NGL
	NGL Ethane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(3,261	)		$	0.29
	NGL Propane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(489	)		$	1.17
	NGL Iso Butane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(652	)		$	1.37
	NGL Normal Butane		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(652	)		$	1.34
	NGL Natural Gasoline		Oct-Dec 2014		Fixed Price Swaps		Mont Belvieu		(1,630	)		$	2.06
	__________
	(a)	Derivatives related to crude oil production are business day average swaps, basis swaps and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. 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, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
	(c)	The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon. All natural gas basis swaps are based on a differential to Henry Hub.
	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 September 30, 2014.
	Derivatives primarily related to storage and transportation
	Commodity		Period		Contract Type (a)		Location (b)		Notional Volume (c)			Weighted Average
												Price (d)
	Natural Gas		Oct-Dec 2014		Fixed Price Swaps		Multiple		8			—
	Natural Gas		Oct-Dec 2014		Basis Swaps		Multiple		(31	)		—
	Natural Gas		Oct-Dec 2014		Index		Multiple		(145	)		—
	Natural Gas		2015		Fixed Price Swaps		Multiple		(11	)		—
	Natural Gas		2015		Basis Swaps		Multiple		(12	)		—
	Natural Gas		2015		Index		Multiple		(118	)		—
	Natural Gas		2016		Index		Multiple		(70	)		—
	Natural Gas		2017+		Index		Multiple		(478	)		—
	__________
	(a)	WPX Marketing enters 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)	WPX Marketing transacts 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.
	(d)	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.
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.
		30-Sep-14								31-Dec-13
		Assets				Liabilities				Assets				Liabilities
		(Millions)
	Derivatives related to production not designated as hedging instruments	$	110			$	26			$	26			$	39
	Derivatives related to physical marketing agreements not designated as hedging instruments	19				61				31				83
	Total derivatives not designated as hedging instruments	$	129			$	87			$	57			$	122
Derivative Gain (Loss)	'
	The following table presents the net gain (loss) related to our energy commodity derivatives.
		Three months								Nine months
		ended September 30,								ended September 30,
		2014				2013				2014				2013
		(Millions)
	Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	150			$	(18	)		$	40			$	(29	)
	Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(2		)		3				(104		)		(2		)
	Net gain (loss) on derivatives not designated as hedges	$	148			$	(15	)		$	(64	)		$	(31	)
	__________
	(a)	Includes receipts totaling $10 million and $1 million for settlements of derivatives during the three months ended September 30, 2014 and 2013, respectively; and payments totaling $57 million and $14 million for the nine months ended September 30, 2014 and 2013, respectively.
	(b)	Includes receipts totaling $5 million for settlements of derivatives during the three months ended September 30, 2014 and payments totaling $2 million during the three months ended September 30, 2013; and payments totaling $114 million for the nine months ended September 30, 2014 and receipts of $1 million for the
Gross And Net Derivative Assets and Liabilities	'
	The following table presents our gross and net derivative assets and liabilities.
		Gross Amount Presented on Balance Sheet				Netting Adjustments (a)				Cash Collateral Posted (Received)				Net Amount
	30-Sep-14	(Millions)
	Derivative assets with right of offset or master netting agreements	$	129			$	(43	)		$	—			$	86
	Derivative liabilities with right of offset or master netting agreements	$	(87	)		$	43			$	43			$	(1	)
	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.
Gross and Net Credit Exposure from Derivative Contracts	'
	The gross and net credit exposure from our derivative contracts as of September 30, 2014, is summarized as follows:
	Counterparty Type	Gross Investment				Gross Total				Net Investment				Net Total
		Grade  (a)								Grade  (a)
		(Millions)
	Financial institutions	$	128			$	128			$	85			$	85
	Utilities	—				1				—				1
		$	128			129				$	85			86
	Credit reserves					—								—
	Credit exposure from derivatives					$	129							$	86
	__________
	(a)	We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Segment_Disclosures_Tables

Segment Disclosures (Tables)	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Reconciliation of Segment Revenues and Segment Operating Income (Loss)	'
	The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statements of Operations.
		Domestic			International		Total
					(Millions)
	Three months ended September 30, 2014
	Total revenues	$	747		$	47	$	794
	Costs and expenses:
	Lease and facility operating	$	63		$	10	$	73
	Gathering, processing and transportation	82			—		82
	Taxes other than income	32			8		40
	Gas management, including charges for unutilized pipeline capacity	164			—		164
	Exploration (Note 4)	28			1		29
	Depreciation, depletion and amortization	201			12		213
	Loss on sale of working interests in the Piceance Basin	1			—		1
	General and administrative	71			4		75
	Other—net	3			—		3
	Total costs and expenses	$	645		$	35	$	680
	Operating income (loss)	$	102		$	12	$	114
	Interest expense	(31		)	—		(31		)
	Interest capitalized	1			—		1
	Investment income and other	(1		)	6		5
	Income (loss) from continuing operations before income taxes	$	71		$	18	$	89
	Three months ended September 30, 2013
	Total revenues	$	581		$	35	$	616
	Costs and expenses:
	Lease and facility operating	$	62		$	8	$	70
	Gathering, processing and transportation	88			—		88
	Taxes other than income	27			6		33
	Gas management, including charges for unutilized pipeline capacity	201			—		201
	Exploration (Note 4)	21			—		21
	Depreciation, depletion and amortization	222			8		230
	Impairment of costs of acquired unproved reserves (Note 4)	19			—		19
	General and administrative	64			3		67
	Other—net	(2		)	3		1
	Total costs and expenses	$	702		$	28	$	730
	Operating income (loss)	$	(121	)	$	7	$	(114	)
	Interest expense	(28		)	—		(28		)
	Interest capitalized	1			—		1
	Investment income and other	—			4		4
	Income (loss) from continuing operations before income taxes	$	(148	)	$	11	$	(137	)
		Domestic			International		Total
					(Millions)
	Nine months ended September 30, 2014
	Total revenues	$	2,368		$	117	$	2,485
	Costs and expenses:
	Lease and facility operating	$	182		$	26	$	208
	Gathering, processing and transportation	249			1		250
	Taxes other than income	100			21		121
	Gas management, including charges for unutilized pipeline capacity	788			—		788
	Exploration (Note 4)	97			4		101
	Depreciation, depletion and amortization	596			31		627
	Loss on sale of working interests in the Piceance Basin	196			—		196
	General and administrative	208			11		219
	Other—net	6			3		9
	Total costs and expenses	$	2,422		$	97	$	2,519
	Operating income (loss)	$	(54	)	$	20	$	(34	)
	Interest expense	(88		)	—		(88		)
	Interest capitalized	1			—		1
	Investment income and other	(1		)	13		12
	Income (loss) from continuing operations before income taxes	$	(142	)	$	33	$	(109	)
	Nine months ended September 30, 2013
	Total revenues	$	1,855		$	113	$	1,968
	Costs and expenses:
	Lease and facility operating	$	170		$	26	$	196
Gathering, processing and transportation	262			2		264
Taxes other than income	77			18		95
Gas management, including charges for unutilized pipeline capacity	666			—		666
Exploration (Note 4)	55			4		59
Depreciation, depletion and amortization	637			25		662
Impairment of costs of acquired unproved reserves (Note 4)	19			—		19
General and administrative	198			11		209
Other—net	10			—		10
Total costs and expenses	$	2,094		$	86	$	2,180
Operating income (loss)	$	(239	)	$	27	$	(212	)
Interest expense	(82		)	—		(82		)
Interest capitalized	1			—		1
Investment income and other	1			16		17
Income (loss) from continuing operations before income taxes	$	(319	)	$	43	$	(276	)
Total assets
Total assets as of September 30, 2014	$	7,838		$	406	$	8,244
Total assets as of December 31, 2013	$	8,046		$	383	$	8,429

Discontinued_Operations_Discon2

Discontinued Operations Discontinued Operation (Details) (USD $)	3 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013	Dec. 31, 2013
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'		'	'		'	'
Disposal Group, Including Discontinued Operation, Revenue	$41		$42	$151		$136	'
Disposal Group, Including Discontinued Operation, Lease Operating Expense	11		12	32		34	'
Disposal Group Including Discontinued Operation Gathering and Transportation Expense	16		18	51		60	'
Disposal Group, Including Discontinued Operation Taxes other than income	4		3	12		12	'
Disposal Group Including Discontinued Operation Exploration Expense	0		0	0		1	'
Disposal Group, Including Discontinued Operation, Depreciation and Amortization	3		11	11		37	'
Disposal Group, Including Discontinued Operation, General and Administrative Expense	1		1	3		5	'
Disposal Group, Including Discontinued Operation, Other Expense	0		9	0		8	'
Disposal Group, Including Discontinued Operation, Operating Expense	35		54	109		157	'
Disposal Group, Including Discontinued Operation, Operating Income (Loss)	6		-12	42		-21	'
Disposal Group including Discontinued Operation Interest Costs Capitalized	0		1	1		3	'
Disposal Group Including Discontinued Operation Investment Income	1		0	4		3	'
Disposal Group Including Discontinued Operation Income before Tax	7		-11	47		-15	'
Discontinued Operation, Tax Effect of Discontinued Operation	2		-3	17		-5	'
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	5		-8	30		-10	'
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]	'		'	'		'	'
Disposal Group, Including Discontinued Operation, Inventory	1		'	1		'	1
Assets of Disposal Group, Including Discontinued Operation, Current	1		'	1		'	1
Disposal Group, Including Discontinued Operation, Investment	18		'	18		'	16	[1]
Disposal Group Including Discontinued Operations Properties and Equipment (successful effort method)	176		'	176		'	167	[1]
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization	-11		'	-11		'	0	[1]
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net	165		'	165		'	167	[1]
Assets of Disposal Group, Including Discontinued Operation, Noncurrent	184		'	184		'	184	[1]
Disposal Group, Including Discontinued Operation, Other Current Liabilities	3		'	3		'	3
Liabilities of Disposal Group, Including Discontinued Operation, Current	3		'	3		'	3
Disposal Group, Including Discontinued Operations Asset Retirement Obligations, Noncurrent	47		'	47		'	48	[1]
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent	50	[1]	'	50	[1]	'	51	[1]
Additional Disclosures [Abstract]	'		'	'		'	'
Daily Production	146		'	'		'	'
Productive Oil Wells, Number of Wells, Gross	5,000		'	5,000		'	'
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities	'		'	58		23	'
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities	'		'	7		3	'
Powder River Basin [Member]	'		'	'		'	'
Additional Disclosures [Abstract]	'		'	'		'	'
Acquistion costs or sale proceeds	$155		'	$155		'	'
Proved Reserves Related to Sale of Assets	222		'	222		'	'
[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.

Earnings_Loss_Per_Common_Share2

Earnings (Loss) Per Common Share from Continuing Operations (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'	'
Income (Loss) from Continuing Operations Attributable to Parent	$57		($106)		($85)	($202)
Weighted Average Number of Shares Outstanding, Basic	203.3		200.7		202.5	200.3
Weighted Average Number of Shares Outstanding, Diluted	207.5	[1]	200.7	[1]	202.5	200.3	[1]
Basic (in dollars per share)	$0.28		($0.53)		($0.42)	($1.01)
Diluted (in dollars per share)	$0.28		($0.53)		($0.42)	($1.01)
Non Vested Restricted Stock Units [Member]	'		'		'	'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'		2.7		2.8	2.3
Employee Stock Option [Member]	'		'		'	'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'		1.2		1	1.1
Non Vested Restricted Stock Units [Member]	'		'		'	'
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	3.2		0		0	0
Employee Stock Option [Member]	'		'		'	'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'	'
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	1		0		0	0
[1]	For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.

Earnings_Loss_Per_Common_Share3

Earnings (Loss) Per Common Share from Continuing Operations (Details 1) (USD $)	9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]	'	'
Options excluded (millions)	0	0.4
Weighted-average exercise price of options excluded	$0	$20.23
Exercise price range of options excluded, lower limit	$0	$19.95
Exercise price range of options excluded, upper limit	$0	$20.97
Third quarter weighted-average market price	$23.67	$19.23

Exploration_Expense_Details

Exploration Expense (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'	'
Geologic and geophysical costs	$1	$6	$8	$14
Dry hole costs and impairments of exploratory area well costs	7	0	25	2
Unproved leasehold property impairment, amortization and expiration	21	15	68	43
Total exploration expenses	$29	$21	$101	$59

Asset_Sale_Impairments_and_Exp1

Asset Sale, Impairments and Exploration Expense Exploration Expense Additional Information (Details) (USD $)

3 Months Ended

5 Months Ended

6 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

31-May-14

Jun. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Subsequent Event [Member]

Post Closing [Member]

Working Interests [Member]

Exploratory Area [Member]

Exploratory Area [Member]

Legacy [Member]

Piceance Basin [Member]

Piceance Basin [Member]

Legacy [Member]

MMcf

Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Final Settlement Adjustment

'

'

'

'

'

'

$12

'

'

'

'

'

'

Proved Reserves Related to Sale of Assets

'

'

'

'

'

'

'

'

'

'

'

300,000

'

Percentage Ownership Of Incentive Distribution Rights

10.00%

'

'

'

10.00%

'

'

'

'

'

'

'

'

Production Related To The Sale Of Working Interests

'

'

70,000

'

'

'

'

'

'

'

'

'

'

Percentage of proved reserves attributed to sale of producing assets

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

Proceeds from sale of assets

'

'

'

'

389

[1]

10

[1]

'

329

337

'

'

'

355

Exploration Abandonment and Impairment Expense

6

'

'

'

16

'

'

'

'

'

'

'

'

Loss on sale of working interests in the Piceance Basin

1

0

'

195

196

0

'

'

'

'

'

'

'

Costs Incurred Exploration Costs Not Expensed

'

'

'

'

70

'

'

'

'

'

'

'

'

Unproved leasehold property impairment, amortization and expiration

$21

$15

'

'

$68

$43

'

'

'

$15

$41

'

'

[1]

(b) Proceeds in 2014 primarily relate to the sale of a portion of our working interests in the Piceance Basin and are subject to post-closing adjustments.

Asset_Sale_Impairments_and_Exp2

Asset Sale, Impairments and Exploration Expense Additional Information (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairment of costs of acquired unproved reserves	$0	$19	$0	$19
Piceance Basin [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairment of costs of acquired unproved reserves	'	$19	'	'

Inventories_Details

Inventories (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Inventory Disclosure [Abstract]	'	'
Natural gas in underground storage	$14	$13
Crude oil production in transit	3	10
Material, supplies and other	53	48
Inventory, Total	$70	$71

Inventories_and_Properties_and

Inventories and Properties and Equipment Asset Retirement Obligation Rollforward (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'
Beginning Balance	$313
Liabilities incurred	17
Liabilities settled	-1
Liabilities associated with assets sold	-65
Estimate revisions	-78	[1]
Accretion expense	16
Ending Balance	202
Asset Retirement Obligation, Current	$3
[1]	(a)Estimate revisions are primarily associated with decreases in anticipated future plug and abandonment costs.

Inventories_and_Properties_and1

Inventories and Properties and Equipment Properties and Equipment (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014		Sep. 30, 2013
	Well
Property, Plant and Equipment [Line Items]	'	'		'
Payments to Acquire Oil and Gas Property	$150	'		'
Proceeds from sale of assets	'	389	[1]	10	[1]
Percentage of working interest sold	49.00%	49.00%		'
Proved developed wells related to sale	100	'		'
Funding commitment associated with joint development agreement	170	'		'
Future wells associated with joint development agreement	400	'		'
Proved Developed Reserves [Member]	'	'		'
Property, Plant and Equipment [Line Items]	'	'		'
Payments to Acquire Oil and Gas Property	50	'		'
TRDC LLC [Member] | Piceance Basin [Member]	'	'		'
Property, Plant and Equipment [Line Items]	'	'		'
Proceeds from sale of assets	'	$50		'
[1]	(b) Proceeds in 2014 primarily relate to the sale of a portion of our working interests in the Piceance Basin and are subject to post-closing adjustments.

Debt_and_Banking_Arrangements_1

Debt and Banking Arrangements (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	$2,052	$1,919
Debt, Current	5	3
Long-term debt	2,047	1,916
Senior Notes | 5.250% Senior Notes due 2017	'	'
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	400	400
Senior Notes | 6.000% Senior Notes due 2022	'	'
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	1,100	1,100
Senior Notes | 5.250% Senior Notes due 2024	'	'
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	500	0
Credit facility agreement	'	'
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	45	410
Other	'	'
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	1	1
Apco | Credit facility agreement	'	'
Debt Instrument [Line Items]	'	'
Debt and Capital Lease Obligations	$6	$8

Debt_and_Banking_Arrangements_2

Debt and Banking Arrangements (Parenthetical) (Details) (Senior Notes [Member])	Sep. 30, 2014	Dec. 31, 2013
Senior Notes Due Twenty Seventeen [Member]	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	5.25%	5.25%
Senior Notes Due Twenty Twenty Two [Member]	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	6.00%	6.00%
Senior Notes Due Twenty Twenty Four [Member]	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	5.25%	5.25%

Debt_and_Banking_Arrangements_3

Debt and Banking Arrangements Narrative (Details) (USD $)

9 Months Ended

9 Months Ended

9 Months Ended

Sep. 30, 2014

Dec. 31, 2013

Nov. 04, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Nov. 04, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Contract

Subsequent Event

MaturityYear2016 [Member]

MaturityYear2016 [Member]

Senior Notes [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Change Of Control [Member]

Prior to December 31, 2015 [Member]

After December 31, 2015 [Member]

Five-year senior unsecured revolving credit facility agreement

Unsecured Revolving Credit Facility [Member]

Subsequent Event

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

$500,000,000

'

'

'

'

'

'

'

'

'

'

'

Limit On Consolidated Indebtedness to Consolidated EBITDAX

3.75

'

'

'

'

'

'

'

'

'

'

'

Net Proceeds From Debt Offering

'

'

'

'

'

494,000,000

'

'

'

'

'

'

Credit facility agreement

'

'

'

1,500,000,000

'

'

'

'

'

'

'

'

Debt instrument maturity length

'

'

'

'

'5 years

'

'

'

'

'

'

'

Increase in the commitments

'

'

'

300,000,000

'

'

'

'

'

'

'

'

Interest rate at end of period

'

'

'

4.13%

'

'

'

'

'

'

'

'

Outstanding amount

'

'

'

45,000,000

'

'

'

'

'

'

'

'

Letters Of Credit Sublimit

750,000,000

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Lines of Credit

2,052,000,000

1,919,000,000

'

'

'

'

45,000,000

410,000,000

210,000,000

'

'

'

Reduction Attributable to Cash Maximum

50,000,000

'

'

'

'

'

'

'

'

'

'

'

Limit On Consolidated Indebtedness

'

'

'

'

'

'

'

'

'

'

1.25

1.5

Number of letter of credit agreements

3

'

'

'

'

'

'

'

'

'

'

'

Letters of credit issued

324,000,000

'

'

'

'

'

'

'

'

'

'

'

Debt Redemption Price As Percentage Of Principal

100.00%

'

'

'

'

'

'

'

'

'

'

'

Percentage Of Repurchase Of Notes On Principal Amount Of Notes

'

'

'

'

'

'

'

'

'

101.00%

'

'

Line of Credit Facility, Capacity Available for Trade Purchases

'

'

$1,300,000,000

'

'

'

'

'

'

'

'

'

Provision_Benefit_for_Income_T2

Provision (Benefit) for Income Taxes from Continuing Operations (Detail) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Current:	'	'	'	'
Federal	($5)	($31)	$12	($28)
State	-3	0	1	0
Foreign	4	3	8	11
Total current	-4	-28	21	-17
Deferred:	'	'	'	'
Federal	29	-27	-59	-84
State	3	12	6	8
Foreign	0	14	1	14
Deferred Income Tax Expense (Benefit)	32	-1	-52	-62
Total provision (benefit)	$28	($29)	($31)	($79)

Provision_Benefit_for_Income_T3

Provision (Benefit) for Income Taxes Additional Information (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'	'
Deferred Tax Expense Related To New York Tax Reform Legislation	'	$9
DeferredForeignIncomeTaxExpenseBenefit-Argentina	14	'
US Deferred Income Tax Expense Benefit related to foreign operation	$4	'

Contingent_Liabilities_Additio

Contingent Liabilities - Additional Information (Detail) (USD $)	1 Months Ended	84 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2006	Sep. 30, 2014	Dec. 31, 2013
	Claim
Commitments and Contingencies Disclosure [Abstract]	'	'	'
Number of claims reserved for court resolution	2	'	'
Loss Contingency, Damages Sought, Value	$20	'	'
Processing, treating and transportation costs used in the calculation of federal royalties	'	113	'
Loss contingencies associated with royalty litigation	'	$20	$16

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	$129		$57
Derivative Liability, Fair Value, Gross Liability	87		122
Level 1 | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	18		30
Derivative Liability, Fair Value, Gross Liability	61		83
Long-term debt	0	[1]	0	[1]
Level 2 | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	110		26
Derivative Liability, Fair Value, Gross Liability	26		38
Long-term debt	2,081	[1]	1,945	[1]
Level 3 | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	1		1
Derivative Liability, Fair Value, Gross Liability	0		1
Long-term debt	0	[1]	0	[1]
Total | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	129		57
Derivative Liability, Fair Value, Gross Liability	87		122
Long-term debt	$2,081	[1]	$1,945	[1]
[1]	The carrying value of total debt, excluding capital leases, was $2,051 million and $1,918 million as of September 30, 2014 and December 31, 2013, respectively.

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets And Liabilities Classified In Level 3 [Line Items]	'	'
Long-term debt	$2,051	$1,918
Percentage of net fair value of derivatives portfolio expiring	100.00%	'
Derivative Portfolio Expiration Period	'2015	'
Level 3	'	'
Assets And Liabilities Classified In Level 3 [Line Items]	'	'
Derivative, Fair Value, Net	$1	'

Derivatives_and_Concentration_2

Derivatives and Concentration of Credit Risk (Details) (Short Position)	9 Months Ended
	Sep. 30, 2014
2016 [Member] | Derivatives related to production | Crude Oil | Swaptions | WTI	'
Derivative [Line Items]	'
Notional Volume	5,250	[1]
Underlying, Derivative	97.55	[2]
2016 [Member] | Derivatives related to production | Natural Gas Commodity Contract Thirteen [Member] | Swaptions | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	90,000	[1]
Underlying, Derivative	4.23	[2]
2016 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Nine [Member] | Index | Multiple	'
Derivative [Line Items]	'
Notional Volume	70,000	[3]
Underlying, Derivative	0	[4]
2017 and beyond [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Ten [Member] | Index | Multiple	'
Derivative [Line Items]	'
Notional Volume	478,000	[3]
Underlying, Derivative	0	[4]
2014 [Member] | Derivatives related to production | Crude Oil | Fixed Price Swaps | WTI	'
Derivative [Line Items]	'
Notional Volume	14,975	[1]
Underlying, Derivative	96.01	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Two | Swaptions | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	50,000	[1]
Underlying, Derivative	4.24	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar [Member] | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	190,000	[1]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar [Member] | Henry Hub | Minimum [Member]	'
Derivative [Line Items]	'
Underlying, Derivative	4.04
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar [Member] | Henry Hub | Maximum [Member]	'
Derivative [Line Items]	'
Underlying, Derivative	4.66
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Four | Basis Swap [Member] | Dominion [Member]	'
Derivative [Line Items]	'
Notional Volume	39,000	[1]
Underlying, Derivative	-0.73	[2]
2014 [Member] | Derivatives related to production | Propane [Member] | Fixed Price Swaps | Mont Belvieu	'
Derivative [Line Items]	'
Notional Volume	489	[1]
Underlying, Derivative	1.17	[2]
2014 [Member] | Derivatives related to production | Isobutane [Member] | Fixed Price Swaps | Mont Belvieu	'
Derivative [Line Items]	'
Notional Volume	652	[1]
Underlying, Derivative	1.37	[2]
2014 [Member] | Derivatives related to production | Butane [Member] | Fixed Price Swaps | Mont Belvieu	'
Derivative [Line Items]	'
Notional Volume	652	[1]
Underlying, Derivative	1.34	[2]
2014 [Member] | Derivatives related to production | Natural Gasoline | Fixed Price Swaps | Mont Belvieu	'
Derivative [Line Items]	'
Notional Volume	1,630	[1]
Underlying, Derivative	2.06	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Five | Basis Swap [Member] | NGPL [Member]	'
Derivative [Line Items]	'
Notional Volume	30,000	[1]
Underlying, Derivative	-0.19	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Six | Basis Swap [Member] | Rockies	'
Derivative [Line Items]	'
Notional Volume	143,000	[1]
Underlying, Derivative	-0.15	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Seven [Member] | Basis Swap [Member] | San Juan [Member]	'
Derivative [Line Items]	'
Notional Volume	255,000	[1]
Underlying, Derivative	-0.15	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract Seven [Member] | Basis Swap [Member] | Southern California [Member]	'
Derivative [Line Items]	'
Notional Volume	73,000	[1]
Underlying, Derivative	0.13	[2]
2014 [Member] | Derivatives related to production | Natural Gas Liquids Ethane [Member] | Fixed Price Swaps | Mont Belvieu	'
Derivative [Line Items]	'
Notional Volume	3,261	[1]
Underlying, Derivative	0.29	[2]
2014 [Member] | Derivatives related to production | Natural Gas Commodity Contract One [Member] | Fixed Price Swaps | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	315,000	[1]
Underlying, Derivative	4.19	[2]
2014 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Two | Fixed Price Swaps | Multiple	'
Derivative [Line Items]	'
Notional Volume	8,000	[3]
Underlying, Derivative	0	[4]
2014 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Two | Basis Swap [Member] | Multiple	'
Derivative [Line Items]	'
Notional Volume	31,000	[3]
Underlying, Derivative	0	[4]
2014 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Three | Index | Multiple	'
Derivative [Line Items]	'
Notional Volume	145,000	[3]
Underlying, Derivative	0	[4]
2015 [Member] | Derivatives related to production | Crude Oil | Swaptions | WTI	'
Derivative [Line Items]	'
Notional Volume	8,382	[1]
Underlying, Derivative	94.9	[2]
2015 [Member] | Derivatives related to production | Crude Oil Commodity Contract One [Member] | Fixed Price Swaps | WTI	'
Derivative [Line Items]	'
Notional Volume	20,236	[1]
Underlying, Derivative	94.88	[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Eight [Member] | Fixed Price Swaps | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	272,000	[1]
Underlying, Derivative	4.31	[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Ten [Member] | Costless Collar [Member] | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	50,000	[1]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Ten [Member] | Costless Collar [Member] | Henry Hub | Minimum [Member]	'
Derivative [Line Items]	'
Underlying, Derivative	4
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Ten [Member] | Costless Collar [Member] | Henry Hub | Maximum [Member]	'
Derivative [Line Items]	'
Underlying, Derivative	4.5
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Eleven [Member] | Basis Swap [Member] | NGPL [Member]	'
Derivative [Line Items]	'
Notional Volume	13,000	[1]
Underlying, Derivative	-0.16	[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Twelve [Member] [Member] | Basis Swap [Member] | Rockies	'
Derivative [Line Items]	'
Notional Volume	150,000	[1]
Underlying, Derivative	-0.11	[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Thirteen [Member] | Basis Swap [Member] | San Juan [Member]	'
Derivative [Line Items]	'
Notional Volume	85,000	[1]
Underlying, Derivative	-0.1	[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Thirteen [Member] | Basis Swap [Member] | Southern California [Member]	'
Derivative [Line Items]	'
Notional Volume	20,000	[1]
Underlying, Derivative	0.18	[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Nine [Member] | Swaptions | Henry Hub	'
Derivative [Line Items]	'
Notional Volume	50,000	[1]
Underlying, Derivative	4.38	[2]
2015 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Two | Fixed Price Swaps | Multiple	'
Derivative [Line Items]	'
Notional Volume	11,000	[3]
Underlying, Derivative	0	[4]
2015 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Five | Basis Swap [Member] | Multiple	'
Derivative [Line Items]	'
Notional Volume	12,000	[3]
Underlying, Derivative	0	[4]
2015 [Member] | Derivatives related to storage and transportation | Natural Gas Commodity Contract Six | Index | Multiple	'
Derivative [Line Items]	'
Notional Volume	118,000	[3]
Underlying, Derivative	0	[4]
[1]	(b)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.
[2]	(c)The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon.
[3]	(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.
[4]	(d)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.

Derivatives_and_Concentration_3

Derivatives and Concentration of Credit Risk (Details 1) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013
		Not Designated as Hedging Instrument	Not Designated as Hedging Instrument	Legacy natural gas contracts from former power business	Legacy natural gas contracts from former power business	Derivatives related to production	Derivatives related to production
				Not Designated as Hedging Instrument	Not Designated as Hedging Instrument	Not Designated as Hedging Instrument	Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]	'	'	'	'	'	'	'
Document Period End Date	30-Sep-14	'	'	'	'	'	'
Total derivatives, Assets	'	$129	$57	$19	$31	$110	$26
Total derivatives, Liabilities	'	$87	$122	$61	$83	$26	$39

Derivatives_and_Concentration_4

Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk (Details 2) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Net gain (loss) on derivatives not designated as hedges (Note 10)	$148		($15)		($64)		($31)
Energy Related Derivative [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Payment Made for Settlement of Derivatives	'		'		57		14
Payment Received for Settlement of Derivatives	10		1		'		'
Net gain (loss) on derivatives not designated as hedges (Note 10)	150	[1]	-18	[1]	40	[1]	-29	[1]
Derivatives Related to Physical Marketing Agreements [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Payment Made for Settlement of Derivatives	'		2		114		'
Payment Received for Settlement of Derivatives	5		'		'		1
Net gain (loss) on derivatives not designated as hedges (Note 10)	($2)	[2]	$3	[2]	($104)	[2]	($2)	[2]
[1]	Includes receipts totaling $10 million and $1 million for settlements of derivatives during the three months ended September 30, 2014 and 2013, respectively; and payments totaling $57 million and $14 million for the nine months ended September 30, 2014 and 2013, respectively.
[2]	Includes receipts totaling $5 million for settlements of derivatives during the three months ended September 30, 2014 and payments totaling $2 million during the three months ended September 30, 2013; and payments totaling $114 million for the nine months ended September 30, 2014 and receipts of $1 million for the

Derivatives_and_Concentration_5

Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk (Details 3) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Gross And Net Derivative Assets and Liabilities [Line Items]	'		'
Document Period End Date	30-Sep-14		'
Derivative Asset, Fair Value, Gross Asset	$129		$57
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	43		52
Derivative Liability, Fair Value, Gross Liability	-87		-122
Derivative, Collateral, Obligation to Return Cash	0		0
Derivative Assets	86		7
Derivative Liabilities	-1		-20
Counterparty Netting Under Agreements Governing Derivatives	'		'
Gross And Net Derivative Assets and Liabilities [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	43	[1]	50	[1]
Derivative Liability, Fair Value, Gross Liability	($43)	[1]	($50)	[1]
[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_6

Derivatives and Concentration of Credit Risk (Details 4) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	$129
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net	86
Credit reserves	0
Credit Reserves Maximum Potential Future Exposure On Credit Risk Derivatives Net	0
Gross credit exposure from derivatives, Gross Total	129
Maximum Potential Future Exposure On Credit Risk Derivatives Net	86
Financial institutions	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	128
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net	85
Utilities [Member]	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	1
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net	1
Investment Grade	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	128	[1]
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net	85	[1]
Investment Grade | Financial institutions	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	128	[1]
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net	85	[1]
Investment Grade | Utilities [Member]	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	0	[1]
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net	$0	[1]
[1]	We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Derivatives_and_Concentration_7

Derivatives and Concentration of Credit Risk - Additional Information (Detail) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Derivative [Line Items]	'	'
Collateral Already Posted, Aggregate Fair Value	$51,000,000	'
NumberOfLargestNetCounterPartyPositionsInvestmentGrade	9	'
Occurrence Of Future Net Cash Flows For Derivatives	'12 months	'
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	'	5,000,000
Net derivative liability position	44,000,000	'
Additional collateral posted	1,000,000	'
Percentage of net credit exposure from derivatives	94.00%	'
Gains or losses recognized in income from assessment of hedge	0	'
Collateral Already Posted, Maintenance Margin, Aggregate Fair Value	43,000,000	'
Collateral Already Posted, Initial Margin, Aggregate Fair Value	8,000,000	'
Cash Flow Hedging [Member] | Revenues [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	'	5,000,000
Maximum [Member]	'	'
Derivative [Line Items]	'	'
Reduction in derivative liabilties	$1,000,000	'

Segment_Disclosures_Details

Segment Disclosures (Details) (USD $)	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Jun. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]	'	'	'	'	'	'
Total revenues	$794,000,000	$616,000,000	'	$2,485,000,000	$1,968,000,000	'
Costs and expenses:	'	'	'	'	'	'
Lease and facility operating	73,000,000	70,000,000	'	208,000,000	196,000,000	'
Gathering, processing and transportation	82,000,000	88,000,000	'	250,000,000	264,000,000	'
Taxes other than income	40,000,000	33,000,000	'	121,000,000	95,000,000	'
Gas management, including charges for unutilized pipeline capacity	164,000,000	201,000,000	'	788,000,000	666,000,000	'
Exploration (Note 4)	29,000,000	21,000,000	'	101,000,000	59,000,000	'
Depreciation, depletion and amortization	213,000,000	230,000,000	'	627,000,000	662,000,000	'
Impairment of costs of acquired unproved reserves	0	19,000,000	'	0	19,000,000	'
Loss on sale of working interests in the Piceance Basin	1,000,000	0	195,000,000	196,000,000	0	'
General and administrative	75,000,000	67,000,000	'	219,000,000	209,000,000	'
Other—net	3,000,000	1,000,000	'	9,000,000	10,000,000	'
Total costs and expenses	680,000,000	730,000,000	'	2,519,000,000	2,180,000,000	'
Operating income (loss)	114,000,000	-114,000,000	'	-34,000,000	-212,000,000	'
Interest expense	-31,000,000	-28,000,000	'	-88,000,000	-82,000,000	'
Interest capitalized	1,000,000	1,000,000	'	1,000,000	1,000,000	'
Investment income and other	5,000,000	4,000,000	'	12,000,000	17,000,000	'
Income (loss) from continuing operations before income taxes	89,000,000	-137,000,000	'	-109,000,000	-276,000,000	'
Total assets	'	'	'	'	'	'
Total assets	8,244,000,000	'	'	8,244,000,000	'	8,429,000,000
Domestic	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'
Total revenues	747,000,000	581,000,000	'	2,368,000,000	1,855,000,000	'
Costs and expenses:	'	'	'	'	'	'
Lease and facility operating	63,000,000	62,000,000	'	182,000,000	170,000,000	'
Gathering, processing and transportation	82,000,000	88,000,000	'	249,000,000	262,000,000	'
Taxes other than income	32,000,000	27,000,000	'	100,000,000	77,000,000	'
Gas management, including charges for unutilized pipeline capacity	164,000,000	201,000,000	'	788,000,000	666,000,000	'
Exploration (Note 4)	28,000,000	21,000,000	'	97,000,000	55,000,000	'
Depreciation, depletion and amortization	201,000,000	222,000,000	'	596,000,000	637,000,000	'
Impairment of costs of acquired unproved reserves	'	19,000,000	'	'	19,000,000	'
Loss on sale of working interests in the Piceance Basin	1,000,000	'	'	196,000,000	'	'
General and administrative	71,000,000	64,000,000	'	208,000,000	198,000,000	'
Other—net	3,000,000	-2,000,000	'	6,000,000	10,000,000	'
Total costs and expenses	645,000,000	702,000,000	'	2,422,000,000	2,094,000,000	'
Operating income (loss)	102,000,000	-121,000,000	'	-54,000,000	-239,000,000	'
Interest expense	-31,000,000	-28,000,000	'	-88,000,000	-82,000,000	'
Interest capitalized	1,000,000	1,000,000	'	1,000,000	1,000,000	'
Investment income and other	-1,000,000	0	'	-1,000,000	1,000,000	'
Income (loss) from continuing operations before income taxes	71,000,000	-148,000,000	'	-142,000,000	-319,000,000	'
Total assets	'	'	'	'	'	'
Total assets	7,838,000,000	'	'	7,838,000,000	'	8,046,000,000
International	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'
Total revenues	47,000,000	35,000,000	'	117,000,000	113,000,000	'
Costs and expenses:	'	'	'	'	'	'
Lease and facility operating	10,000,000	8,000,000	'	26,000,000	26,000,000	'
Gathering, processing and transportation	0	0	'	1,000,000	2,000,000	'
Taxes other than income	8,000,000	6,000,000	'	21,000,000	18,000,000	'
Gas management, including charges for unutilized pipeline capacity	0	0	'	0	0	'
Exploration (Note 4)	1,000,000	0	'	4,000,000	4,000,000	'
Depreciation, depletion and amortization	12,000,000	8,000,000	'	31,000,000	25,000,000	'
Impairment of costs of acquired unproved reserves	'	0	'	'	0	'
Loss on sale of working interests in the Piceance Basin	0	'	'	0	'	'
General and administrative	4,000,000	3,000,000	'	11,000,000	11,000,000	'
Other—net	0	3,000,000	'	3,000,000	0	'
Total costs and expenses	35,000,000	28,000,000	'	97,000,000	86,000,000	'
Operating income (loss)	12,000,000	7,000,000	'	20,000,000	27,000,000	'
Interest expense	0	0	'	0	0	'
Interest capitalized	0	0	'	0	0	'
Investment income and other	6,000,000	4,000,000	'	13,000,000	16,000,000	'
Income (loss) from continuing operations before income taxes	18,000,000	11,000,000	'	33,000,000	43,000,000	'
Total assets	'	'	'	'	'	'
Total assets	406,000,000	'	'	406,000,000	'	383,000,000
Intersegment Eliminations [Member]	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'
Total revenues	$0	'	'	'	'	'

Subsequent_Events_Details

Subsequent Events (Details) (Subsequent Event [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Subsequent Event [Line Items]	'
Equity Method Investment, Ownership Percentage	69.00%
Noncontrolling Equity Interest Ownership Percentage	5.00%
International	'
Subsequent Event [Line Items]	'
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	294