WPX Energy (WPX) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 26, 2014	Jun. 30, 2013
Document Documentand Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'WPX	'	'
Entity Registrant Name	'WPX ENERGY, INC.	'	'
Entity Central Index Key	'0001518832	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	201,737,171	'
Entity Public Float	'	'	$3,775,544,298

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$99	$153
Accounts receivable, net of allowance of $7 and $11 as of December 31, 2013 and 2012, respectively	536	443
Deferred income taxes	49	17
Derivative assets	50	58
Inventories	72	66
Margin deposits	71	0
Other	45	35
Total current assets	922	772
Investments	145	145
Properties and equipment, net (successful efforts method of accounting)	7,241	8,416
Derivative assets	7	2
Other noncurrent assets	114	121
Total assets	8,429	9,456
Current liabilities:	'	'
Accounts payable	652	509
Accrued and other current liabilities	190	201
Customer margin deposits payable	55	2
Derivative liabilities	110	14
Total current liabilities	1,007	726
Deferred income taxes	788	1,401
Long-term debt	1,916	1,508	[1]
Derivative liabilities	12	1
Asset retirement obligations	358	316
Other noncurrent liabilities	138	133
Contingent liabilities and commitments (Note 11)	'	'
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; 201 million shares issued at December 31, 2013 and 199.3 million shares issued at December 31, 2012)	2	2
Additional paid-in-capital	5,516	5,487
Accumulated deficit	-1,408	-223
Accumulated other comprehensive income (loss)	-1	2
Total stockholders’ equity	4,109	5,268
Noncontrolling interests in consolidated subsidiaries	101	103
Total equity	4,210	5,371
Total liabilities and equity	$8,429	$9,456
[1]	Interest paid on debt totaled $91 million and $58 million for 2013 and 2012, respectively.

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Allowance for doubtful accounts	$7	$11
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued	201,000,000	199,300,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Product revenues:	'		'		'
Natural gas sales	$1,093		$1,364		$1,694
Oil and condensate sales	649		491		312
Natural gas liquid sales	230		299		408
Total product revenues	1,972		2,154		2,414
Gas management	891		949		1,428
Net gain (loss) on derivatives not designated as hedges (Note 16)	-124		78		29
Other	22		8		11
Total revenues	2,761		3,189		3,882
Costs and expenses:	'		'		'
Lease and facility operating	308		283		262
Gathering, processing and transportation	433		506		487
Taxes other than income	141		111		134
Gas management, including charges for unutilized pipeline capacity	931		996		1,471
Exploration (Note 6)	431		83		126
Depreciation, depletion and amortization	940		966		902
Impairment of producing properties and costs of acquired unproved reserves (Note 6)	1,055	[1],[2]	225	[1],[3]	367	[1],[4]
Gain on sale of Powder River Basin deep rights leasehold	-36		0		0
General and administrative	289		287		275
Other—net	17		12		0
Total costs and expenses	4,509		3,469		4,024
Operating income (loss)	-1,748		-280		-142
Interest expense	-108		-102		-117
Interest capitalized	5		8		9
Investment income, impairment of equity method investment and other	5		30		26
Income (loss) from continuing operations before income taxes	-1,846		-344		-224
Provision (benefit) for income taxes	-655		-111		-74
Income (loss) from continuing operations	-1,191		-233		-150
Income (loss) from discontinued operations	0		22		-142
Net income (loss)	-1,191		-211		-292
Less: Net income (loss) attributable to noncontrolling interests	-6		12		10
Net income (loss) attributable to WPX Energy, Inc.	($1,185)		($223)		($302)
Basic and diluted earnings (loss) per common share (Note 5):	'		'		'
Income (loss) from continuing operations (in dollars per share)	($5.91)		($1.23)		($0.81)
Income (loss) from discontinued operations (in dollars per share)	$0		$0.11		($0.72)
Net income (loss) (in dollars per share)	($5.91)		($1.12)		($1.53)
Weighted-average shares	200.5		198.8		197.1
[1]	Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
[2]	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
[3]	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
[4]	As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Statement of Partners' Capital [Abstract]	'		'		'
Net income (loss) attributable to WPX Energy, Inc.	($1,185)		($223)		($302)
Other comprehensive income (loss):	'		'		'
Change in fair value of cash flow hedges, net of tax	0	[1]	57	[1]	262	[1]
Net reclassifications into earnings of net cash flow hedge gains, net of tax	-3	[2]	-274	[2]	-211	[2]
Other comprehensive income (loss), net of tax	-3		-217		51
Comprehensive income (loss) attributable to WPX Energy, Inc.	($1,188)		($440)		($251)
[1]	Change in fair value of cash flow hedges is net of income tax of $33 million and $151 million for 2012 and 2011, respectively. 2012 includes a $15 million before tax unrealized gain that was recognized in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations, as the underlying transaction was no longer probable of occurring (see Note 16).
[2]	Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million, $159 million and $120 million of income tax for 2013, 2012 and 2011, respectively. Before tax amounts realized and reclassified to product revenues, primarily natural gas sales revenues, on the Consolidated Statements of Operations were $5 million, $434 million and $331 million for 2013, 2012 and 2011, respectively.

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Partners' Capital [Abstract]	'	'	'
Income tax for net cash flow hedges	'	$33	$151
Unrealized gains recognized for hedge transactions	'	15	'
Income tax provision for cash flow hedge gains	2	159	120
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$5	$434	$331

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)	Total	Total Stockholders’ Equity	Common Stock	Capital in Excess of Par Value	Accumulated Deficit	Williams’ Net Investment	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
In Millions, unless otherwise specified
Balance at beginning of period at Dec. 31, 2010	$4,484	$4,412	$0	$0	'	$4,244	$168	$72	[1]
Comprehensive income:	'	'	'	'	'	'	'	'
Net income (loss)	-292	-302	'	'	'	-302	'	10	[1]
Other comprehensive income (loss)	51	51	'	'	'	'	51	'
Comprehensive income (loss)	-241	'	'	'	'	'	'	'
Contribution of Notes Payable to Williams (Note 3)	2,420	2,420	'	'	'	2,420	'	'
Allocation of alternative minimum tax credit (Note 10)	98	98	'	'	'	98	'	'
Net transfers with Williams	-25	-25	'	'	'	-25	'	'
Distribution to Williams a portion of note proceeds	-981	-981	'	'	'	-981	'	'
Recapitalization upon contribution by Williams	0	'	2	5,452	'	-5,454	'	'
Dividends to noncontrolling interests	-1	'	'	'	'	'	'	-1	[1]
Stock based compensation, net of tax benefit	5	5	'	5	'	'	'	'
Balance at end of period at Dec. 31, 2011	5,759	5,678	2	5,457	0	0	219	81	[1]
Comprehensive income:	'	'	'	'	'	'	'	'
Net income (loss)	-211	-223	'	'	-223	'	'	12	[1]
Other comprehensive income (loss)	-217	-217	'	'	'	'	-217	'
Comprehensive income (loss)	-428	'	'	'	'	'	'	'
Contribution from noncontrolling interest	10	'	'	'	'	'	'	10	[1]
Stock based compensation, net of tax benefit	30	30	'	30	'	'	'	'
Balance at end of period at Dec. 31, 2012	5,371	5,268	2	5,487	-223	'	2	103	[1]
Comprehensive income:	'	'	'	'	'	'	'	'
Net income (loss)	-1,191	-1,185	'	'	-1,185	'	'	-6	[1]
Other comprehensive income (loss)	-3	-3	'	'	'	'	-3	'
Comprehensive income (loss)	-1,194	'	'	'	'	'	'	'
Contribution from noncontrolling interest	4	'	'	'	'	'	'	4	[1]
Stock based compensation, net of tax benefit	29	29	'	29	'	'	'	'
Balance at end of period at Dec. 31, 2013	$4,210	$4,109	$2	$5,516	($1,408)	'	($1)	$101	[1]
[1]	Primarily represents the 31 percent of Apco Oil and Gas International Inc. owned by others.

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Equity (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Noncontrolling interest, ownership percentage by noncontrolling owners	31.00%	31.00%	31.00%

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating Activities	'		'		'
Net income (loss)	($1,191)		($211)		($292)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'		'		'
Depreciation, depletion and amortization	940		973		951
Deferred income tax provision (benefit)	-645		-160		-176
Provision for impairment of properties and equipment (including certain exploration expenses) and investments	1,483		288		694
Amortization of stock-based awards	32		28		5
Gain on sales of assets	41	[1]	42	[1]	1
Cash provided (used) by operating assets and liabilities:	'		'		'
Accounts receivable	-43		68		-100
Inventories	-5		7		3
Margin deposits and customer margin deposit payable	-18		-5		-18
Other current assets	-7		7		-11
Accounts payable	41		-128		131
Accrued and other current liabilities	-21		12		10
Changes in current and noncurrent derivative assets and liabilities	106		-32		8
Other, including changes in other noncurrent assets and liabilities	5		-9		3
Net cash provided by operating activities	636		796		1,207
Investing Activities	'		'		'
Capital expenditures	-1,154	[2]	-1,521	[2]	-1,572	[2]
Proceeds from sales of assets	49		310		15
Purchases of investments	-3		-2		-12
Other	-3		9		13
Net cash used in investing activities	-1,111		-1,204		-1,556
Financing Activities	'		'		'
Proceeds from common stock	6		3		0
Proceeds from long-term debt	0		6		1,502
Borrowings on credit facility	970		50		0
Payments on credit facility	-560		-50		0
Contribution from noncontrolling interest	4		10		0
Excess tax benefit of stock based awards	0		13		0
Payments for debt issuance costs	0		0		-30
Net increase in notes payable to Williams	0		0		159
Net changes in Williams’ net investment	0		0		-777
Other	6		5		-15
Net cash provided by financing activities	426		37		839
Net increase (decrease) in cash and cash equivalents	-49		-371		490
Effect of Exchange Rate on Cash and Cash Equivalents	-5		-2		-1
Cash and cash equivalents at beginning of period	153		526		37
Cash and cash equivalents at end of period	$99		$153		$526
[1]	2013 includes a $36 million gain on sale of Powder River Basin deep rights leasehold (Note 6) and 2012 includes the gain on the sale of Barnett Shale and Arkoma Basin (Note 2)
[2]	Increase to properties and equipment$(1,207) $(1,449) $(1,641)Changes in related accounts payable53 (72) 69Capital expenditures$(1,154) $(1,521) $(1,572)

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Statement of Cash Flows [Abstract]	'		'		'
Gain on sale of Powder River Basin deep rights leasehold	$36		$0		$0
Increase to properties and equipment	-1,207		-1,449		-1,641
Changes in related accounts payable and accounts receivable	53		-72		69
Capital expenditures	($1,154)	[1]	($1,521)	[1]	($1,572)	[1]
[1]	Increase to properties and equipment$(1,207) $(1,449) $(1,641)Changes in related accounts payable53 (72) 69Capital expenditures$(1,154) $(1,521) $(1,572)

Description_of_Business_Basis_

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	'
	Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
	Description of Business
	Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments. WPX Energy, Inc. was formed in 2011 by The Williams Companies, Inc. (“Williams”) to effect the separation of its exploration and production business. Williams contributed to the Company its investment in certain subsidiaries related to Williams’ domestic and international exploration and production businesses, collectively referred to as the “Contribution”. The separation was completed on December 31, 2011 through a pro rata distribution of WPX common stock to Williams’ stockholders.
	Domestic includes natural gas, oil and NGL development, production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania and Wyoming in the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, Williston, San Juan, Powder River, Appalachian and Green River Basins. 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.
	The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we”, “us” or “our”.
	Basis of Presentation
	These financial statements are prepared on a consolidated basis. Prior to the Contribution, the financial statements were derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the Contribution to WPX. Management believes the assumptions underlying the financial statements are reasonable. The financial statements of 2011 included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during 2011. Because a direct ownership relationship did not exist prior to the Contribution among the various entities that comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, has been shown as Williams’ net investment within stockholder’s equity in the consolidated financial statements. In connection with the Contribution, we have reflected the amounts previously presented as Williams’ net investment in excess of the par value of our common stock as additional paid-in capital. Transactions in 2011 with Williams’ other operating businesses, which generally settled monthly, are shown as changes in accounts receivable or accounts payable in the Consolidated Statements of Cash Flows for the year ended December 31, 2011. Other transactions during the period prior to separation between the Company and Williams which were not part of the notes payable to Williams have been identified in the Consolidated Statements of Equity as net transfers with Williams (see Note 3).
	Discontinued operations
	During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. We have reported the results of operations and financial position of the Barnett Shale and Arkoma Basin operations as discontinued operations for all periods presented.
	Additionally, see Note 11 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
	Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
	Summary of Significant Accounting Policies
	Principles of consolidation
	The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
	Significant estimates and assumptions which impact these financials include:
	•	Impairment assessments of long-lived assets;
	•	Valuations of derivatives;
	•	Estimation of natural gas and oil reserves;
	•	Assessments of litigation-related contingencies; and
	•	Asset retirement obligations.
	These estimates are discussed further throughout these notes.
	Cash and cash equivalents
	Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
	Restricted cash
	Restricted cash of our domestic operations consists of approximately $21 million and $19 million at December 31, 2013 and 2012, respectively, primarily related to escrow accounts established as part of the settlement agreement with certain California utilities and is included in other current and noncurrent assets. Included in the separation and distribution agreement with Williams are indemnifications requiring us to pay to Williams any net asset (or receive any net liability) that result upon ultimate resolution of these matters (see Note 11). Additionally, restricted cash of our international segment consists of approximately $6 million and $9 million at December 31, 2013 and 2012, respectively, associated with various letters of credit that is also classified in other current and other noncurrent assets.
	Accounts receivable
	Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
	Inventories
	All inventories are stated at the lower of cost or market. Our inventories consist of tubular goods and production equipment for future transfer to wells of $49 million and $42 million at December 3l, 2013 and 2012, respectively. Additionally, we have natural gas in storage related to our gas management activities of $13 million and $24 million at December 31, 2013 and 2012, respectively, and crude oil production in transit of $10 million at December 31, 2013. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recognized lower of cost or market writedowns on natural gas in storage of $1 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
	Properties and equipment
	Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
	Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
	Other capitalized costs
	Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
	Depreciation, depletion and amortization
	Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis for our domestic properties or on a concession basis for our international properties. International concession reserve estimates are limited to production quantities estimated through the life of the concession. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
	Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
	Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net.
	Impairment of long-lived assets
	We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
	Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows.
	Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
	Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
	Contingent liabilities
	Owing to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
	Asset retirement obligations
	We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
	Cash flows from revolving credit facilities
	Proceeds and payments related to any borrowings under our credit facilities are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
	Derivative instruments and hedging activities
	We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
	We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
	The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
		Derivative Treatment	Accounting Method
		Normal purchases and normal sales exception	Accrual accounting
		Designated in a qualifying hedging relationship	Hedge accounting
		All other derivatives	Mark-to-market accounting
	We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
	For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
	For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
•	Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;
•	The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
•	Realized gains and losses on all derivatives that settle financially;
•	Realized gains and losses on derivatives held for trading purposes; and
•	Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2013 and 2012 was insignificant. Additionally, natural gas revenues include $5 million, $423 million and $326 million in 2013, 2012 and 2011, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities through May 2012 included purchases and subsequent sales to Williams Partners for fuel and shrink gas (see Note 3). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
Charges for unutilized transportation capacity included in gas management expenses were $61 million, $46 million and $35 million in 2013, 2012 and 2011, respectively.
Capitalization of interest
We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used until June 30, 2011 was the rate charged to us by Williams through June 30, 2011, at which time our intercompany note with Williams was forgiven (see Note 3). We did not capitalize interest for the period from July 1, 2011 to mid November 2011. Beginning November 2011, we began using the weighted average rate of our long-term notes payable which were issued in November 2011 (see Note 9).
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. Through the effective date of the spin-off, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provisions for 2011 were calculated on a separate return basis for us and our subsidiaries, except for certain adjustments. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.
Employee stock-based compensation
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Through the date of the spin-off, certain employees providing direct service to us participated in Williams’ common-stock-based awards plans. The plans provided for Williams’ common-stock-based awards to both employees and Williams’ non-management directors. The plans permitted the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards were granted for no consideration other than prior and future services or based on certain financial performance targets.
Through the date of the spin-off, Williams charged us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation was also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.
In preparation for the spin-off, Williams’ Compensation Committee determined that all outstanding Williams’ equity-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (“Pre-2006 Options”) would convert into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options were converted into options covering both Williams and WPX common stock. The number of shares underlying each award and, with respect to options, the per share exercise price of each such award has been adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of such awards.
Foreign exchange
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 5).

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	Discontinued Operations
	During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.
	Summarized Results of Discontinued Operations
			2012			2011
		(Millions)
	Revenues		$	28		$	118
	Income (loss) from discontinued operations before gain on sale, impairments and income taxes		$	(3	)	$	(15	)
	Gain on sale		38			—
	Impairments		—			(209		)
	Less: Provision (benefit) for income taxes		13			(82		)
	Income (loss) from discontinued operations		$	22		$	(142	)
	The impairments in 2011 reflect write-downs to estimates of fair value of our holdings in the Barnett Shale and the Arkoma Basin. Impairment charges on our Fort Worth (Barnett Shale) properties were $180 million in 2011. Impairment charges in Arkoma were $29 million in 2011. These nonrecurring fair value measurements, which fall within Level 3 of the fair value hierarchy, utilized a probability-weighted discounted cash flow analysis that was based on internal cash flow models.

Transactions_with_Williams

Transactions with Williams	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Transactions with Williams	'
	Transactions with Williams
	During the fourth quarter of 2011, the Contribution and recapitalization of the Company was completed, whereby common stock held by Williams converted into approximately 197 million shares of WPX common stock. We also entered into agreements with Williams in connection with our separation. These agreements include:
	•	A Separation and Distribution agreement for, among other things, the separation from Williams and the distribution of WPX common stock, the distribution of a portion of the net proceeds from the debt financing as well as agreements between us and Williams, including those relating to indemnification;
	•	A tax sharing agreement, providing for, among other things, the allocation between Williams and WPX of federal, state, local and foreign tax liabilities for periods prior to the distribution and in some instances for periods after the distribution;
	•	An employee matters agreement discussed below; and
	•	A transition services agreement for one year following separation.
	Personnel and related services
	As previously discussed, our domestic operations were contributed to WPX Energy, Inc. on July 1, 2011. On June 30, 2011, certain entities that were contributed to us on July 1, 2011 withdrew from the Williams’ benefit plans and terminated their personnel services agreements with Williams’ payroll companies.
	Simultaneously, two new administrative service entities owned and controlled by Williams executed new personnel services agreements with the payroll companies and joined the Williams plans as participants. The effect of these transactions is that none of the companies contributed to WPX Energy in June 2011 had any employees. Through December 30, 2011, these service entities employed all personnel that provided services to the Company and remained owned and controlled by Williams.
	In connection with the spin-off, we entered into an Employee Matters Agreement with Williams that set forth our agreements with Williams as to certain employment, compensation and benefits matters. The Employee Matters Agreement provides for the allocation and treatment of assets and liabilities arising out of employee compensation and benefit programs in which our employees participated prior to January 1, 2012. In connection with the spin-off, we provided benefit plans and arrangements in which our employees will participate going forward. Generally, other than with respect to equity compensation (discussed below), from and after January 1, 2012, we sponsored and maintained employee compensation and benefit programs relating to all employees who transferred to us from Williams in connection with the spin-off through the contribution of two newly established service entities that employees of Williams were moved to prior to the spin-off. The Employee Matters Agreement provides that Williams will remain solely responsible for all liabilities under The Williams Companies Pension Plan, The Williams Companies Retirement Restoration Plan and The Williams Companies Investment Plus Plan. No assets and/or liabilities under any of those plans transferred to us or our benefit plans and our employees ceased active participation in those plans as of January 1, 2012.
	All outstanding Williams equity awards (other than stock options granted prior to January 1, 2006) held by our employees as of the spin-off were converted into WPX equity awards, issued pursuant to a plan that we established (see Note 13). In addition, outstanding Williams stock options that were granted prior to January 1, 2006 and held by our employees and Williams’ other employees as of the date of the spin-off were converted into options to acquire both WPX common stock and Williams common stock, in the same proportion as the number of shares of WPX common stock that each holder of Williams common stock received in the spin-off. The conversion maintained the same intrinsic value as the applicable Williams equity award as of the date of the conversion.
	Through the date of the spin-off, Williams charged us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carried the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs was charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Consolidated Statements of Operations.
	In addition, Williams charged us for certain employees of Williams who provided general and administrative services on our behalf (referred to as indirect employees). These charges were either directly identifiable or allocated to our operations. Direct charges included goods and services provided by Williams at our request. Allocated general corporate costs were based on our relative usage of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses was reflected in general and administrative expense in the accompanying Consolidated Statements of Operations. In management’s estimation, the allocation methodologies used were reasonable and resulted in a reasonable allocation to us of our costs of doing business incurred by Williams.
	Other arrangements with Williams or its affiliates
	We also have operating activities with Williams Partners and another Williams subsidiary. Beginning January 1, 2012, Williams and its subsidiaries were no longer related parties, therefore only amounts related to 2011 are disclosed as related parties. For 2011, the following were considered related party transactions. Our revenues include revenues from the following types of transactions:
	•	Sales of NGLs related to our production to Williams Partners at market prices at the time of sale and included within our oil and gas sales revenues; and
	•	Sales to Williams Partners and another Williams subsidiary of natural gas procured by WPX Energy Marketing for those companies’ fuel and shrink replacement at market prices at the time of sale and included in our gas management revenues.
	Our costs and operating expenses include the following services provided by Williams Partners:
	•	Gathering, treating and processing services under several contracts for our production primarily in the San Juan and Piceance Basins; and
	•	Pipeline transportation for both our oil and gas sales and gas management activities which included commitments totaling $401 million at December 31, 2011.
	We have managed a transportation capacity contract for Williams Partners. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, Williams Partners reimburses us for these transportation costs. These reimbursements to us totaled approximately $11 million for the year ended December 31, 2011, and are included in gas management revenues. We signed an agreement with Williams Partners under which these contracts were assigned to them effective May 1, 2012.
	Prior to December 1, 2011, we participated in Williams’ centralized approach to cash management and the financing of its businesses. Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011, at which time the notes were cancelled by Williams.
	The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in owner’s net investment. Through fourth-quarter 2011, an additional $162 million was cancelled and reflected as an increase in owner’s net investment. The notes reflected interest based on Williams’ weighted average cost of debt and such interest was added monthly to the note principle. The interest rate for the notes payable to Williams was 8.08 percent at June 30, 2011.
	On August 25, 2011, we entered into a 10.5 year lease for our present headquarters office with Williams Headquarters Building Company, a direct subsidiary of Williams. We estimate the annual rent payable by us under the lease to be approximately $4 million per year.
	Below is a summary for 2011 of the transactions with Williams or its affiliates (including amounts in discontinued operations) discussed above:
		2011
		(Millions)
	Product revenues—sales of NGLs to Williams Partners	$	258
	Gas management revenues—sales of natural gas for fuel and shrink to Williams Partners and another Williams subsidiary	586
	Lease and facility operating expenses from Williams-direct employee salary and benefit costs	21
	Gathering, processing and transportation expense from services with Williams Partners:
	Gathering and processing	298
	Transportation	44
	General and administrative from Williams:
	Direct employee salary and benefit costs	111
	Charges for general and administrative services	62
	Allocated general corporate costs	62
	Other	16
	Interest expense on notes payable to Williams	96

Investment_Income_and_Other

Investment Income and Other	12 Months Ended
	Dec. 31, 2013
Investments, Debt and Equity Securities [Abstract]	'
Investment Income and Other	'
	Investment Income and Other
	Investment income
		Years Ended December 31,
		2013			2012		2011
		(Millions)
	Equity earnings- Petrolera Entre Lomas S.A.	$	19		$	26	$	20
	Equity earnings- other	4			4		4
	Impairment of equity method investment in Appalachian Basin	(20		)	—		—
	Other	2			—		2
	Total investment income and other	$	5		$	30	$	26
	The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.
	Investments
		December 31,
		2013			2012
		(Millions)
	Petrolera Entre Lomas S.A.—40.8%	$	125		$	109
	Other	20			36
		$	145		$	145
	Petrolera Entre Lomas S.A. operates several development concessions in South America. Other is comprised of investments in miscellaneous gas gathering interests in the United States.
	Dividends and distributions received from companies accounted for by the equity method were $7 million, $12 million and $17 million in 2013, 2012 and 2011, respectively.

Earnings_Loss_Per_Common_Share

Earnings (Loss) Per Common Share from Continuing Operations	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings (Loss) Per Common Share from Continuing Operations	'
	Earnings (Loss) Per Common Share from Continuing Operations
	The following table summarizes the calculation of earnings per share.
		Years Ended December 31,
		2013				2012			2011
		(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	$	1,185			$	(245	)	$	(160	)
	Basic weighted-average shares	200.5				198.8			197.1
	Diluted weighted-average shares	200.5				198.8			197.1
	Earnings (loss) per common share from continuing operations:
	Basic	$	(5.91	)		$	(1.23	)	$	(0.81	)
	Diluted	$	(5.91	)		$	(1.23	)	$	(0.81	)
	The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidiltive due to our loss from continuing operations attributable to WPX Energy, Inc.
		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Weighted-average nonvested restricted stock units and awards	2.5			1.9			2.9
	Weighted-average stock options	1.1			1			1.2
	On December 31, 2011, 197.1 million shares of our common stock were distributed to Williams’ shareholders in conjunction with our spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount of common stock to be outstanding as of the beginning of 2011 in the calculation of basic and diluted weighted average shares.
	The table below includes information related to stock options that were outstanding at December 31, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
		2013				2012
	Options excluded (millions)	0.4				1.3
	Weighted-average exercise price of options excluded	$	20.24			$	18.17
	Exercise price range of options excluded	$20.21 - $20.97				$16.46  - $20.97
	Fourth quarter weighted-average market price(a)	$	19.97			$	16.15
	__________
	(a)	Our stock began trading on the New York Stock Exchange on January 3, 2012; therefore, a fourth quarter weighted-average market price is not available for 2011.

Asset_Sales_Impairments_and_Ex

Asset Sales, Impairments and Exploration Expenses	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Asset Sales, Impairments and Exploration Expenses	'
	Asset Sales, Impairments and Exploration Expenses
	In 2013, we recorded a total of $1.4 billion in impairment charges of which $1,055 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expense and $20 million is included in investment income and other (see Note 4). These impairments are discussed further in the sections below.
	Impairments and Asset Sales
	The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, gain on sale, and other—net within costs and expenses. These significant adjustments are primarily associated with our domestic operations.
		Years Ended December 31,
		2013		2012		2011
		(Millions)
	Impairment of producing properties and costs of acquired unproved reserves(a)	$	1,055	$	225	$	367
	Gain on sale of Powder River Basin deep rights leasehold	$	36	$	—	$	—
	Net gain on sales of other assets	$	4	$	4	$	1
	__________
	(a)	Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
	As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded the following impairments during 2013:
	•	$772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin;
	•	$192 million impairment in the fourth quarter including $107 million of proved producing oil and gas properties and $85 million of the capitalized costs of acquired unproved reserves in the Powder River Basin;
	•	$88 million impairment in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area; and,
	•	$3 million impairment in the fourth quarter on property in Colombia.
	As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded impairments of $48 million of proved producing oil and gas properties in the Green River Basin. Additionally, we recorded a total of $102 million and $75 million in impairments of capitalized costs of acquired unproved reserves primarily in the Powder River Basin and Piceance Basin, respectively. Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and reserves quantities (see Note 15).
	As part of our assessment for impairments primarily resulting from declining forward natural gas prices during the fourth-quarter 2011, we recorded a $276 million impairment of proved producing oil and gas properties in the Powder River Basin (see Note 15). Additionally, we recorded a $91 million impairment of our capitalized cost of acquired unproved reserves in the Powder River Basin.
	Our impairment analyses included an assessment of undiscounted (except for the costs of acquired unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 15).
	In October 2013, we completed the sale of deep rights leasehold on approximately 140,000 net acres in the Powder River Basin for $36 million. This sale did not include our producing coal bed methane assets in the Powder River Basin.
	Exploration Expenses
	The following table presents a summary of exploration expenses.
		Years Ended December 31,
		2013		2012		2011
		(Millions)
	Geologic and geophysical costs	$	22	$	21	$	18
	Dry hole costs	7		4		13
	Unproved leasehold property impairment, amortization and expiration	402		58		95
	Total exploration expenses	$	431	$	83	$	126
	Dry hole costs in 2011 reflect an $11 million dry hole expense in connection with a Marcellus Shale well in Columbia County, Pennsylvania.
	Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold, while 2011 includes a $50 million write-off of leasehold costs associated with certain portions of our Columbia County, Pennsylvania acreage that we did not plan to develop. The $317 million impairment is associated with our impairment of the producing properties in the Appalachian Basin.

Properties_and_Equipment

Properties and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Properties and Equipment	'
	Properties and Equipment
	Properties and equipment is carried at cost and consists of the following:
		Estimated		December 31,
		Useful
		Life(a)
		(Years)		2013				2012
				(Millions)
	Proved properties	(b)		$	11,476			$	11,267
	Unproved properties	(c)		423				1,156
	Gathering, processing and other facilities	15-25		225				247
	Construction in progress	(c)		382				497
	Other	Mar-40		180				172
	Total properties and equipment, at cost			12,686				13,339
	Accumulated depreciation, depletion and amortization			(5,445		)		(4,923		)
	Properties and equipment—net			$	7,241			$	8,416
	__________
	(a)	Estimated useful lives are presented as of December 31, 2013.
	(b)	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
	(c)	Unproved properties and construction in progress are not yet subject to depreciation and depletion.
	Unproved properties consist primarily of non-producing leasehold in the Appalachian Basin and the Williston Basin and costs of acquired unproved reserves in the Powder River and Piceance Basins.
	Construction in progress includes $15 million in 2013 and $44 million in 2012 related to wells located in the Powder River Basin. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production. Additionally, construction in progress in 2013 includes $24 million related to exploratory well costs pending the determination of proved reserves.
	Asset Retirement Obligations
	Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
	A rollforward of our asset retirement obligations for the years ended 2013 and 2012 is presented below.
		2013				2012
		(Millions)
	Balance, January 1	$	321			$	289
	Liabilities incurred during the period	14				19
	Liabilities settled during the period	(11		)		(7		)
	Estimate revisions	17				(1		)
	Accretion expense(a)	23				21
	Balance, December 31	$	364			$	321
	Amount reflected as current	$	6			$	5
	__________
	(a)	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
	Estimate revisions in 2013 are primarily associated with increases in anticipated plug and abandonment costs.

Accounts_Payable_and_Accrued_a

Accounts Payable and Accrued and Other Current Liabilities	12 Months Ended
	Dec. 31, 2013
Payables and Accruals [Abstract]	'
Accounts Payable and Accrued and Other Current Liabilities	'
	Accounts Payable and Accrued and Other Current Liabilities
	Accounts Payable
		December 31,
		2013		2012
		(Millions)
	Trade	$	213	$	209
	Accrual for capital expenditures	237		126
	Royalties	130		106
	Cash overdrafts	35		34
	Other	37		34
		$	652	$	509
	Accrued and other current liabilities
		December 31,
		2013		2012
		(Millions)
	Taxes other than income taxes	$	41	$	54
	Accrued interest	43		42
	Compensation and benefit related accruals	52		52
	Other, including other loss contingencies	54		53
		$	190	$	201

Debt_and_Banking_Arrangements

Debt and Banking Arrangements	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt and Banking Arrangements	'
	Debt and Banking Arrangements
	As of the indicated dates, our debt consisted of the following:
		December 31,
		2013(a)		2012 (a)
		(Millions)
	5.250% Senior Notes due 2017	$	400	$	400
	6.000% Senior Notes due 2022	1,100		1,100
	Credit facility agreement	410		—
	Apco	8		8
	Other	1		2
	Total debt	$	1,919	$	1,510
	Less: Current portion of long-term debt	3		2
	Total long-term debt	$	1,916	$	1,508
	__________
	(a)	Interest paid on debt totaled $91 million and $58 million for 2013 and 2012, respectively.
	Senior Notes
	In November 2011, we issued $1.5 billion in face value Senior Notes (“the Notes”). The Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the Notes were approximately $1.481 billion after deducting the initial purchasers’ discounts and our offering expenses. We retained $500 million of the net proceeds from the issuance of the Notes and distributed the remainder of the net proceeds from the issuance of the Notes, approximately $981 million, to Williams in connection with the Contribution.
	Optional Redemption. We have the option, prior to maturity, in the case of the 2017 notes, and prior to October 15, 2021 (which is three months prior to the maturity date of the 2022 notes) in the case of the 2022 notes, to redeem all or a portion of the Notes of the applicable series at any time at a redemption price equal to the greater of (i) 100% of their principal amount and (ii) the discounted present value of 100% of their principal amount and remaining scheduled interest payments, in either case plus accrued and unpaid interest to the redemption date. We also have the option at any time on or after October 15, 2021, to redeem the 2022 notes, in whole or in part, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest thereon to the redemption date.
	Change of Control. If we experience a change of control (as defined in the indenture governing the Notes) accompanied by a rating decline with respect to a series of Notes, we must offer to repurchase the Notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
	Covenants. The terms of the 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 will be 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 of any series:
	(1) a default in the payment of interest on the Notes when due that continues for 30 days;
	(2) a default in the payment of the principal of or any premium, if any, on the Notes when due at their stated maturity, upon redemption, or otherwise;
	(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and
	(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
	Notes Registration. In June 2012, we completed an exchange offer whereby we exchanged our privately-placed Notes for like principal amounts of registered 5.250% Senior Notes due 2017 and 6.000% Senior Notes due 2022. The exchange offer fulfilled our obligations under the registration rights agreement that we entered into as part of the November 2011 issuance.
	Credit Facility Agreement
	During 2011, we entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. As of December 31, 2013, the weighted average variable interest rate was 2.27 percent on the $410 million outstanding under the Credit Facility Agreement. Subsequent to December 31, 2013, we have borrowed an additional net amount of $195 million under the Credit Facility Agreement.
	Interest on borrowings under the Credit Facility Agreement will be payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Applicable Rate changes depending on which interest rate we select and our credit rating. Additionally, we will be required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility Agreement.
	Under the Credit Facility Agreement, prior to the occurrence of the Investment Grade Date (as defined below), we will be required to maintain a ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness (each as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. Net present value is determined as of the end of each fiscal year and reflects the present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (such cash flows are adjusted to reflect the impact of hedges, our lenders’ commodity price forecasts, and, if necessary, to include only a portion of our reserves that are not proved developed producing reserves). Additionally, the ratio of debt to capitalization (defined as net worth plus debt) will not be permitted to be greater than 60%. We were in compliance with our debt covenant ratios as of December 31, 2013. Investment Grade Date means the first date on which our long-term senior unsecured debt ratings are BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
	The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness, make investments, loans or advances and enter into certain hedging agreements; our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person, enter into certain affiliate transactions, make certain distributions during the continuation of an event of default and allow material changes in the nature of our business. In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors.
	The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.
	Letters of Credit
	In addition to the Notes and Credit Facility Agreement, WPX has entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2013 a total of $361 million in letters of credit have been issued.
	Apco
	Apco had a loan agreement with a financial institution for a $10 million bank line of credit. As of December 31, 2013, Apco had borrowed $8 million under this banking agreement. Principal amounts will be repaid in installments through 2016. This debt agreement contains covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, purchase or sell assets outside the ordinary course of business, and incur additional debt.

Provision_Benefit_for_Income_T

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Provision (Benefit) for Income Taxes	'
	Provision (Benefit) for Income Taxes
	The provision (benefit) for income taxes from continuing operations includes:
		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Provision (benefit):
	Current:
	Federal	$	(29	)	$	48		$	49
	State	1			3			7
	Foreign	18			14			10
		(10		)	65			66
	Deferred:
	Federal	(608		)	(162		)	(139		)
	State	(51		)	(13		)	(1		)
	Foreign	14			(1		)	—
		(645		)	(176		)	(140		)
	Total provision (benefit)	$	(655	)	$	(111	)	$	(74	)
	Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Provision (benefit) at statutory rate	$	(646	)	$	(120	)	$	(79	)
	Increases (decreases) in taxes resulting from:
	State income taxes (net of federal benefit)	(110		)	(10		)	(5		)
	State income change in valuation allowance (net of federal benefit)	80			3			—
	Effective state income tax rate change (net of federal benefit)	(3		)	—			9
	Alternative minimum tax credits	—			11			—
	Argentina capital tax (net of federal benefit)	10			—			—
	Foreign operations	5			4			—
	Other	9			1			1
	Provision (benefit) for income taxes	$	(655	)	$	(111	)	$	(74	)
	Significant components of deferred tax liabilities and deferred tax assets are as follows:
		December 31,
		2013			2012
		(Millions)
	Deferred tax liabilities:
	Properties and equipment	$	963		$	1,652
	Other, net	36			19
	Total deferred tax liabilities	999			1,671
	Deferred tax assets:
	Accrued liabilities and other	176			176
	Alternative minimum tax credits	76			99
	Loss carryovers	89			31
	Other	21			—
	Total deferred tax assets	362			306
	Less: valuation allowance	102			19
	Total net deferred tax assets	260			287
	Net deferred tax liabilities	$	739		$	1,384
	Net cash refunds for domestic income taxes were $26 million in 2013 while net cash payments were $40 million and $10 million in 2012 and 2011, respectively. Additionally, payments made directly to foreign taxing authorities were $14 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
	As of December 31, 2013, the Company has approximately $114 million of federal net operating loss ("NOL") carryovers which begin expiring after 2033, as well as approximately $825 million of state NOL carryovers, primarily in Pennsylvania, of which more than 90 percent expire after 2029.
	Income (loss) from continuing operations before income taxes includes foreign income of $50 million, $52 million and $40 million in 2013, 2012 and 2011, respectively. This income is attributable to our 69 percent investment in Apco, a Cayman Islands corporation with operations in Argentina and Colombia. The statutory income tax rate in Argentina is 35 percent while the rate in Colombia is 25 percent with an additional 9 percent for certain items.
	We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania and Apco's operations in Colombia. In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. Apco has historically generated NOLs from its Colombia operations. As a result of our assessment of available evidence, valuation allowances were recorded to reduce recognized tax assets, net of federal benefit, to an amount that will more likely than not be realized by the Company.
	Undistributed earnings of Apco at December 31, 2013, excluding amounts related to Apco's equity investment in Petrolera Entre Lomas S.A. ("Petrolera") totaled approximately $76 million. No provision for deferred U.S. income taxes has been made for those undistributed earnings because it is our intent to reinvest Apco's earnings in its operation in Argentina and Colombia. U.S income taxes have been accrued as required by GAAP, however, to the extent book basis exceeds tax basis in Apco's equity investment in Petrolera.
	In September 2013, the Argentine government enacted tax reform legislation related to dividends and capital gains which will apply to the Argentine operations of Apco. The new 10 percent dividend tax will be accrued by Apco when dividends are paid by its Argentine investments in future periods. The capital gains tax applies to the sale of Argentine securities by a non-Argentine resident, such as Apco, making such sales subject to an effective 13.5 percent tax on the gross proceeds. As a result, Apco recorded approximately $14 million of foreign deferred tax expense during third quarter 2013 for the excess book basis over tax basis in its equity investment in Petrolera, of which approximately $12 million relates to basis differences that occurred prior to 2013. This accrual was partially offset by approximately $4 million of U.S. deferred tax benefit recorded by WPX related to the additional Argentine tax.
	Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the additional tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. Since the additional tax benefit does not reduce our current taxes payable for 2013, these tax benefits are not included in the Company’s loss carryovers deferred tax asset. The additional tax benefit deductible for tax purposes but not included in our loss carryovers deferred tax asset as of December 31, 2013 totaled $7 million.
	Through the effective date of the spin-off, December 31, 2011, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for 2011 has been calculated on a separate return basis for the Company and its consolidated subsidiaries, except for certain adjustments such as alternative minimum tax calculated at the consolidated level by Williams. Effective with the spin-off, Williams and the Company entered into a tax sharing agreement which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off.
	In connection with the spin-off, alternative minimum tax credits were estimated and allocated between Williams and the Company effective December 31, 2011. This resulted in the allocation to the Company of a $98 million deferred tax asset with a corresponding increase to additional paid-in-capital. Subsequent to the spin-off, Williams notified the Company of certain corrections that resulted in $15 million of reductions in the alternative minimum tax credit allocated to the Company of which $11 million is a reduction of the benefit for income taxes in 2012.
	Pursuant to our tax sharing agreement with Williams, we will remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. During the third quarter of 2012, Williams finalized settlements with the IRS for 2009 and 2010. We were recently notified that the IRS has commenced an audit of Williams' 2011 consolidated tax filing. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for Apco's operations in Argentina are open to audit for the 2006 to 2013 tax years.
	The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
	As of December 31, 2013, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of an unrecognized tax benefit.

Contingent_Liabilities_and_Com

Contingent Liabilities and Commitments	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Contingent Liabilities and Commitments	'
	Contingent Liabilities and Commitments
	Royalty litigation
	In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs' proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We are in the process of conducting an accounting under that standard. 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, fraud, fraud concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
	Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR's guidance provides its view as to how much of a producer's bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR's assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR's predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2007 through December 2013, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $106 million.
	Environmental matters
	The Environmental Protection Agency (“EPA”), other federal agencies, and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
	Matters related to Williams’ former power business
	In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending or threatened litigation described below relating to the 2000-2001 California energy crisis and the reporting of certain natural gas-related information to trade publications.
	California energy crisis
	Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (“FERC”). We have entered into settlements with the State of California (“State Settlement”), major California utilities (“Utilities Settlement”) and others that substantially resolved each of these issues with these parties.
	Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We currently have a settlement agreement in principle with certain California utilities aimed at eliminating and substantially reducing this exposure. Once finalized, the settlement agreement will also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement will resolve most, if not all, of our legal issues arising from the 2000-2001 California energy crisis. With respect to these matters, amounts accrued are not material to our financial position.
	Certain other issues also remain open at the FERC and for other nonsettling parties.
	Reporting of 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. Defendants' filed a petition for writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.
	Other Indemnifications
	Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
	At December 31, 2013, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
	In connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
	Summary
	As of December 31, 2013 and December 31, 2012, the Company had accrued approximately $16 million and $18 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In 2013, we accrued and settled certain royalty litigation matters for approximately $8 million. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
	Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
	Commitments
	As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2013 are as follows:
		(Millions)
	2014	$	224
	2015	219
	2016	197
	2017	178
	2018	167
	Thereafter	578
	Total	$	1,563
	We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services and well completion services, which total $389 million over approximately six years.
	We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in November 2014.
	In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
	Future minimum annual rentals under noncancelable operating leases as of December 31, 2013, are payable as follows:
		(Millions)
	2014	$	58
	2015	50
	2016	29
	2017	8
	2018	7
	Thereafter	22
	Total	$	174
	Total rent expense, excluding amounts capitalized, was $27 million, $20 million and $12 million in 2013, 2012 and 2011, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Postemployment Benefits [Abstract]	'
Employee Benefit Plans	'
	Employee Benefit Plans
	Subsequent to spin-off
	On January 1, 2012, several new plans became effective for us including a defined contribution plan. WPX matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $16 million and $6 million for 2013 and 2012, respectively. Approximately $11 million and $10 million were included in accrued and other current liabilities at December 31, 2013 and December 31, 2012, respectively, related to the non-matching annual employer contribution.
	Prior to spin-off
	Through the spin-off date, certain benefit costs associated with direct employees who supported our operations were determined based on a specific employee basis and were charged to us by Williams as described below. These pension and post retirement benefit costs included amounts associated with vested participants who are no longer employees. As described in Note 3, Williams also charged us for the allocated cost of certain indirect employees of Williams who provided general and administrative services on our behalf. Williams included an allocation of the benefit costs associated with these Williams employees based upon Williams’ determined benefit rate, not necessarily specific to the employees providing general and administrative services on our behalf. As a result, the information described below is limited to amounts associated with the direct employees that supported our operations.
	For the periods presented, we were not the plan sponsor for these plans. Accordingly, our Consolidated Balance Sheets do not reflect any assets or liabilities related to these plans.
	Pension plans
	Williams is the sponsor of noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2011 totaled $8 million.
	Other postretirement benefits
	Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (“other postretirement benefits”) that provide benefits to certain eligible participants, generally including employees hired on or before December 31, 1991, and other miscellaneous defined participant groups. Other postretirement benefit expense charged to us by Williams for 2011 totaled less than $1 million.
	Defined contribution plan
	Williams also is the sponsor of a defined contribution plan that provides benefits to certain eligible participants and charged us compensation expense of $4 million in 2011 for Williams’ matching contributions to this plan.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-Based Compensation	'
	Stock-Based Compensation
	WPX Energy, Inc. 2011 Incentive Plan
	Subsequent to the spin-off, we have an equity incentive plan (“2011 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2011 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2011 Incentive Plan is 11 million shares. The 2011 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2011 Incentive Plan.
	The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 117 thousand shares at an average price of $14.33 per share during 2013.
	The Williams Companies, Inc. Incentive Plan
	Certain of our direct employees participated in The Williams Companies, Inc. 2007 Incentive Plan, which provides for Williams common-stock-based awards to both employees and Williams’ nonmanagement directors. The plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets.
	Through the date of spin-off, we were charged by Williams for stock-based compensation expense related to our direct employees. Williams also charged us for the allocated costs of certain indirect employees of Williams (including stock-based compensation) who provided general and administrative services on our behalf. However, information included in this note is limited to stock-based compensation associated with the direct employees for 2011. See Note 3 for total costs charged to us by Williams.
	Williams’ Compensation Committee determined that all outstanding Williams stock-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (the “Pre-2006 Options”), be converted into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options (whether held by our employees or other Williams employees) converted into options for both Williams and WPX common stock following the spin-off, in the same ratio as is used in the distribution of WPX common stock to holders of Williams common stock. The number of shares underlying each such award (including the Pre-2006 Options) and, with respect to options (including the Pre-2006 Options), the per share exercise price of each award was adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of each award.
	Employee stock-based awards
	Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
	Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
	Restricted stock units are generally valued at fair value on the grant date and generally vest over three years . Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
	Total stock-based compensation expense (including amount charged to us by Williams) reflected in general and administrative expense for the years ended December 31, 2013, 2012 and 2011 was $31 million, $28 million and $18 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2013 was $41 million. This amount is comprised of $1 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 2.0 years.
	Stock Options
	The following summary reflects stock option activity and related information for the year ended December 31, 2013.
		WPX Plan
	Stock Options	Options			Weighted-				Aggregate
					Average				Intrinsic
					Exercise				Value
					Price
		(Millions)							(Millions)
	Outstanding at December 31, 2012(a)	4.1			$	12.68			$	14
	Granted	0.4			$	14.41
	Exercised	(0.4	)		$	8.86
	Forfeited	—			$	16.46
	Expired	—			$	19.26
	Outstanding at December 31, 2013(a)	4.1			$	13.27			$	29
	Exercisable at December 31, 2013	3.2			$	12.62			$	25
	__________
	(a)	Includes approximately 344 thousand shares held by Williams’ employees at a weighted average price of $9.24 per share at December 31, 2013 and 598 thousand shares held by Williams' employees at a weighted average price of $8.48 per share at December 31, 2012.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $5 million, $5 million and $7 million, respectively.
	The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2013.
		WPX Plan
		Stock Options Outstanding									Stock Options Exercisable
	Range of Exercise Prices	Options			Weighted-				Weighted-		Options		Weighted-		Weighted-
					Average				Average				Average		Average
					Exercise				Remaining				Exercise		Remaining
					Price				Contractual				Price		Contractual
									Life						Life
		(Millions)							(Years)		(Millions)				(Years)
	$5.50 to $6.02	0.8			$	5.95			4.5		0.8		$	5.95	4.5
	$9.08 to $11.75	0.9			$	11.34			4.3		0.9		$	11.34	4.3
	$12.00 to $15.67	1.1			$	14.45			5.4		0.7		$	14.47	2.9
	$16.46 to $20.97	1.3			$	18.17			6.4		0.8		$	18.48	5.9
	Total	4.1			$	13.27			5.3		3.2		$	12.62	4.5
	The estimated fair value at date of grant of options for our common stock and date of conversion for WPX awards in each respective year, using the Black-Scholes option pricing model, is as follows:
		WPX Plan
		2013				2012				2011
	Weighted-average grant date fair value of options granted	$	6.04			$	7.79			$	—
	Weighted-average conversion date fair value options granted									$	8.48
	Weighted-average assumptions:
	Dividend yield	—				—				—
	Volatility	42.8		%		43.8		%		45		%
	Risk-free interest rate	1.06		%		1.17		%		0.38		%
	Expected life (years)	6				6				2.8
	For 2013 and 2012, we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method.
	For 2011, the weighted average fair value is a component of the intrinsic value calculation at spin-off. The expected volatility yield is based on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the modification date. The expected life of the options is based over the remaining option term.
	Cash received from stock option exercises was $4 million and $2 million during 2013 and 2012, respectively.
	Nonvested Restricted Stock Units
	The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2013.
		WPX Plan
	Restricted Stock Units	Shares			Weighted-
					Average
Fair Value(a)
	(Millions)
Nonvested at December 31, 2012	4.8			$	16.45
Granted	2.2			$	14.97
Forfeited	(0.2	)		$	16.61
Vested	(1.6	)		$	11.27
Nonvested at December 31, 2013	5.2			$	16.97
__________
(a)	Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other restricted stock unit information
	WPX Plan								Williams Plan
	2013				2012				2011
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	14.97			$	17.35			$	27.74
Total fair value of restricted stock units vested during the year (millions)	$	18			$	14			$	10
Performance-based shares granted represent 17 percent of nonvested restricted stock units outstanding at December 31, 2013. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Stockholders' Equity	'
	Stockholders’ Equity
	Common Stock
	Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends were declared or paid for 2013, 2012 or 2011. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
	Preferred Stock
	Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
	The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
	•	Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
	•	Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps, and options. These options, which hedge future sales of production, are structured as costless collars or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.
	•	Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
	In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
	The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
		December 31, 2013												December 31, 2012
		Level 1			Level 2				Level 3			Total		Level 1		Level 2		Level 3		Total
					(Millions)											(Millions)
	Energy derivative assets	$	30		$	26			$	1		$	57	$	20	$	38	$	2	$	60
	Energy derivative liabilities	$	83		$	38			$	1		$	122	$	11	$	1	$	3	$	15
	Total debt(a)	$	—		$	1,945			$	—		$	1,945	$	—	$	1,617	$	—	$	1,617
	__________
	(a)	The carrying value of total debt, excluding capital leases, was $1,918 million and $1,508 million as of December 31, 2013 and 2012, respectively.
	Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
	Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
	The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
	Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
	Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
	Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
	Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2013, consist primarily of natural gas index transactions that are used to manage our physical requirements.
	Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2013 or 2012. During the period ended March 31, 2011, certain NGL swaps that originated during the first quarter of 2011 were transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3 due to a lack of observable third-party market quotes. Due to an increase in exchange-traded transactions and greater visibility from OTC trading, we transferred these instruments to Level 2.
	The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
		Years ended December 31,
		2013			2012				2011
		Net Energy			Net Energy				Net Energy
		Derivatives			Derivatives				Derivatives
		(Millions)
	Beginning balance	$	(1	)	$	1			$	1
	Realized and unrealized gains (losses):
	Included in income (loss) from continuing operations	(2		)	3				15
	Included in other comprehensive income (loss)	—			—				—
	Purchases, issuances, and settlements	3			(5		)		(12		)
	Transfers out of Level 3	—			—				(3		)
	Ending balance	$	—		$	(1	)		$	1
	Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	(1	)	$	(1	)		$	1
	Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations.
	For the year ending December 31, 2011, the entire $12 million reduction to level 3 fair value measurements are settlements.
	As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, future natural gas liquids prices, expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In each of the three years ended December 31, 2013, our assessments identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
		Total losses for
		the years ended December 31,
		2013					2012					2011
		(Millions)
	Impairments:
	Producing properties and costs of acquired unproved reserves (Note 6)	1,055			(a)		225				(b)	367		(c)
	Unproved leasehold	317			(a)		—					—
	Equity method investment (Note 4)	20					—					—
		$	1,392				$	225				$	367
	__________
	(a)	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million
	•	$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
	•	$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.
	•	$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
	•	$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
	•	$85 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
	(b)	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.
	•	$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
	•	$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
	(c)	As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.
	•	$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
	•	$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Derivatives_and_Concentration_

Derivatives and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives and Concentration of Credit Risk	'
	Derivatives and Concentration of Credit Risk
	Energy Commodity Derivatives
	Risk Management Activities
	We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
	We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.
	We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.
	The following table sets forth the derivative notional volumes that are economic hedges of production volumes as well as notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, both which are included in our commodity derivatives portfolio as of December 31, 2013.
	Derivatives related to production
	Commodity		Period		Contract Type(a)		Location		Notional Volume(b)			Weighted Average
												Price(c)
	Crude Oil		2014		Fixed Price Swaps		WTI		(13,243	)		$	94.82
	Crude Oil		2014		Basis Swaps		Brent		(4,463	)		$	9.64
	Natural Gas		2014		Fixed Price Swaps		Henry Hub		(315	)		$	4.19
	Natural Gas		2014		Swaptions		Henry Hub		(50	)		$	4.24
	Natural Gas		2014		Costless Collars		Henry Hub		(165	)		$ 4.01 - 4.64
	Natural Gas		2014		Basis Swaps		Northeast		(23	)		$	0.09
	Natural Gas		2014		Basis Swaps		MidCon		(39	)		$	(0.18	)
	Natural Gas		2014		Basis Swaps		Rockies		(78	)		$	(0.18	)
	Natural Gas		2014		Basis Swaps		West		(27	)		$	0.08
	NGL - Ethane		2014		Fixed Price Swaps		Mont Belvieu		(986	)		$	0.28
	NGL - Natural Gasoline		2014		Fixed Price Swaps		Mont Belvieu		(822	)		$	2.05
	Crude Oil		2015		Swaptions		WTI		(1,750	)		$	98.54
	Natural Gas		2015		Fixed Price Swaps		Henry Hub		(35	)		$	4.38
	Natural Gas		2015		Swaptions		Henry Hub		(35	)		$	4.38
	Derivatives primarily related to storage and transportation
	Commodity		Period		Contract Type(d)		Location(e)		Notional Volume(b)			Weighted Average
												Price(f)
	Natural Gas		2014		Fixed Price Swaps		Multiple		(11	)		—
	Natural Gas		2014		Basis Swaps		Multiple		(31	)		—
	Natural Gas		2014		Index		Multiple		(107	)		—
	Natural Gas Liquids		2014		Fixed Price Swaps		Multiple		(822	)		—
	Natural Gas		2015		Basis Swaps		Multiple		(6	)		—
	Natural Gas		2015		Index		Multiple		(43	)		—
	Natural Gas		2016		Index		Multiple		2			—
	Natural Gas		2017		Index		Multiple		2			—
	__________
	(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.
	(d)	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.
	(e)	WPX Marketing transacts at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
	(f)	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.
		December 31,
		2013								2012
		Assets				Liabilities				Assets				Liabilities
		(Millions)
	Derivatives related to production designated as hedging instruments	$	—			$	—			$	5			$	—
	Not designated as hedging instruments:
	Derivatives related to production not designated as hedging instruments	26				39				33				—
	Derivatives related to physical marketing agreements not designated as hedging instruments	31				83				20				13
	Legacy natural gas contracts from former power business	—				—				2				2
	Total derivatives not designated as hedging instruments	57				122				55				15
	Total derivatives	$	57			$	122			$	60			$	15
	The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (“AOCI”) or revenues.
		Years Ended								Classification
		December 31,
		2013				2012
		(Millions)
	Net gain recognized in other comprehensive income (loss) (effective portion)	$	—			$	90			AOCI
	Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	5			$	434			Revenues
	__________
(a)	Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
	Gross Amount Presented on Balance Sheet				Netting Adjustments (a)				Cash Collateral Posted(Received)				Net Amount
31-Dec-13	(Millions)
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	)
31-Dec-12
Derivative assets with right of offset or master netting agreements	$	60			$	(10	)		$	(2	)		$	48
Derivative liabilities with right of offset or master netting agreements	$	(15	)		$	10			$	—			$	(5	)
__________
(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 December 31, 2013, we had collateral totaling $71 million posted to derivative counterparties, which includes $19 million of initial margin to clearinghouses or exchanges to enter into positions and $52 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $72 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2012, we had collateral totaling $2 million posted to derivative counterparties to support the aggregate fair value of our net $5 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $20 million and $3 million at December 31, 2013 and December 31, 2012, respectively.
Cash flow hedges
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark to market value. As of December 31, 2012, we had hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) were reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Actual gains or losses realized in the first quarter of 2013 matched these values. These gains substantially offset net losses that were realized in earnings from previous unfavorable market movements associated with underlying hedged transactions.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:
	2013				2012
	(Millions)
Receivables by product or service:
Sale of natural gas and related products and services	$	339			$	289
Joint interest owners	186				138
Other	11				16
Total	$	536			$	443
Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2013, 2012 and 2011, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
The gross and net credit exposure from our derivative contracts as of December 31, 2013, is summarized as follows:
Counterparty Type	Gross  Investment			Gross Total				Net			Net Total
	Grade(a)							Investment
								Grade(a)
	(Millions)
Financial institutions	57			57				7			7
Credit reserves				—							—
Credit exposure from derivatives				$	57						$	7
__________
(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 three largest net counterparty positions represent approximately 89 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.
Other
At December 31, 2013, we held collateral support of approximately $55 million, either in the form of cash or letters of credit, related to our gas management sale agreements.
Revenues
During 2013, 2012, and 2011, BP Energy Company, a domestic segment customer, accounted for 15 percent, 10 percent and 11 percent of our consolidated revenues, respectively. During 2013, Southern California Gas Company accounted for 11 percent of our consolidated revenues. Williams accounted for 8 percent and 12 percent of our consolidated revenue for 2013 and 2012 respectively. Prior to 2012, Williams was considered an affiliate of WPX. See Note 3 for revenue related to Williams for 2011. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Segment_Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2013
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. Long-lived assets are comprised of gross property, plant and equipment and long-term investments.
	For the year ended December 31, 2013	Domestic			International		Total
					(Millions)
	Total revenues	$	2,609		$	152	$	2,761
	Costs and expenses:
	Lease and facility operating	$	271		$	37	$	308
	Gathering, processing and transportation	430			3		433
	Taxes other than income	117			24		141
	Gas management, including charges for unutilized pipeline capacity	931			—		931
	Exploration	424			7		431
	Depreciation, depletion and amortization	906			34		940
	Impairment of producing properties and costs of acquired unproved reserves	1,052			3		1,055
	Gain on sale of Powder River Basin deep rights leasehold	(36		)	—		(36		)
	General and administrative	275			14		289
	Other—net	17			—		17
	Total costs and expenses	$	4,387		$	122	$	4,509
	Operating income (loss)	$	(1,778	)	$	30	$	(1,748	)
	Interest expense	(108		)	—		(108		)
	Interest capitalized	5			—		5
	Investment income, impairment of equity method investment and other	(16		)	21		5
	Income (loss) from continuing operations before income taxes	$	(1,897	)	$	51	$	(1,846	)
	Other financial information:
	Net capital expenditures	$	1,103		$	51	$	1,154
	Total assets	$	8,046		$	383	$	8,429
	Long—lived assets	$	12,346		$	485	$	12,831
	For the year ended December 31, 2012
	Total revenues	$	3,052		$	137	$	3,189
	Costs and expenses:
	Lease and facility operating	$	251		$	32	$	283
	Gathering, processing and transportation	504			2		506
	Taxes other than income	87			24		111
	Gas management, including charges for unutilized pipeline capacity	996			—		996
	Exploration	72			11		83
	Depreciation, depletion and amortization	939			27		966
	Impairment of producing properties and costs of acquired unproved reserves	225			—		225
	General and administrative	273			14		287
	Other—net	12			—		12
	Total costs and expenses	$	3,359		$	110	$	3,469
	Operating income (loss)	$	(307	)	$	27	$	(280	)
	Interest expense	(102		)	—		(102		)
	Interest capitalized	8			—		8
	Investment income and other	3			27		30
	Income (loss) from continuing operations before income taxes	$	(398	)	$	54	$	(344	)
	Other financial information:
	Net capital expenditures	$	1,463		$	58	$	1,521
	Total assets	$	9,113		$	343	$	9,456
	Long-lived assets	$	13,056		$	428	$	13,484
	For the year ended December 31, 2011	Domestic			International		Total
					(Millions)
	Total revenues	$	3,772		$	110	$	3,882
	Costs and expenses:
	Lease and facility operating	$	235		$	27	$	262
	Gathering, processing and transportation	487			—		487
	Taxes other than income	113			21		134
	Gas management, including charges for unutilized pipeline capacity	1,471			—		1,471
	Exploration	123			3		126
	Depreciation, depletion and amortization	880			22		902
	Impairment of producing properties and costs of acquired unproved reserves	367			—		367
General and administrative	263			12		275
Other—net	(3		)	3		—
Total costs and expenses	$	3,936		$	88	$	4,024
Operating income (loss)	$	(164	)	$	22	$	(142	)
Interest expense	(117		)	—		(117		)
Interest capitalized	9			—		9
Investment income and other	6			20		26
Income (loss) from continuing operations before income taxes	$	(266	)	$	42	$	(224	)
Other financial information:
Net capital expenditures	$	1,531		$	41	$	1,572
Total assets	$	10,144		$	288	$	10,432
Long—lived assets	$	11,969		$	354	$	12,323

Quarterly_Financial_Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
QUARTERLY FINANCIAL DATA	'
	WPX Energy, Inc.
	QUARTERLY FINANCIAL DATA
	(Unaudited)
	Summarized quarterly financial data are as follows:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(Millions, except per-share amounts)
	2013
	Revenues	$	631		$	815		$	658		$	657
	Operating costs and expenses	710			689			687			1,098
	Income (loss) from continuing operations	(113		)	22			(116		)	(984		)
	Net income (loss)	(113		)	22			(116		)	(984		)
	Amounts attributable to WPX Energy, Inc.:
	Net income (loss)	(116		)	18			(114		)	(973		)
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)
	2012
	Revenues	$	910		$	775		$	677		$	827
	Operating costs and expenses	834			673			680			758
	Income (loss) from continuing operations	(38		)	(29		)	(63		)	(103		)
	Net income (loss)	(40		)	(6		)	(61		)	(104		)
	Amounts attributable to WPX Energy, Inc.:
	Net income (loss)	(43		)	(10		)	(64		)	(106		)
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.21	)	$	(0.17	)	$	(0.33	)	$	(0.53	)
	The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.
	Net loss for fourth-quarter 2013 includes the following pre-tax items:
	•	$1,373 million of impairments of costs of producing properties, acquired unproved reserves, leasehold and equity method investment (see Note 4 and Note 6).
	•	$36 million gain on the sale of deep rights in the Powder River Basin.
	•	$9 million buyout of a transportation agreement.
	Net loss for third-quarter 2013 includes the following pre-tax items:
	•	$19 million of impairments of costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin (see Note 6).
	•	$7 million accrual for litigation.
	Net loss for fourth-quarter 2012 includes the following pre-tax items:
	•	$108 million of impairments of producing properties and costs of acquired unproved reserves (see Note 6).
	Net loss for second-quarter 2012 includes the following pre-tax items:
	•	$65 million of impairments of costs of acquired unproved reserves in the Powder River Basin (see Note 6).
	•	Gain on sale of Barnett and Arkoma properties.
	Net loss for first-quarter 2012 includes the following pre-tax items:
	•	$52 million of impairments of costs of acquired unproved reserves primarily in the Powder River Basin (see Note 6).

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Supplemental Oil and Gas Disclosures	'
	We have significant oil and gas producing activities primarily in the Piceance and San Juan Basins in the Rocky Mountain region, the Williston Basin in North Dakota and the Appalachian Basin in Pennsylvania, all of which are located in the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. The following information excludes our gas management activities.
	With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information, through the date of sale in 2012, for the holdings in the Barnett Shale and Arkoma Basin which have been reported as discontinued operations in our consolidated financial statements. These operations represented less than five percent of our total domestic and international proved reserves in 2011.
	Capitalized Costs
		As of December 31, 2013
		Domestic				International				Consolidated			Entity’s share of
										Total			equity method
													investee
		(Millions)
	Proved Properties	$	11,349			$	350			$	11,699		$	330
	Unproved properties	414				9				423			2
		11,763				359				12,122			332
	Accumulated depreciation, depletion and amortization and valuation provisions	(5,070		)		(194		)		(5,264		)	(195		)
	Net capitalized costs	$	6,693			$	165			$	6,858		$	137
		As of December 31, 2012
		Domestic				International				Consolidated			Entity’s share of
										Total			equity method
													investee
		(Millions)
	Proved Properties	$	11,295			$	310			$	11,605		$	292
	Unproved properties	1,153				9				1,162			1
		12,448				319				12,767			293
	Accumulated depreciation, depletion and amortization and valuation provisions	(4,612		)		(161		)		(4,773		)	(181		)
	Net capitalized costs	$	7,836			$	158			$	7,994		$	112
	•	Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $329 million and $365 million, net, for 2013 and 2012, respectively.
	•	Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.
	•	Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproved reserves.
	Cost Incurred
		Domestic				International				Entity’s share of
										equity method
										investee
		(Millions)
	For the Year Ended December 31, 2013
	Acquisition	$	57			$	—			$	—
	Exploration	104				16				3
	Development	939				36				34
		$	1,100			$	52			$	37
	For the Year Ended December 31, 2012
	Acquisition	$	111			$	—			$	—
	Exploration	23				31				5
	Development	1,130				35				35
		$	1,264			$	66			$	40
	For the Year Ended December 31, 2011
	Acquisition	$	45			$	—			$	—
	Exploration	31				20				8
	Development	1,461				24				26
		$	1,537			$	44			$	34
	•	Costs incurred include capitalized and expensed items.
	•	Acquisition costs are as follows: The 2013 and 2012 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves. The 2011 costs are primarily for additional leasehold in the Appalachian Basin.
	•	Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.
	•	Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.
	•	We have classified our step-out drilling and site preparation costs in the Powder River Basin as development. While the immediate offsets are frequently in the dewatering stage, the development classification better reflects the low risk profile of the costs incurred.
	Results of Operations
		Domestic				International				Total
		(Millions)
	For the Year Ended December 31, 2013
	Revenues:
	Natural gas sales	$	1,074			$	19			$	1,093
	Oil and condensate sales	534				115				649
	Natural gas liquid sales	228				2				230
	Net gain (loss) on derivatives not designated as hedges	(57		)		—				(57		)
	Other revenues	6				16				22
	Total revenues	1,785				152				1,937
	Costs:
Lease and facility operating	271				37				308
Gathering, processing and transportation	430				3				433
Taxes other than income	117				24				141
Exploration	424				7				431
Depreciation, depletion and amortization	906				34				940
Impairment of certain natural gas properties primarily in the Appalachian and Powder River Basins	899				3				902
Impairment of costs of acquired unproved reserves	153				—				153
Gain on sale of Powder River deep rights leasehold	(36		)		—				(36		)
General and administrative	268				14				282
Other (income) expense	17				—				17
Total costs	3,449				122				3,571
Results of operations	(1,664		)		30				(1,634		)
Provision (benefit) for income taxes	(621		)		11				(610		)
Exploration and production net income (loss)	$	(1,043	)		$	19			$	(1,024	)
	Domestic				International				Total
	(Millions)
For the Year Ended December 31, 2012
Revenues:
Natural gas sales	$	1,346			$	18			$	1,364
Oil and condensate sales	376				115				491
Natural gas liquid sales	296				3				299
Net gain on derivatives not designated as hedges	66				—				66
Other revenues	7				1				8
Total revenues	2,091				137				2,228
Costs:
Lease and facility operating	251				32				283
Gathering, processing and transportation	504				2				506
Taxes other than income	87				24				111
Exploration	72				11				83
Depreciation, depletion and amortization	939				27				966
Impairment of certain natural gas properties in the Green River Basin	48				—				48
Impairment of costs of acquired unproved reserves	177				—				177
General and administrative	267				14				281
Other (income) expense	14				—				14
Total costs	2,359				110				2,469
Results of operations	(268		)		27				(241		)
Provision (benefit) for income taxes	(98		)		10				(88		)
Exploration and production net income (loss)	$	(170	)		$	17			$	(153	)
	Domestic				International				Total
	(Millions)
For the Year Ended December 31, 2011
Revenues:
Natural gas sales	$	1,678			$	16			$	1,694
Oil and condensate sales	226				86				312
Natural gas liquid sales	404				4				408
Other revenues	7				4				11
Total revenues	2,315				110				2,425
Costs:
Lease and facility operating	235				27				262
Gathering, processing and transportation	487				—				487
Taxes other than income	113				21				134
Exploration	123				3				126
Depreciation, depletion and amortization	880				22				902
Impairment of certain natural gas properties in the Powder River Basin	276				—				276
Impairment of costs of acquired unproved reserves	91				—				91
General and administrative	246				12				258
Other (income) expense	(3		)		3				—
Total costs	2,448				88				2,536
Results of operations	(133		)		22				(111		)
Provision (benefit) for income taxes	(49		)		8				(41		)
Exploration and production net income (loss)	$	(84	)		$	14			$	(70	)
•	Amounts for all years exclude the equity earnings (losses) from our equity method investees. Net equity earnings (losses) from these investees were $23 million, $30 million and $24 million in 2013, 2012 and 2011, respectively.
•	Natural gas revenues consist of natural gas production sold and includes realized gains (losses) of derivatives that were designated as cash flow hedges in 2012 and 2011.
•	For derivative instruments that were entered into after January 1, 2012, we did not designate those as cash flow hedges. Any gain (loss) related to these derivatives is included in net gain on derivatives not designated as hedges.
•	Other revenues consist of activities that are an indirect part of the producing activities.
•	Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachia Basin.
•	Depreciation, depletion and amortization includes depreciation of support equipment.
Proved Reserves
The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
The following is a summary of and changes in our domestic and international proved reserves. Our international reserves are primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest. The Entity’s share of equity method investee represents Apco’s 40.8 percent interest in reserves of Petrolera Entre Lomas S.A.
	Natural Gas (Bcf)
	Domestic			International			Entity’s share of			Combined
							equity method
							investee
Proved reserves at December 31, 2010	3,914.20			74.3			48.2			4,036.70
Revisions	(279.4	)		0.2			(4.0	)		(283.2	)
Purchases	8			—			—			8
Divestitures	(12.8	)		—			—			(12.8	)
Extensions and discoveries	769.7			9.6			11.5			790.8
Production	(416.8	)		(9.1	)		(4.7	)		(430.6	)
Proved reserves at December 31, 2011	3,982.90			75			51			4,108.90
Revisions	(404.8	)		(18.0	)		(18.5	)		(441.3	)
Purchases	5.8			—			—			5.8
Divestitures	(217.0	)		—			—			(217.0	)
Extensions and discoveries	409.2			5.7			7.4			422.3
Production	(407.0	)		(8.6	)		(4.4	)		(420.0	)
Proved reserves at December 31, 2012	3,369.10			54.1			35.5			3,458.70
Revisions	308.3			(1.7	)		(3.1	)		303.5
Divestitures	(0.2	)		—			—			(0.2	)
Extensions and discoveries	312			18.5			0.9			331.4
Production	(359.4	)		(7.1	)		(3.3	)		(369.8	)
Proved reserves at December 31, 2013	3,629.80			63.8			30			3,723.60
Proved developed reserves:
December 31, 2011	2,497.30			48.4			28.5			2,574.20
December 31, 2012	2,170.70			36.5			20.8			2,228.00
December 31, 2013	2,265.20			41.4			18.7			2,325.30
Proved undeveloped reserves:
31-Dec-11	1,485.60			26.6			22.5			1,534.70
31-Dec-12	1,198.40			17.6			14.7			1,230.70
31-Dec-13	1,364.60			22.4			11.3			1,398.30
	Oil (MMBbls)
	Domestic			International			Entity’s share of			Combined
							equity method
							investee
Proved reserves at December 31, 2010	24.3			11.9			13.4			49.6
Revisions	1.2			(0.7	)		(0.9	)		(0.4	)
Extensions and discoveries	24.3			1.5			1.3			27.1
Production	(2.7	)		(1.4	)		(1.6	)		(5.7	)
Proved reserves at December 31, 2011	47.1			11.3			12.2			70.6
Revisions	5.6			(1.1	)		(1.1	)		3.4
Divestitures	(0.3	)		—			—			(0.3	)
Extensions and discoveries	28.5			2.1			1.1			31.7
Production	(4.4	)		(1.5	)		(1.6	)		(7.5	)
Proved reserves at December 31, 2012	76.5			10.8			10.6			97.9
Revisions	3.5			(1.6	)		(0.8	)		1.1
Extensions and discoveries	28.8			0.9			—			29.7
Production	(5.9	)		(1.4	)		(1.5	)		(8.8	)
Proved reserves at December 31, 2013	102.9			8.7			8.3			119.9
Proved developed reserves:
December 31, 2011	13.6			6.8			7.6			28
December 31, 2012	23.7			6.1			6.4			36.2
December 31, 2013	36.8			5.2			5.3			47.3
Proved undeveloped reserves:
31-Dec-11	33.5			4.5			4.6			42.6
31-Dec-12	52.8			4.7			4.2			61.7
31-Dec-13	66.1			3.5			3			72.6
	NGLs (MMBbls)
	Domestic			International			Entity’s share			Combined
							of equity method
							investee
Proved reserves at December 31, 2010	95.8			1			1.1			97.9
Revisions	23			(0.1	)		(0.1	)		22.8
Purchases	0.3			—			—			0.3
Extensions and discoveries	25			—			—			25
Production	(10.1	)		(0.1	)		(0.1	)		(10.3	)
Proved reserves at December 31, 2011	134			0.8			0.9			135.7
Revisions	(21.1	)		—			—			(21.1	)
Divestitures	(1.0	)		—			—			(1.0	)
Extensions and discoveries	8.9			—			—			8.9
Production	(10.4	)		(0.1	)		(0.1	)		(10.6	)
Proved reserves at December 31, 2012	110.4			0.7			0.8			111.9
Revisions	(25.4	)		—			—			(25.4	)
Extensions and discoveries	8.1			0.1			—			8.2
Production	(7.4	)		(0.1	)		(0.1	)		(7.6	)
Proved reserves at December 31, 2013	85.7			0.7			0.7			87.1
Proved developed reserves:
December 31, 2011	72.1			0.6			0.6			73.3
December 31, 2012	64.9			0.5			0.6			66
December 31, 2013	48.6			0.5			0.5			49.6
Proved undeveloped reserves:
31-Dec-11	61.9			0.2			0.3			62.4
31-Dec-12	45.5			0.2			0.2			45.9
31-Dec-13	37.1			0.2			0.2			37.5
	All products (Bcfe) (a)
	Domestic			International			Entity’s share			Combined
							of equity method
							investee
Proved reserves at December 31, 2010	4,635.00			151.4			135.2			4,921.60
Revisions	(134.3	)		(4.6	)		(10.0	)		(148.9	)
Purchases	9.9			—			—			9.9
Divestitures	(12.8	)		—			—			(12.8	)
Extensions and discoveries	1,065.50			18.6			19.3			1,103.40
Production	(493.2	)		(18.2	)		(14.9	)		(526.3	)
Proved reserves at December 31, 2011	5,070.10			147.2			129.6			5,346.90
Revisions	(498.6	)		(24.7	)		(25.1	)		(548.4	)
Purchases	5.8			—			—			5.8
Divestitures	(224.8	)		—			—			(224.8	)
Extensions and discoveries	633.8			18.3			14			666.1
Production	(495.8	)		(18.0	)		(14.6	)		(528.4	)
Proved reserves at December 31, 2012	4,490.50			122.8			103.9			4,717.20
Revisions	177.2			(11.3	)		(7.9	)		158
Divestitures	(0.5	)		—			—			(0.5	)
Extensions and discoveries	533.8			24.5			0.9			559.2
Production	(439.4	)		(16.2	)		(12.9	)		(468.5	)
Proved reserves at December 31, 2013	4,761.60			119.8			84			4,965.40
Proved developed reserves:
December 31, 2011	3,011.50			93			77.7			3,182.20
December 31, 2012	2,702.60			76.1			62.8			2,841.50
December 31, 2013	2,777.70			75.5			53.5			2,906.70
Proved undeveloped reserves:
31-Dec-11	2,058.60			54.2			51.9			2,164.70
31-Dec-12	1,787.90			46.7			41.1			1,875.70
31-Dec-13	1,983.90			44.3			30.5			2,058.70
__________
(a)	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
•	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
•	The domestic revisions in 2013 reflects 133 Bcfe related to developed reserves and 44 Bcfe related to undeveloped reserves. The domestic revisions in 2012 primarily resulted from the lower 12-month average price as compared to the 12-month average price used in 2011. The domestic revisions in 2011 primarily relate to the reclassification of reserves from proved to probable reserves attributable to locations not expected to be developed within five years.
•	Divestitures in 2012 primarily relate to the sale in 2012 of our holdings in the Barnett Shale and the Arkoma Basin (see Note 2 of Notes to Consolidated Financial Statements).
•	Domestic extensions and discoveries in 2013 reflects 127 Bcfe added for drilled locations and 407 Bcfe added for new undeveloped locations. The 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin. Domestic extensions and discoveries in 2012 reflect 225 Bcfe added for drilled locations and 405 Bcfe added for new undeveloped locations. The 2012 extensions and discoveries were primarily in the Williston Basin, Appalachian Basin and Piceance Basin. Domestic extensions and discoveries in 2011 reflect 306 Bcfe added for drilled locations and 760 Bcfe added for new undeveloped locations. The 2011 extensions and discoveries were primarily in the Piceance Basin, Appalachian Basin and Williston Basin.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves. Prices are based on the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years ended December 31, 2013, 2012 and 2011, the average domestic combined natural gas and NGL equivalent price was $3.63, $3.01 and $4.41 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2013, 2012 and 2011 was $92.16, $82.32 and $86.87 per barrel, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows
As of December 31, 2013	Domestic				International(a)				Entity’s share
									of equity method
									investee(b)
	(Millions)
Future cash inflows	$	24,547			$	866			$	733
Less:
Future production costs	12,148				360				297
Future development costs	3,789				136				109
Future income tax provisions	2,147				72				95
Future net cash flows	6,463				298				232
Less 10 percent annual discount for estimated timing of cash flows	3,499				118				85
Standardized measure of discounted future net cash inflows	$	2,964			$	180			$	147
As of December 31, 2012	Domestic				International(a)				Entity’s share
									of equity method
									investee(b)
Future cash inflows	$	18,435			$	968			$	892
Less:
Future production costs	9,836				385				356
Future development costs	3,217				136				115
Future income tax provisions	1,059				97				104
Future net cash flows	4,323				350				317
Less 10 percent annual discount for estimated timing of cash flows	(2,374		)		(136		)		(118		)
Standardized measure of discounted future net cash inflows	$	1,949			$	214			$	199
__________
(a)	Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
(b)	Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
	Domestic				International(a)				Entity’s share
									of equity method
									investee(b)
	(Millions)
31-Dec-10	$	2,814			$	198			$	186
Sales of oil and gas produced, net of operating costs	(1,194		)		(64		)		(61		)
Net change in prices and production costs	495				26				29
Extensions, discoveries and improved recovery, less estimated future costs	1,661				—				—
Development costs incurred during year	593				23				25
Changes in estimated future development costs	(750		)		(32		)		(30		)
Purchase of reserves in place, less estimated future costs	15				—				—
Sale of reserves in place, less estimated future costs	(20		)		—				—
Revisions of previous quantity estimates	(209		)		22				18
Accretion of discount	395				25				26
Net change in income taxes	(226		)		6				4
Other	17				(5		)		—
Net changes in 2011	777				1				11
31-Dec-11	$	3,591			$	199			$	197
Sales of oil and gas produced, net of operating costs	(778		)		(78		)		(78		)
Net change in prices and production costs	(3,601		)		46				49
Extensions, discoveries and improved recovery, less estimated future costs	1,154				—				—
Development costs incurred during year	333				35				35
Changes in estimated future development costs	50				(16		)		(17		)
Purchase of reserves in place, less estimated future costs	4				—				—
Sale of reserves in place, less estimated future costs	(272		)		—				—
Revisions of previous quantity estimates	(232		)		(3		)		(26		)
Accretion of discount	481				26				27
Net change in income taxes	1,194				5				12
Other	25				—				—
Net changes in 2012	(1,642		)		15				2
31-Dec-12	$	1,949			$	214			$	199
Sales of oil and gas produced, net of operating costs	(1,040		)		(77		)		(71		)
Net change in prices and production costs	1,198				(5		)		17
Extensions, discoveries and improved recovery, less estimated future costs	1,282				—				—
Development costs incurred during year	414				37				34
Changes in estimated future development costs	(736		)		(27		)		(16		)
Sale of reserves in place, less estimated future costs	(3		)		—				—
Revisions of previous quantity estimates	239				(17		)		(61		)
Accretion of discount	225				28				27
Net change in income taxes	(540		)		27				18
Other	(24		)		—				—
Net changes in 2013	1,015				(34		)		(52		)
31-Dec-13	$	2,964			$	180			$	147
__________
(a)	Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
(b)	Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.

Schedule_II_Valuation_And_Qual

Schedule II - Valuation And Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]	'
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS	'
	WPX Energy, Inc.
	SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
		Beginning		Charged			Other		Deductions				Ending
		Balance		(Credited)									Balance
				to Costs and
				Expenses
		(Millions)
	2013:00:00
	Allowance for doubtful accounts—accounts and notes receivable(a)	$	11	$	(3	)	$	—	$	(1	)		$	7
	Deferred tax asset valuation allowance(a)	19		80			3		—				102
	2012:00:00
	Allowance for doubtful accounts—accounts and notes receivable(a)	13		(2		)	—		—				11
	Deferred tax asset valuation allowance(a)	16		3			—		—				19
	2011:00:00
	Allowance for doubtful accounts—accounts and notes receivable(a)	16		(1		)	—		(2		)		13
	Deferred tax asset valuation allowance(a)	22		—			—		(6		)	(b)	16
	__________
	(a)	Deducted from related assets.
	(b)	Deferred tax asset retained by Williams.

Description_of_Business_Basis_1

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Description of Business	'
	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. WPX Energy, Inc. was formed in 2011 by The Williams Companies, Inc. (“Williams”) to effect the separation of its exploration and production business. Williams contributed to the Company its investment in certain subsidiaries related to Williams’ domestic and international exploration and production businesses, collectively referred to as the “Contribution”. The separation was completed on December 31, 2011 through a pro rata distribution of WPX common stock to Williams’ stockholders.
	Domestic includes natural gas, oil and NGL development, production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania and Wyoming in the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, Williston, San Juan, Powder River, Appalachian and Green River Basins. 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.
	The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we”, “us” or “our”.
Basis of Presentation	'
	Basis of Presentation
	These financial statements are prepared on a consolidated basis. Prior to the Contribution, the financial statements were derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the Contribution to WPX. Management believes the assumptions underlying the financial statements are reasonable. The financial statements of 2011 included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during 2011. Because a direct ownership relationship did not exist prior to the Contribution among the various entities that comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, has been shown as Williams’ net investment within stockholder’s equity in the consolidated financial statements. In connection with the Contribution, we have reflected the amounts previously presented as Williams’ net investment in excess of the par value of our common stock as additional paid-in capital. Transactions in 2011 with Williams’ other operating businesses, which generally settled monthly, are shown as changes in accounts receivable or accounts payable in the Consolidated Statements of Cash Flows for the year ended December 31, 2011. Other transactions during the period prior to separation between the Company and Williams which were not part of the notes payable to Williams have been identified in the Consolidated Statements of Equity as net transfers with Williams (see Note 3).
Discontinued operations	'
	Discontinued operations
	During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. We have reported the results of operations and financial position of the Barnett Shale and Arkoma Basin operations as discontinued operations for all periods presented.
	Additionally, see Note 11 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
	Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Principles of consolidation	'
	Principles of consolidation
	The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
Use of estimates	'
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
	Significant estimates and assumptions which impact these financials include:
	•	Impairment assessments of long-lived assets;
	•	Valuations of derivatives;
	•	Estimation of natural gas and oil reserves;
	•	Assessments of litigation-related contingencies; and
	•	Asset retirement obligations.
	These estimates are discussed further throughout these notes.
Cash and cash equivalents	'
	Cash and cash equivalents
	Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash	'
	Restricted cash
	Restricted cash of our domestic operations consists of approximately $21 million and $19 million at December 31, 2013 and 2012, respectively, primarily related to escrow accounts established as part of the settlement agreement with certain California utilities and is included in other current and noncurrent assets. Included in the separation and distribution agreement with Williams are indemnifications requiring us to pay to Williams any net asset (or receive any net liability) that result upon ultimate resolution of these matters (see Note 11). Additionally, restricted cash of our international segment consists of approximately $6 million and $9 million at December 31, 2013 and 2012, respectively, associated with various letters of credit that is also classified in other current and other noncurrent assets.
Accounts receivable	'
	Accounts receivable
	Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories	'
	Inventories
	All inventories are stated at the lower of cost or market. Our inventories consist of tubular goods and production equipment for future transfer to wells of $49 million and $42 million at December 3l, 2013 and 2012, respectively. Additionally, we have natural gas in storage related to our gas management activities of $13 million and $24 million at December 31, 2013 and 2012, respectively, and crude oil production in transit of $10 million at December 31, 2013. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recognized lower of cost or market writedowns on natural gas in storage of $1 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
Properties and equipment	'
	Properties and equipment
	Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
	Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Other capitalized costs	'
	Other capitalized costs
	Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization	'
	Depreciation, depletion and amortization
	Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis for our domestic properties or on a concession basis for our international properties. International concession reserve estimates are limited to production quantities estimated through the life of the concession. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
	Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
	Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net.
Impairment of long-lived assets	'
	Impairment of long-lived assets
	We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
	Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows.
	Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
	Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities	'
	Contingent liabilities
	Owing to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations	'
	Asset retirement obligations
	We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities	'
	Cash flows from revolving credit facilities
	Proceeds and payments related to any borrowings under our credit facilities are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities	'
	Derivative instruments and hedging activities
	We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
	We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
	The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
		Derivative Treatment	Accounting Method
		Normal purchases and normal sales exception	Accrual accounting
		Designated in a qualifying hedging relationship	Hedge accounting
		All other derivatives	Mark-to-market accounting
	We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
	For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
	For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
	Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
	•	Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;
	•	The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
	•	Realized gains and losses on all derivatives that settle financially;
	•	Realized gains and losses on derivatives held for trading purposes; and
	•	Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
	Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues	'
	Product revenues
	Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2013 and 2012 was insignificant. Additionally, natural gas revenues include $5 million, $423 million and $326 million in 2013, 2012 and 2011, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses	'
	Gas management revenues and expenses
	Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities through May 2012 included purchases and subsequent sales to Williams Partners for fuel and shrink gas (see Note 3). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
	Charges for unutilized transportation capacity included in gas management expenses were $61 million, $46 million and $35 million in 2013, 2012 and 2011, respectively.
Capitalization of interest	'
	Capitalization of interest
	We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used until June 30, 2011 was the rate charged to us by Williams through June 30, 2011, at which time our intercompany note with Williams was forgiven (see Note 3). We did not capitalize interest for the period from July 1, 2011 to mid November 2011. Beginning November 2011, we began using the weighted average rate of our long-term notes payable which were issued in November 2011 (see Note 9).
Income taxes	'
	Income taxes
	We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. Through the effective date of the spin-off, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provisions for 2011 were calculated on a separate return basis for us and our subsidiaries, except for certain adjustments. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.
Employee stock-based compensation	'
	Employee stock-based compensation
	Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
	Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
	Through the date of the spin-off, certain employees providing direct service to us participated in Williams’ common-stock-based awards plans. The plans provided for Williams’ common-stock-based awards to both employees and Williams’ non-management directors. The plans permitted the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards were granted for no consideration other than prior and future services or based on certain financial performance targets.
	Through the date of the spin-off, Williams charged us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation was also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.
	In preparation for the spin-off, Williams’ Compensation Committee determined that all outstanding Williams’ equity-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (“Pre-2006 Options”) would convert into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options were converted into options covering both Williams and WPX common stock. The number of shares underlying each award and, with respect to options, the per share exercise price of each such award has been adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of such awards.
Foreign exchange	'
	Foreign exchange
	Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Earnings (loss) per common share	'
	Earnings (loss) per common share
	Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 5).

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Summarized Results of Discontinued Operations	'
	Summarized Results of Discontinued Operations
			2012			2011
		(Millions)
	Revenues		$	28		$	118
	Income (loss) from discontinued operations before gain on sale, impairments and income taxes		$	(3	)	$	(15	)
	Gain on sale		38			—
	Impairments		—			(209		)
	Less: Provision (benefit) for income taxes		13			(82		)
	Income (loss) from discontinued operations		$	22		$	(142	)

Transactions_with_Williams_Tab

Transactions with Williams (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Summary of Transactions with Williams or its Affiliates (Including Amounts in Discontinued Operations)	'
	Below is a summary for 2011 of the transactions with Williams or its affiliates (including amounts in discontinued operations) discussed above:
		2011
		(Millions)
	Product revenues—sales of NGLs to Williams Partners	$	258
	Gas management revenues—sales of natural gas for fuel and shrink to Williams Partners and another Williams subsidiary	586
	Lease and facility operating expenses from Williams-direct employee salary and benefit costs	21
	Gathering, processing and transportation expense from services with Williams Partners:
	Gathering and processing	298
	Transportation	44
	General and administrative from Williams:
	Direct employee salary and benefit costs	111
	Charges for general and administrative services	62
	Allocated general corporate costs	62
	Other	16
	Interest expense on notes payable to Williams	96

Investment_Income_and_Other_Ta

Investment Income and Other (Tables)	12 Months Ended
	Dec. 31, 2013
Investments, Debt and Equity Securities [Abstract]	'
Investment Income	'
	Investment income
		Years Ended December 31,
		2013			2012		2011
		(Millions)
	Equity earnings- Petrolera Entre Lomas S.A.	$	19		$	26	$	20
	Equity earnings- other	4			4		4
	Impairment of equity method investment in Appalachian Basin	(20		)	—		—
	Other	2			—		2
	Total investment income and other	$	5		$	30	$	26
Investments	'
	Investments
		December 31,
		2013			2012
		(Millions)
	Petrolera Entre Lomas S.A.—40.8%	$	125		$	109
	Other	20			36
		$	145		$	145

Earnings_Loss_Per_Common_Share1

Earnings (Loss) Per Common Share from Continuing Operations (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings (Loss) Per Common Share from Continuing Operations	'
	Earnings (Loss) Per Common Share from Continuing Operations
	The following table summarizes the calculation of earnings per share.
		Years Ended December 31,
		2013				2012			2011
		(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	$	1,185			$	(245	)	$	(160	)
	Basic weighted-average shares	200.5				198.8			197.1
	Diluted weighted-average shares	200.5				198.8			197.1
	Earnings (loss) per common share from continuing operations:
	Basic	$	(5.91	)		$	(1.23	)	$	(0.81	)
	Diluted	$	(5.91	)		$	(1.23	)	$	(0.81	)
Schedule of Weighted Average Number of Shares	'
	The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidiltive due to our loss from continuing operations attributable to WPX Energy, Inc.
		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Weighted-average nonvested restricted stock units and awards	2.5			1.9			2.9
	Weighted-average stock options	1.1			1			1.2
Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Options	'
	The table below includes information related to stock options that were outstanding at December 31, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
		2013				2012
	Options excluded (millions)	0.4				1.3
	Weighted-average exercise price of options excluded	$	20.24			$	18.17
	Exercise price range of options excluded	$20.21 - $20.97				$16.46  - $20.97
	Fourth quarter weighted-average market price(a)	$	19.97			$	16.15
	__________
	(a)	Our stock began trading on the New York Stock Exchange on January 3, 2012; therefore, a fourth quarter weighted-average market price is not available for 2011.

Asset_Sales_Impairments_and_Ex1

Asset Sales, Impairments and Exploration Expenses (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Summary of Significant Gains or Losses Reflected in Impairment of Producing Properties and Costs of Acquired Unproved Reserves, Goodwill Impairment and Other-Net within Costs and Expenses	'
	The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, gain on sale, and other—net within costs and expenses. These significant adjustments are primarily associated with our domestic operations.
		Years Ended December 31,
		2013		2012		2011
		(Millions)
	Impairment of producing properties and costs of acquired unproved reserves(a)	$	1,055	$	225	$	367
	Gain on sale of Powder River Basin deep rights leasehold	$	36	$	—	$	—
	Net gain on sales of other assets	$	4	$	4	$	1
	__________
	(a)	Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
Summary of Exploration Expenses	'
	The following table presents a summary of exploration expenses.
		Years Ended December 31,
		2013		2012		2011
		(Millions)
	Geologic and geophysical costs	$	22	$	21	$	18
	Dry hole costs	7		4		13
	Unproved leasehold property impairment, amortization and expiration	402		58		95
	Total exploration expenses	$	431	$	83	$	126

Properties_and_Equipment_Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Properties and Equipment, at Cost	'
	Properties and equipment is carried at cost and consists of the following:
		Estimated		December 31,
		Useful
		Life(a)
		(Years)		2013				2012
				(Millions)
	Proved properties	(b)		$	11,476			$	11,267
	Unproved properties	(c)		423				1,156
	Gathering, processing and other facilities	15-25		225				247
	Construction in progress	(c)		382				497
	Other	Mar-40		180				172
	Total properties and equipment, at cost			12,686				13,339
	Accumulated depreciation, depletion and amortization			(5,445		)		(4,923		)
	Properties and equipment—net			$	7,241			$	8,416
	__________
	(a)	Estimated useful lives are presented as of December 31, 2013.
	(b)	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
	(c)	Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Rollforward of Asset Retirement Obligation	'
	A rollforward of our asset retirement obligations for the years ended 2013 and 2012 is presented below.
		2013				2012
		(Millions)
	Balance, January 1	$	321			$	289
	Liabilities incurred during the period	14				19
	Liabilities settled during the period	(11		)		(7		)
	Estimate revisions	17				(1		)
	Accretion expense(a)	23				21
	Balance, December 31	$	364			$	321
	Amount reflected as current	$	6			$	5
	__________
	(a)	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Accounts_Payable_and_Accrued_a1

Accounts Payable and Accrued and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Payables and Accruals [Abstract]	'
Accounts Payable	'
	Accounts Payable
		December 31,
		2013		2012
		(Millions)
	Trade	$	213	$	209
	Accrual for capital expenditures	237		126
	Royalties	130		106
	Cash overdrafts	35		34
	Other	37		34
		$	652	$	509
Accrued and Other Current Liabilities	'
	Accrued and other current liabilities
		December 31,
		2013		2012
		(Millions)
	Taxes other than income taxes	$	41	$	54
	Accrued interest	43		42
	Compensation and benefit related accruals	52		52
	Other, including other loss contingencies	54		53
		$	190	$	201

Debt_and_Banking_Arrangements_

Debt and Banking Arrangements (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt	'
	As of the indicated dates, our debt consisted of the following:
		December 31,
		2013(a)		2012 (a)
		(Millions)
	5.250% Senior Notes due 2017	$	400	$	400
	6.000% Senior Notes due 2022	1,100		1,100
	Credit facility agreement	410		—
	Apco	8		8
	Other	1		2
	Total debt	$	1,919	$	1,510
	Less: Current portion of long-term debt	3		2
	Total long-term debt	$	1,916	$	1,508
	__________
	(a)	Interest paid on debt totaled $91 million and $58 million for 2013 and 2012, respectively.

Provision_Benefit_for_Income_T1

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Provision (Benefit) for Income Taxes from Continuing Operations	'
	The provision (benefit) for income taxes from continuing operations includes:
		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Provision (benefit):
	Current:
	Federal	$	(29	)	$	48		$	49
	State	1			3			7
	Foreign	18			14			10
		(10		)	65			66
	Deferred:
	Federal	(608		)	(162		)	(139		)
	State	(51		)	(13		)	(1		)
	Foreign	14			(1		)	—
		(645		)	(176		)	(140		)
	Total provision (benefit)	$	(655	)	$	(111	)	$	(74	)
Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate	'
	Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Provision (benefit) at statutory rate	$	(646	)	$	(120	)	$	(79	)
	Increases (decreases) in taxes resulting from:
	State income taxes (net of federal benefit)	(110		)	(10		)	(5		)
	State income change in valuation allowance (net of federal benefit)	80			3			—
	Effective state income tax rate change (net of federal benefit)	(3		)	—			9
	Alternative minimum tax credits	—			11			—
	Argentina capital tax (net of federal benefit)	10			—			—
	Foreign operations	5			4			—
	Other	9			1			1
	Provision (benefit) for income taxes	$	(655	)	$	(111	)	$	(74	)
Significant Components of Deferred Tax Liabilities and Deferred Tax Assets	'
	Significant components of deferred tax liabilities and deferred tax assets are as follows:
		December 31,
		2013			2012
		(Millions)
	Deferred tax liabilities:
	Properties and equipment	$	963		$	1,652
	Other, net	36			19
	Total deferred tax liabilities	999			1,671
	Deferred tax assets:
	Accrued liabilities and other	176			176
	Alternative minimum tax credits	76			99
	Loss carryovers	89			31
	Other	21			—
	Total deferred tax assets	362			306
	Less: valuation allowance	102			19
	Total net deferred tax assets	260			287
	Net deferred tax liabilities	$	739		$	1,384

Contingent_Liabilities_and_Com1

Contingent Liabilities and Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitment Under Contracts	'
	Our commitments under these contracts as of December 31, 2013 are as follows:
		(Millions)
	2014	$	224
	2015	219
	2016	197
	2017	178
	2018	167
	Thereafter	578
	Total	$	1,563
Future Minimum Annual Rentals Under Noncancelable Operating Leases	'
	Future minimum annual rentals under noncancelable operating leases as of December 31, 2013, are payable as follows:
		(Millions)
	2014	$	58
	2015	50
	2016	29
	2017	8
	2018	7
	Thereafter	22
	Total	$	174

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Summary of Stock Option Activity and Related Information	'
	The following summary reflects stock option activity and related information for the year ended December 31, 2013.
		WPX Plan
	Stock Options	Options			Weighted-				Aggregate
					Average				Intrinsic
					Exercise				Value
					Price
		(Millions)							(Millions)
	Outstanding at December 31, 2012(a)	4.1			$	12.68			$	14
	Granted	0.4			$	14.41
	Exercised	(0.4	)		$	8.86
	Forfeited	—			$	16.46
	Expired	—			$	19.26
	Outstanding at December 31, 2013(a)	4.1			$	13.27			$	29
	Exercisable at December 31, 2013	3.2			$	12.62			$	25
	__________
	(a)	Includes approximately 344 thousand shares held by Williams’ employees at a weighted average price of $9.24 per share at December 31, 2013 and 598 thousand shares held by Williams' employees at a weighted average price of $8.48 per share at December 31, 2012.
Additional Information about Stock Options Outstanding and Exercisable	'
	The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2013.
		WPX Plan
		Stock Options Outstanding									Stock Options Exercisable
	Range of Exercise Prices	Options			Weighted-				Weighted-		Options		Weighted-		Weighted-
					Average				Average				Average		Average
					Exercise				Remaining				Exercise		Remaining
					Price				Contractual				Price		Contractual
									Life						Life
		(Millions)							(Years)		(Millions)				(Years)
	$5.50 to $6.02	0.8			$	5.95			4.5		0.8		$	5.95	4.5
	$9.08 to $11.75	0.9			$	11.34			4.3		0.9		$	11.34	4.3
	$12.00 to $15.67	1.1			$	14.45			5.4		0.7		$	14.47	2.9
	$16.46 to $20.97	1.3			$	18.17			6.4		0.8		$	18.48	5.9
	Total	4.1			$	13.27			5.3		3.2		$	12.62	4.5
Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model	'
	The estimated fair value at date of grant of options for our common stock and date of conversion for WPX awards in each respective year, using the Black-Scholes option pricing model, is as follows:
		WPX Plan
		2013				2012				2011
	Weighted-average grant date fair value of options granted	$	6.04			$	7.79			$	—
	Weighted-average conversion date fair value options granted									$	8.48
	Weighted-average assumptions:
	Dividend yield	—				—				—
	Volatility	42.8		%		43.8		%		45		%
	Risk-free interest rate	1.06		%		1.17		%		0.38		%
	Expected life (years)	6				6				2.8
Summary of Nonvested Restricted Stock Unit Activity and Related Information	'
	The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2013.
		WPX Plan
	Restricted Stock Units	Shares			Weighted-
					Average
					Fair Value(a)
		(Millions)
	Nonvested at December 31, 2012	4.8			$	16.45
	Granted	2.2			$	14.97
	Forfeited	(0.2	)		$	16.61
	Vested	(1.6	)		$	11.27
	Nonvested at December 31, 2013	5.2			$	16.97
	__________
	(a)	Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other Restricted Stock Unit Information	'
	Other restricted stock unit information
		WPX Plan								Williams Plan
		2013				2012				2011
	Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	14.97			$	17.35			$	27.74
	Total fair value of restricted stock units vested during the year (millions)	$	18			$	14			$	10

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
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.
		December 31, 2013												December 31, 2012
		Level 1			Level 2				Level 3			Total		Level 1		Level 2		Level 3		Total
					(Millions)											(Millions)
	Energy derivative assets	$	30		$	26			$	1		$	57	$	20	$	38	$	2	$	60
	Energy derivative liabilities	$	83		$	38			$	1		$	122	$	11	$	1	$	3	$	15
	Total debt(a)	$	—		$	1,945			$	—		$	1,945	$	—	$	1,617	$	—	$	1,617
	__________
	(a)	The carrying value of total debt, excluding capital leases, was $1,918 million and $1,508 million as of December 31, 2013 and 2012, respectively.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs	'
	The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
		Years ended December 31,
		2013			2012				2011
		Net Energy			Net Energy				Net Energy
		Derivatives			Derivatives				Derivatives
		(Millions)
	Beginning balance	$	(1	)	$	1			$	1
	Realized and unrealized gains (losses):
	Included in income (loss) from continuing operations	(2		)	3				15
	Included in other comprehensive income (loss)	—			—				—
	Purchases, issuances, and settlements	3			(5		)		(12		)
	Transfers out of Level 3	—			—				(3		)
	Ending balance	$	—		$	(1	)		$	1
	Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	(1	)	$	(1	)		$	1
Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy	'
	The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
		Total losses for
		the years ended December 31,
		2013					2012					2011
		(Millions)
	Impairments:
	Producing properties and costs of acquired unproved reserves (Note 6)	1,055			(a)		225				(b)	367		(c)
	Unproved leasehold	317			(a)		—					—
	Equity method investment (Note 4)	20					—					—
		$	1,392				$	225				$	367
	__________
	(a)	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million
	•	$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
	•	$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.
	•	$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
	•	$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
	•	$85 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
	(b)	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.
	•	$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
	•	$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
	(c)	As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.
	•	$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
	•	$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively

Derivatives_and_Concentration_1

Derivatives and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Volumes that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production	'
	The following table sets forth the derivative notional volumes that are economic hedges of production volumes as well as notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, both which are included in our commodity derivatives portfolio as of December 31, 2013.
	Derivatives related to production
	Commodity		Period		Contract Type(a)		Location		Notional Volume(b)			Weighted Average
												Price(c)
	Crude Oil		2014		Fixed Price Swaps		WTI		(13,243	)		$	94.82
	Crude Oil		2014		Basis Swaps		Brent		(4,463	)		$	9.64
	Natural Gas		2014		Fixed Price Swaps		Henry Hub		(315	)		$	4.19
	Natural Gas		2014		Swaptions		Henry Hub		(50	)		$	4.24
	Natural Gas		2014		Costless Collars		Henry Hub		(165	)		$ 4.01 - 4.64
	Natural Gas		2014		Basis Swaps		Northeast		(23	)		$	0.09
	Natural Gas		2014		Basis Swaps		MidCon		(39	)		$	(0.18	)
	Natural Gas		2014		Basis Swaps		Rockies		(78	)		$	(0.18	)
	Natural Gas		2014		Basis Swaps		West		(27	)		$	0.08
	NGL - Ethane		2014		Fixed Price Swaps		Mont Belvieu		(986	)		$	0.28
	NGL - Natural Gasoline		2014		Fixed Price Swaps		Mont Belvieu		(822	)		$	2.05
	Crude Oil		2015		Swaptions		WTI		(1,750	)		$	98.54
	Natural Gas		2015		Fixed Price Swaps		Henry Hub		(35	)		$	4.38
	Natural Gas		2015		Swaptions		Henry Hub		(35	)		$	4.38
	Derivatives primarily related to storage and transportation
	Commodity		Period		Contract Type(d)		Location(e)		Notional Volume(b)			Weighted Average
												Price(f)
	Natural Gas		2014		Fixed Price Swaps		Multiple		(11	)		—
	Natural Gas		2014		Basis Swaps		Multiple		(31	)		—
	Natural Gas		2014		Index		Multiple		(107	)		—
	Natural Gas Liquids		2014		Fixed Price Swaps		Multiple		(822	)		—
	Natural Gas		2015		Basis Swaps		Multiple		(6	)		—
	Natural Gas		2015		Index		Multiple		(43	)		—
	Natural Gas		2016		Index		Multiple		2			—
	Natural Gas		2017		Index		Multiple		2			—
	__________
	(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.
	(d)	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.
	(e)	WPX Marketing transacts at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
	(f)	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.
		December 31,
		2013								2012
		Assets				Liabilities				Assets				Liabilities
		(Millions)
	Derivatives related to production designated as hedging instruments	$	—			$	—			$	5			$	—
	Not designated as hedging instruments:
	Derivatives related to production not designated as hedging instruments	26				39				33				—
	Derivatives related to physical marketing agreements not designated as hedging instruments	31				83				20				13
	Legacy natural gas contracts from former power business	—				—				2				2
	Total derivatives not designated as hedging instruments	57				122				55				15
	Total derivatives	$	57			$	122			$	60			$	15
Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues	'
	The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (“AOCI”) or revenues.
		Years Ended								Classification
		December 31,
		2013				2012
		(Millions)
	Net gain recognized in other comprehensive income (loss) (effective portion)	$	—			$	90			AOCI
	Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	5			$	434			Revenues
	__________
	(a)	Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
Gross And Net Derivative Asset and Liability	'
	The following table presents our gross and net derivative assets and liabilities.
		Gross Amount Presented on Balance Sheet				Netting Adjustments (a)				Cash Collateral Posted(Received)				Net Amount
	31-Dec-13	(Millions)
	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	)
	31-Dec-12
	Derivative assets with right of offset or master netting agreements	$	60			$	(10	)		$	(2	)		$	48
	Derivative liabilities with right of offset or master netting agreements	$	(15	)		$	10			$	—			$	(5	)
	__________
	(a)	With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Concentration of Receivables, Net of Allowances, by Product or Service	'
	The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:
		2013				2012
		(Millions)
	Receivables by product or service:
	Sale of natural gas and related products and services	$	339			$	289
	Joint interest owners	186				138
	Other	11				16
	Total	$	536			$	443
Gross and Net Credit Exposure from Derivative Contracts	'
	The gross and net credit exposure from our derivative contracts as of December 31, 2013, is summarized as follows:
	Counterparty Type	Gross  Investment			Gross Total				Net			Net Total
		Grade(a)							Investment
									Grade(a)
		(Millions)
	Financial institutions	57			57				7			7
	Credit reserves				—							—
	Credit exposure from derivatives				$	57						$	7
	__________
	(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)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Reconciliation of Segment Revenues and Segment Operating Income (Loss) to Revenues and 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. Long-lived assets are comprised of gross property, plant and equipment and long-term investments.
	For the year ended December 31, 2013	Domestic			International		Total
					(Millions)
	Total revenues	$	2,609		$	152	$	2,761
	Costs and expenses:
	Lease and facility operating	$	271		$	37	$	308
	Gathering, processing and transportation	430			3		433
	Taxes other than income	117			24		141
	Gas management, including charges for unutilized pipeline capacity	931			—		931
	Exploration	424			7		431
	Depreciation, depletion and amortization	906			34		940
	Impairment of producing properties and costs of acquired unproved reserves	1,052			3		1,055
	Gain on sale of Powder River Basin deep rights leasehold	(36		)	—		(36		)
	General and administrative	275			14		289
	Other—net	17			—		17
	Total costs and expenses	$	4,387		$	122	$	4,509
	Operating income (loss)	$	(1,778	)	$	30	$	(1,748	)
	Interest expense	(108		)	—		(108		)
	Interest capitalized	5			—		5
	Investment income, impairment of equity method investment and other	(16		)	21		5
	Income (loss) from continuing operations before income taxes	$	(1,897	)	$	51	$	(1,846	)
	Other financial information:
	Net capital expenditures	$	1,103		$	51	$	1,154
	Total assets	$	8,046		$	383	$	8,429
	Long—lived assets	$	12,346		$	485	$	12,831
	For the year ended December 31, 2012
	Total revenues	$	3,052		$	137	$	3,189
	Costs and expenses:
	Lease and facility operating	$	251		$	32	$	283
	Gathering, processing and transportation	504			2		506
	Taxes other than income	87			24		111
	Gas management, including charges for unutilized pipeline capacity	996			—		996
	Exploration	72			11		83
	Depreciation, depletion and amortization	939			27		966
	Impairment of producing properties and costs of acquired unproved reserves	225			—		225
	General and administrative	273			14		287
	Other—net	12			—		12
	Total costs and expenses	$	3,359		$	110	$	3,469
	Operating income (loss)	$	(307	)	$	27	$	(280	)
	Interest expense	(102		)	—		(102		)
	Interest capitalized	8			—		8
	Investment income and other	3			27		30
	Income (loss) from continuing operations before income taxes	$	(398	)	$	54	$	(344	)
	Other financial information:
	Net capital expenditures	$	1,463		$	58	$	1,521
	Total assets	$	9,113		$	343	$	9,456
	Long-lived assets	$	13,056		$	428	$	13,484
	For the year ended December 31, 2011	Domestic			International		Total
					(Millions)
	Total revenues	$	3,772		$	110	$	3,882
	Costs and expenses:
	Lease and facility operating	$	235		$	27	$	262
	Gathering, processing and transportation	487			—		487
	Taxes other than income	113			21		134
	Gas management, including charges for unutilized pipeline capacity	1,471			—		1,471
	Exploration	123			3		126
	Depreciation, depletion and amortization	880			22		902
	Impairment of producing properties and costs of acquired unproved reserves	367			—		367
	General and administrative	263			12		275
	Other—net	(3		)	3		—
	Total costs and expenses	$	3,936		$	88	$	4,024
	Operating income (loss)	$	(164	)	$	22	$	(142	)
	Interest expense	(117		)	—		(117		)
Interest capitalized	9			—		9
Investment income and other	6			20		26
Income (loss) from continuing operations before income taxes	$	(266	)	$	42	$	(224	)
Other financial information:
Net capital expenditures	$	1,531		$	41	$	1,572
Total assets	$	10,144		$	288	$	10,432
Long—lived assets	$	11,969		$	354	$	12,323

Quarterly_Financial_Data_Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Summarized Quarterly Financial Data	'
	Summarized quarterly financial data are as follows:
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(Millions, except per-share amounts)
	2013
	Revenues	$	631		$	815		$	658		$	657
	Operating costs and expenses	710			689			687			1,098
	Income (loss) from continuing operations	(113		)	22			(116		)	(984		)
	Net income (loss)	(113		)	22			(116		)	(984		)
	Amounts attributable to WPX Energy, Inc.:
	Net income (loss)	(116		)	18			(114		)	(973		)
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)
	2012
	Revenues	$	910		$	775		$	677		$	827
	Operating costs and expenses	834			673			680			758
	Income (loss) from continuing operations	(38		)	(29		)	(63		)	(103		)
	Net income (loss)	(40		)	(6		)	(61		)	(104		)
	Amounts attributable to WPX Energy, Inc.:
	Net income (loss)	(43		)	(10		)	(64		)	(106		)
	Basic and diluted earnings (loss) per common share:
	Income (loss) from continuing operations	$	(0.21	)	$	(0.17	)	$	(0.33	)	$	(0.53	)

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Capitalized Costs	'
	Capitalized Costs
		As of December 31, 2013
		Domestic				International				Consolidated			Entity’s share of
										Total			equity method
													investee
		(Millions)
	Proved Properties	$	11,349			$	350			$	11,699		$	330
	Unproved properties	414				9				423			2
		11,763				359				12,122			332
	Accumulated depreciation, depletion and amortization and valuation provisions	(5,070		)		(194		)		(5,264		)	(195		)
	Net capitalized costs	$	6,693			$	165			$	6,858		$	137
		As of December 31, 2012
		Domestic				International				Consolidated			Entity’s share of
										Total			equity method
													investee
		(Millions)
	Proved Properties	$	11,295			$	310			$	11,605		$	292
	Unproved properties	1,153				9				1,162			1
		12,448				319				12,767			293
	Accumulated depreciation, depletion and amortization and valuation provisions	(4,612		)		(161		)		(4,773		)	(181		)
	Net capitalized costs	$	7,836			$	158			$	7,994		$	112
Cost Incurred	'
	Cost Incurred
		Domestic				International				Entity’s share of
										equity method
										investee
		(Millions)
	For the Year Ended December 31, 2013
	Acquisition	$	57			$	—			$	—
	Exploration	104				16				3
	Development	939				36				34
		$	1,100			$	52			$	37
	For the Year Ended December 31, 2012
	Acquisition	$	111			$	—			$	—
	Exploration	23				31				5
	Development	1,130				35				35
		$	1,264			$	66			$	40
	For the Year Ended December 31, 2011
	Acquisition	$	45			$	—			$	—
	Exploration	31				20				8
	Development	1,461				24				26
		$	1,537			$	44			$	34
Results of Operations	'
	Results of Operations
		Domestic				International				Total
		(Millions)
	For the Year Ended December 31, 2013
	Revenues:
	Natural gas sales	$	1,074			$	19			$	1,093
	Oil and condensate sales	534				115				649
	Natural gas liquid sales	228				2				230
	Net gain (loss) on derivatives not designated as hedges	(57		)		—				(57		)
	Other revenues	6				16				22
	Total revenues	1,785				152				1,937
	Costs:
	Lease and facility operating	271				37				308
	Gathering, processing and transportation	430				3				433
	Taxes other than income	117				24				141
	Exploration	424				7				431
	Depreciation, depletion and amortization	906				34				940
	Impairment of certain natural gas properties primarily in the Appalachian and Powder River Basins	899				3				902
	Impairment of costs of acquired unproved reserves	153				—				153
	Gain on sale of Powder River deep rights leasehold	(36		)		—				(36		)
	General and administrative	268				14				282
	Other (income) expense	17				—				17
	Total costs	3,449				122				3,571
	Results of operations	(1,664		)		30				(1,634		)
	Provision (benefit) for income taxes	(621		)		11				(610		)
	Exploration and production net income (loss)	$	(1,043	)		$	19			$	(1,024	)
		Domestic				International				Total
		(Millions)
	For the Year Ended December 31, 2012
	Revenues:
	Natural gas sales	$	1,346			$	18			$	1,364
	Oil and condensate sales	376				115				491
	Natural gas liquid sales	296				3				299
	Net gain on derivatives not designated as hedges	66				—				66
	Other revenues	7				1				8
	Total revenues	2,091				137				2,228
	Costs:
	Lease and facility operating	251				32				283
	Gathering, processing and transportation	504				2				506
	Taxes other than income	87				24				111
	Exploration	72				11				83
	Depreciation, depletion and amortization	939				27				966
	Impairment of certain natural gas properties in the Green River Basin	48				—				48
	Impairment of costs of acquired unproved reserves	177				—				177
	General and administrative	267				14				281
	Other (income) expense	14				—				14
	Total costs	2,359				110				2,469
	Results of operations	(268		)		27				(241		)
	Provision (benefit) for income taxes	(98		)		10				(88		)
	Exploration and production net income (loss)	$	(170	)		$	17			$	(153	)
		Domestic				International				Total
		(Millions)
	For the Year Ended December 31, 2011
	Revenues:
	Natural gas sales	$	1,678			$	16			$	1,694
	Oil and condensate sales	226				86				312
	Natural gas liquid sales	404				4				408
	Other revenues	7				4				11
	Total revenues	2,315				110				2,425
	Costs:
	Lease and facility operating	235				27				262
	Gathering, processing and transportation	487				—				487
	Taxes other than income	113				21				134
Exploration	123				3				126
Depreciation, depletion and amortization	880				22				902
Impairment of certain natural gas properties in the Powder River Basin	276				—				276
Impairment of costs of acquired unproved reserves	91				—				91
General and administrative	246				12				258
Other (income) expense	(3		)		3				—
Total costs	2,448				88				2,536
Results of operations	(133		)		22				(111		)
Provision (benefit) for income taxes	(49		)		8				(41		)
Exploration and production net income (loss)	$	(84	)		$	14			$	(70	)
Proved Reserves	'
		Natural Gas (Bcf)
		Domestic			International			Entity’s share of			Combined
								equity method
								investee
	Proved reserves at December 31, 2010	3,914.20			74.3			48.2			4,036.70
	Revisions	(279.4	)		0.2			(4.0	)		(283.2	)
	Purchases	8			—			—			8
	Divestitures	(12.8	)		—			—			(12.8	)
	Extensions and discoveries	769.7			9.6			11.5			790.8
	Production	(416.8	)		(9.1	)		(4.7	)		(430.6	)
	Proved reserves at December 31, 2011	3,982.90			75			51			4,108.90
	Revisions	(404.8	)		(18.0	)		(18.5	)		(441.3	)
	Purchases	5.8			—			—			5.8
	Divestitures	(217.0	)		—			—			(217.0	)
	Extensions and discoveries	409.2			5.7			7.4			422.3
	Production	(407.0	)		(8.6	)		(4.4	)		(420.0	)
	Proved reserves at December 31, 2012	3,369.10			54.1			35.5			3,458.70
	Revisions	308.3			(1.7	)		(3.1	)		303.5
	Divestitures	(0.2	)		—			—			(0.2	)
	Extensions and discoveries	312			18.5			0.9			331.4
	Production	(359.4	)		(7.1	)		(3.3	)		(369.8	)
	Proved reserves at December 31, 2013	3,629.80			63.8			30			3,723.60
	Proved developed reserves:
	December 31, 2011	2,497.30			48.4			28.5			2,574.20
	December 31, 2012	2,170.70			36.5			20.8			2,228.00
	December 31, 2013	2,265.20			41.4			18.7			2,325.30
	Proved undeveloped reserves:
	31-Dec-11	1,485.60			26.6			22.5			1,534.70
	31-Dec-12	1,198.40			17.6			14.7			1,230.70
	31-Dec-13	1,364.60			22.4			11.3			1,398.30
		Oil (MMBbls)
		Domestic			International			Entity’s share of			Combined
								equity method
								investee
	Proved reserves at December 31, 2010	24.3			11.9			13.4			49.6
	Revisions	1.2			(0.7	)		(0.9	)		(0.4	)
	Extensions and discoveries	24.3			1.5			1.3			27.1
	Production	(2.7	)		(1.4	)		(1.6	)		(5.7	)
	Proved reserves at December 31, 2011	47.1			11.3			12.2			70.6
	Revisions	5.6			(1.1	)		(1.1	)		3.4
	Divestitures	(0.3	)		—			—			(0.3	)
	Extensions and discoveries	28.5			2.1			1.1			31.7
	Production	(4.4	)		(1.5	)		(1.6	)		(7.5	)
	Proved reserves at December 31, 2012	76.5			10.8			10.6			97.9
	Revisions	3.5			(1.6	)		(0.8	)		1.1
	Extensions and discoveries	28.8			0.9			—			29.7
	Production	(5.9	)		(1.4	)		(1.5	)		(8.8	)
	Proved reserves at December 31, 2013	102.9			8.7			8.3			119.9
	Proved developed reserves:
	December 31, 2011	13.6			6.8			7.6			28
	December 31, 2012	23.7			6.1			6.4			36.2
	December 31, 2013	36.8			5.2			5.3			47.3
	Proved undeveloped reserves:
	31-Dec-11	33.5			4.5			4.6			42.6
	31-Dec-12	52.8			4.7			4.2			61.7
	31-Dec-13	66.1			3.5			3			72.6
		NGLs (MMBbls)
		Domestic			International			Entity’s share			Combined
								of equity method
								investee
	Proved reserves at December 31, 2010	95.8			1			1.1			97.9
	Revisions	23			(0.1	)		(0.1	)		22.8
	Purchases	0.3			—			—			0.3
Extensions and discoveries	25			—			—			25
Production	(10.1	)		(0.1	)		(0.1	)		(10.3	)
Proved reserves at December 31, 2011	134			0.8			0.9			135.7
Revisions	(21.1	)		—			—			(21.1	)
Divestitures	(1.0	)		—			—			(1.0	)
Extensions and discoveries	8.9			—			—			8.9
Production	(10.4	)		(0.1	)		(0.1	)		(10.6	)
Proved reserves at December 31, 2012	110.4			0.7			0.8			111.9
Revisions	(25.4	)		—			—			(25.4	)
Extensions and discoveries	8.1			0.1			—			8.2
Production	(7.4	)		(0.1	)		(0.1	)		(7.6	)
Proved reserves at December 31, 2013	85.7			0.7			0.7			87.1
Proved developed reserves:
December 31, 2011	72.1			0.6			0.6			73.3
December 31, 2012	64.9			0.5			0.6			66
December 31, 2013	48.6			0.5			0.5			49.6
Proved undeveloped reserves:
31-Dec-11	61.9			0.2			0.3			62.4
31-Dec-12	45.5			0.2			0.2			45.9
31-Dec-13	37.1			0.2			0.2			37.5
	All products (Bcfe) (a)
	Domestic			International			Entity’s share			Combined
							of equity method
							investee
Proved reserves at December 31, 2010	4,635.00			151.4			135.2			4,921.60
Revisions	(134.3	)		(4.6	)		(10.0	)		(148.9	)
Purchases	9.9			—			—			9.9
Divestitures	(12.8	)		—			—			(12.8	)
Extensions and discoveries	1,065.50			18.6			19.3			1,103.40
Production	(493.2	)		(18.2	)		(14.9	)		(526.3	)
Proved reserves at December 31, 2011	5,070.10			147.2			129.6			5,346.90
Revisions	(498.6	)		(24.7	)		(25.1	)		(548.4	)
Purchases	5.8			—			—			5.8
Divestitures	(224.8	)		—			—			(224.8	)
Extensions and discoveries	633.8			18.3			14			666.1
Production	(495.8	)		(18.0	)		(14.6	)		(528.4	)
Proved reserves at December 31, 2012	4,490.50			122.8			103.9			4,717.20
Revisions	177.2			(11.3	)		(7.9	)		158
Divestitures	(0.5	)		—			—			(0.5	)
Extensions and discoveries	533.8			24.5			0.9			559.2
Production	(439.4	)		(16.2	)		(12.9	)		(468.5	)
Proved reserves at December 31, 2013	4,761.60			119.8			84			4,965.40
Proved developed reserves:
December 31, 2011	3,011.50			93			77.7			3,182.20
December 31, 2012	2,702.60			76.1			62.8			2,841.50
December 31, 2013	2,777.70			75.5			53.5			2,906.70
Proved undeveloped reserves:
31-Dec-11	2,058.60			54.2			51.9			2,164.70
31-Dec-12	1,787.90			46.7			41.1			1,875.70
31-Dec-13	1,983.90			44.3			30.5			2,058.70
__________
(a)	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
Standardized Measure of Discounted Future Net Cash Flows	'
	Standardized Measure of Discounted Future Net Cash Flows
	As of December 31, 2013	Domestic				International(a)				Entity’s share
										of equity method
										investee(b)
		(Millions)
	Future cash inflows	$	24,547			$	866			$	733
	Less:
	Future production costs	12,148				360				297
	Future development costs	3,789				136				109
	Future income tax provisions	2,147				72				95
	Future net cash flows	6,463				298				232
	Less 10 percent annual discount for estimated timing of cash flows	3,499				118				85
	Standardized measure of discounted future net cash inflows	$	2,964			$	180			$	147
	As of December 31, 2012	Domestic				International(a)				Entity’s share
										of equity method
										investee(b)
	Future cash inflows	$	18,435			$	968			$	892
	Less:
	Future production costs	9,836				385				356
	Future development costs	3,217				136				115
	Future income tax provisions	1,059				97				104
	Future net cash flows	4,323				350				317
	Less 10 percent annual discount for estimated timing of cash flows	(2,374		)		(136		)		(118		)
	Standardized measure of discounted future net cash inflows	$	1,949			$	214			$	199
	__________
	(a)	Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
	(b)	Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows	'
	Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
		Domestic				International(a)				Entity’s share
										of equity method
										investee(b)
		(Millions)
	31-Dec-10	$	2,814			$	198			$	186
	Sales of oil and gas produced, net of operating costs	(1,194		)		(64		)		(61		)
	Net change in prices and production costs	495				26				29
	Extensions, discoveries and improved recovery, less estimated future costs	1,661				—				—
	Development costs incurred during year	593				23				25
	Changes in estimated future development costs	(750		)		(32		)		(30		)
	Purchase of reserves in place, less estimated future costs	15				—				—
	Sale of reserves in place, less estimated future costs	(20		)		—				—
	Revisions of previous quantity estimates	(209		)		22				18
	Accretion of discount	395				25				26
	Net change in income taxes	(226		)		6				4
	Other	17				(5		)		—
	Net changes in 2011	777				1				11
	31-Dec-11	$	3,591			$	199			$	197
	Sales of oil and gas produced, net of operating costs	(778		)		(78		)		(78		)
	Net change in prices and production costs	(3,601		)		46				49
	Extensions, discoveries and improved recovery, less estimated future costs	1,154				—				—
	Development costs incurred during year	333				35				35
	Changes in estimated future development costs	50				(16		)		(17		)
	Purchase of reserves in place, less estimated future costs	4				—				—
	Sale of reserves in place, less estimated future costs	(272		)		—				—
	Revisions of previous quantity estimates	(232		)		(3		)		(26		)
	Accretion of discount	481				26				27
	Net change in income taxes	1,194				5				12
	Other	25				—				—
	Net changes in 2012	(1,642		)		15				2
	31-Dec-12	$	1,949			$	214			$	199
	Sales of oil and gas produced, net of operating costs	(1,040		)		(77		)		(71		)
	Net change in prices and production costs	1,198				(5		)		17
	Extensions, discoveries and improved recovery, less estimated future costs	1,282				—				—
	Development costs incurred during year	414				37				34
	Changes in estimated future development costs	(736		)		(27		)		(16		)
	Sale of reserves in place, less estimated future costs	(3		)		—				—
	Revisions of previous quantity estimates	239				(17		)		(61		)
	Accretion of discount	225				28				27
	Net change in income taxes	(540		)		27				18
	Other	(24		)		—				—
	Net changes in 2013	1,015				(34		)		(52		)
	31-Dec-13	$	2,964			$	180			$	147
	__________
	(a)	Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
	(b)	Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.

Description_of_Business_Basis_2

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Line Items]	'	'	'
Share Based Compensation Arrangement By Share Based Payment Award Minimum Exercisable Period For Stock Options	'3 years	'	'
Material Supplies And Other	$49	$42	'
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Minimum	20.00%	'	'
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Maximum	50.00%	'	'
Natural gas in storage	13	24	'
Crude inventory in transit	10	'	'
Hedge gains realized from natural gas revenues	5	423	326
Charges for unutilized transportation capacity included in gas management expenses	61	46	35
Projects with construction periods, minimum	'3 months	'	'
Total estimated project cost	1	'	'
Share Based Compensation Arrangement By Share Based Payment Award Award Term	'10 years	'	'
Natural Gas	'	'	'
Accounting Policies [Line Items]	'	'	'
Inventory writedowns	1	11	10
Domestic Segment	'	'	'
Accounting Policies [Line Items]	'	'	'
Restricted cash related to escrow accounts to settle agreement	21	19	'
International Segment	'	'	'
Accounting Policies [Line Items]	'	'	'
Restricted cash related to letters of credit	$6	$9	'

Discontinued_Operations_Additi

Discontinued Operations - Additional Information (Detail) (USD $)	12 Months Ended		3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2011
			Barnett Shale	Barnett Shale	Arkoma Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'
Proceeds from divestiture	'	'	$306	'	'
Impairments	$0	$209	'	$180	$29

Discontinued_Operations_Summar

Discontinued Operations - Summarized Results of Discontinued Operations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Revenues	'	$28	$118
Income (loss) from discontinued operations before impairments, gain on sale and income taxes	'	-3	-15
Impairments	'	0	-209
Less: Provision (benefit) for income taxes	'	13	-82
Income (loss) from discontinued operations	0	22	-142
Discontinued Operations	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Gain on sale	'	$38	$0

Transactions_with_Williams_Add

Transactions with Williams - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended			12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 25, 2011	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2011
				Williams	Williams	Williams	Williams	Williams	Williams	Williams	Stock Conversion
						administrative_service_entity		Unsecured Promissory Note	Unsecured Promissory Note	Reimbursements
Related Party Transaction [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Contribution and recapitalization of common stock held by Williams	'	'	'	'	'	'	'	'	'	'	197
Services to be provided by related party pursuant to transaction services agreement, after spin-off, period	'	'	'	'	'1 year	'	'	'	'	'	'
Number of administrative service entities that executed service agreements with payroll companies	'	'	'	'	'	2	'	'	'	'	'
Commitments for pipeline transportation for both oil and gas sales and gas management activities	'	'	'	'	'	'	$401	'	'	'	'
Reimbursement of transportation cost	891	949	1,428	'	'	'	586	'	'	11	'
Amount due to related party at the time of cancellation of notes	'	'	'	'	'	'	'	162	2,400	'	'
Interest rate on notes payable	'	'	'	'	'	'	'	'	8.08%	'	'
Lease term for headquarters office	'	'	'	'10 years 6 months	'	'	'	'	'	'	'
Annual rent payable under lease	'	'	'	$4	'	'	'	'	'	'	'

Transactions_with_Williams_Sum

Transactions with Williams - Summary of Transaction with Williams or its Affiliates (Including Amounts in Discontinued Operations) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Gas management revenues—sales of natural gas for fuel and shrink to Williams Partners and another Williams subsidiary	$891	$949	$1,428
Charges for general and administrative services	289	287	275
Williams	'	'	'
Related Party Transaction [Line Items]	'	'	'
Product revenues—sales of NGLs to Williams Partners	'	'	258
Gas management revenues—sales of natural gas for fuel and shrink to Williams Partners and another Williams subsidiary	'	'	586
Lease and facility operating expenses from Williams-direct employee salary and benefit costs	'	'	21
Gathering and processing	'	'	298
Transportation	'	'	44
Direct employee salary and benefit costs	'	'	111
Charges for general and administrative services	'	'	62
Allocated general corporate costs	'	'	62
Other	'	'	16
Interest expense on notes payable to Williams	'	'	$96

Investment_Income_and_Other_In

Investment Income and Other - Investment Income (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Investment Income, Reported Amounts, by Category [Line Items]	'	'	'
Total investment income and other	$5	$30	$26
Equity Earnings Petrolera Entre Lomas S.A.	'	'	'
Schedule of Investment Income, Reported Amounts, by Category [Line Items]	'	'	'
Total investment income and other	19	26	20
Equity earnings	'	'	'
Schedule of Investment Income, Reported Amounts, by Category [Line Items]	'	'	'
Total investment income and other	4	4	4
Impairment of Equity Method Investment in Appalachian Basin	'	'	'
Schedule of Investment Income, Reported Amounts, by Category [Line Items]	'	'	'
Total investment income and other	-20	0	0
Other	'	'	'
Schedule of Investment Income, Reported Amounts, by Category [Line Items]	'	'	'
Total investment income and other	$2	$0	$2

Investment_Income_and_Other_In1

Investment Income and Other - Investments (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Investment [Line Items]	'	'
Investment	$145	$145
Petrolera Entre Lomas S.A 40.8%	'	'
Investment [Line Items]	'	'
Investment	125	109
Equity method ownership percentage	40.80%	40.80%
Other	'	'
Investment [Line Items]	'	'
Investment	$20	$36

Investment_Income_and_Other_Ad

Investment Income and Other - Additional Information (Detail) (Equity Method Investments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity Method Investments	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Dividends and distributions received	$7	$12	$17

Earnings_Loss_Per_Common_Share2

Earnings (Loss) Per Common Share from Continuing Operations (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	($984)	($116)	$22	($113)	($103)	($63)	($29)	($38)	$1,185	($245)	($160)
Basic weighted-average shares	'	'	'	'	'	'	'	'	200.5	198.8	197.1
Diluted weighted-average shares	'	'	'	'	'	'	'	'	200.5	198.8	197.1
Earnings (loss) per common share from continuing operations:	'	'	'	'	'	'	'	'	'	'	'
Basic (in dollars per share)	'	'	'	'	'	'	'	'	($5.91)	($1.23)	($0.81)
Diluted (in dollars per share)	'	'	'	'	'	'	'	'	($5.91)	($1.23)	($0.81)

Earnings_Loss_Per_Common_Share3

Earnings (Loss) Per Common Share from Continuing Operations - Additional information (Detail)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Computation Of Earnings Per Share Line Items	'	'	'
Common stock distributed to William's shareholders in conjunction with spin-off	'	'	197.1
Restricted Stock Units	'	'	'
Computation Of Earnings Per Share Line Items	'	'	'
Weighted-average shares excluded from the computation of diluted earnings per common share	2.5	1.9	2.9
Stock Options	'	'	'
Computation Of Earnings Per Share Line Items	'	'	'
Weighted-average shares excluded from the computation of diluted earnings per common share	1.1	1	1.2

Earnings_Loss_Per_Common_Share4

Earnings (Loss) Per Common Share from Continuing Operations - Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Option (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Disclosure Stock Options Outstanding Excluded From Computation Of Weighted Average Stock Option [Abstract]	'		'
Options excluded	0.4		1.3
Weighted-average exercise price of options excluded	$20.24		$18.17
Exercise price range of options excluded, lower limit	$20.21		$16.46
Exercise price range of options excluded, upper limit	$20.97		$20.97
Fourth quarter weighted-average market price	$19.97	[1]	$16.15	[1]
[1]	Our stock began trading on the New York Stock Exchange on January 3, 2012; therefore, a fourth quarter weighted-average market price is not available for 2011.

Asset_Sales_Impairments_and_Ex2

Asset Sales, Impairments and Exploration Expenses - Significant Adjustments with Domestic Operations (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Extractive Industries [Abstract]	'	'		'		'
Impairment of producing properties and costs of acquired unproved reserves (Note 6)	$108	$1,055	[1],[2]	$225	[1],[3]	$367	[1],[4]
Gain on sale of Powder River Basin deep rights leasehold	'	36		0		0
Net gain on sales of other assets	'	$4		$4		$1
[1]	Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
[2]	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
[3]	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
[4]	As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Asset_Sales_Impairments_and_Ex3

Asset Sales, Impairments and Exploration Expenses (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Oct. 31, 2013

Dec. 31, 2013

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Marcellus Shale

Appalachian Basin

Appalachian Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Piceance

Piceance

Kokopelli area of Piceance Basin

Kokopelli area of Piceance Basin

Columbia

Green River Basin

Columbia County, Pennsylvania

Impairment of Equity Method Investment in Appalachian Basin [Member]

Impairment of Equity Method Investment in Appalachian Basin [Member]

Impairment of Equity Method Investment in Appalachian Basin [Member]

acre

Impairment Costs [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset impairment charges

'

$1,392

$225

$367

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of producing properties and costs of acquired unproved reserves (Note 6)

108

1,055

[1],[2]

225

[1],[3]

367

[1],[4]

'

'

317

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of producing properties and costs of acquired unproved reserves

'

1,055

225

367

'

'

'

'

85

65

52

91

85

102

88

75

69

19

'

'

'

'

'

'

Impairment charge

'

'

'

'

'

772

792

'

192

'

'

'

107

102

'

75

'

'

3

'

'

'

'

'

Impairment of proved oil and gas properties

'

'

'

'

'

'

'

'

107

'

'

276

'

'

'

'

'

'

'

48

'

'

'

'

Net acres sold

'

'

'

'

'

'

'

140,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of Powder River Basin deep rights leasehold

'

36

0

0

'

'

'

36

36

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dry hole costs

'

7

4

13

11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unproved leasehold property impairment, amortization and expiration

'

402

58

95

'

'

317

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Write-off of leasehold costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

'

'

Investment income, impairment of equity method investment and other

'

$5

$30

$26

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($20)

$0

$0

[1]

Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.

[2]

As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

[3]

As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

[4]

As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Asset_Sales_Impairments_and_Ex4

Asset Sales, Impairments and Exploration Expenses - Summary of Exploration Expenses (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Geologic and geophysical costs	$22	$21	$18
Dry hole costs	7	4	13
Unproved leasehold property impairment, amortization and expiration	402	58	95
Total exploration expense	$431	$83	$126

Properties_and_Equipment_Carri

Properties and Equipment - Carried at Cost (Detail) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

Proved properties

Proved properties

Unproved Properties

Unproved Properties

Gathering, Processing and Other Facilities

Gathering, Processing and Other Facilities

Gathering, Processing and Other Facilities

Gathering, Processing and Other Facilities

Construction in Progress

Construction in Progress

Other

Other

Other

Other

Minimum

Maximum

Minimum

Maximum

Property, Plant and Equipment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Property and equipment, estimated useful life (years)

'

'

'

'

'

'

'

'

'15 years

[1]

'25 years

[1]

'

'

'

'

'3 years

[1]

'40 years

[1]

Properties and equipment-net, at cost

$12,686

$13,339

$11,476

[2]

$11,267

[2]

$423

[3]

$1,156

[3]

$225

$247

'

'

$382

[3]

$497

[3]

$180

$172

'

'

Accumulated depreciation, depletion and amortization

-5,445

-4,923

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Properties and equipment-net

$7,241

$8,416

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Estimated useful lives are presented as of December 31, 2013.

[2]

Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).

[3]

Unproved properties and construction in progress are not yet subject to depreciation and depletion.

Properties_and_Equipment_Addit

Properties and Equipment - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Powder River Basin	'	'
Property, Plant and Equipment [Line Items]	'	'
Construction in progress	$15	$44
Exploratory Well Cost Pending the Determination of Proved Reserves	'	'
Property, Plant and Equipment [Line Items]	'	'
Construction in progress	$24	'

Properties_and_Equipment_Rollf

Properties and Equipment - Rollforward Asset Retirement Obligation (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning Balance	$321		$289
Liabilities incurred during the period	14		19
Liabilities settled during the period	-11		-7
Estimate revisions	17		-1
Accretion expense	23	[1]	21	[1]
Ending Balance	364		321
Amount reflected as current	$6		$5
[1]	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Accounts_Payable_and_Accrued_a2

Accounts Payable and Accrued and Other Current Liabilities - Accounts Payable (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Payables and Accruals [Abstract]	'	'
Trade	$213	$209
Accrual for capital expenditures	237	126
Royalties	130	106
Cash overdrafts	35	34
Other	37	34
Accounts payable	$652	$509

Accounts_Payable_and_Accrued_a3

Accounts Payable and Accrued and Other Current Liabilities - Accrued and Other Current Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Payables and Accruals [Abstract]	'	'
Taxes other than income taxes	$41	$54
Accrued interest	43	42
Compensation and benefit related accruals	52	52
Other, including other loss contingencies	54	53
Accrued And Other Current Liabilities	$190	$201

Debt_and_Banking_Arrangements_1

Debt and Banking Arrangements - Debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'	'
Total debt	$1,919	$1,510	[1]
Less: Current portion of long-term debt	3	2	[1]
Total long-term debt	1,916	1,508	[1]
Apco	'	'
Debt Instrument [Line Items]	'	'
Total debt	8	8	[1]
5.250% Senior Notes due 2017	'	'
Debt Instrument [Line Items]	'	'
Total debt	400	400	[1]
6.000% Senior Notes due 2022	'	'
Debt Instrument [Line Items]	'	'
Total debt	1,100	1,100	[1]
Credit Facility Agreement	'	'
Debt Instrument [Line Items]	'	'
Total debt	410	0	[1]
Other	'	'
Debt Instrument [Line Items]	'	'
Total debt	$1	$2	[1]
[1]	Interest paid on debt totaled $91 million and $58 million for 2013 and 2012, respectively.

Debt_and_Banking_Arrangements_2

Debt and Banking Arrangements - Debt (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2012
			5.250% Senior Notes due 2017	5.250% Senior Notes due 2017	5.250% Senior Notes due 2017	6.000% Senior Notes due 2022	6.000% Senior Notes due 2022	6.000% Senior Notes due 2022
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'
Debt instrument stated interest rate	'	'	5.25%	5.25%	5.25%	6.00%	6.00%	6.00%
Debt instrument maturity year	'	'	'2017	'2017	'	'2022	'2022	'
Long-term debt, interest expense	$91	$58	'	'	'	'	'	'

Debt_and_Banking_Arrangements_3

Debt and Banking Arrangements - Additional Information (Detail) (USD $)

12 Months Ended

2 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2011

Feb. 27, 2014

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2011

Nov. 30, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2012

Contract

Subsequent Event

Apco

Unsecured Revolving Credit Facility

Unsecured Revolving Credit Facility

Unsecured Revolving Credit Facility

Unsecured Revolving Credit Facility

Senior Notes

Change of Control

Debt Covenant

Other Contractual Agreements

5.250% Senior Notes due 2017

5.250% Senior Notes due 2017

5.250% Senior Notes due 2017

6.000% Senior Notes due 2022

6.000% Senior Notes due 2022

6.000% Senior Notes due 2022

Federal Funds Rate

one-month LIBOR

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Face value of senior notes

'

'

'

'

'

'

'

'

$1,500,000,000

'

'

'

'

'

'

'

'

'

Net proceeds from debt offering

'

'

'

'

'

'

'

'

1,481,000,000

'

'

'

'

'

'

'

'

'

Retained proceeds from issuance of notes

'

'

'

'

'

'

'

'

500,000,000

'

'

'

'

'

'

'

'

'

Distribution to Williams a portion of note proceeds

'

981,000,000

'

'

'

'

'

'

981,000,000

'

'

'

'

'

'

'

'

'

Debt redemption price as percentage of principal amount

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt redemption price as percentage of present value of principal amount

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument redemption date

15-Oct-21

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of repurchase of notes on principal amount of notes

'

'

'

'

'

'

'

'

'

101.00%

'

'

'

'

'

'

'

'

Number of days of default interest payment

'30 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of continuance of failure notice after notice given date

'

'

'

'

'

'

'

'

'

'

'60 days

'90 days

'

'

'

'

'

'

Automatic additional days extended if such failure is not capable of cure within such 60-day or 90-day period

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument stated interest rate

'

'

'

'

'

'

'

'

'

'

'

'

5.25%

5.25%

5.25%

6.00%

6.00%

6.00%

Credit facility agreement

'

'

'

10,000,000

1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument maturity period

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument additional borrowing capacity

'

'

195,000,000

'

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average interest rate

'

'

'

'

'

2.27%

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding amount

'

'

'

8,000,000

'

410,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Basis spread on variable rate

'

'

'

'

'

'

0.50%

1.00%

'

'

'

'

'

'

'

'

'

'

Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness

1.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Present value discounted rate

9.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum ratio of debt to capitalization

60.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of letter of credit agreements

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of credit issued

$361,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Credit facility, maturity year

'

'

'

'2016

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Provision_Benefit_for_Income_T2

Provision (Benefit) for Income Taxes - Provision (Benefit) for Income Taxes from Continuing Operations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:	'	'	'
Federal	($29)	$48	$49
State	1	3	7
Foreign	18	14	10
Total current	-10	65	66
Deferred:	'	'	'
Federal	-608	-162	-139
State	-51	-13	-1
Foreign	14	-1	0
Total Deferred	-645	-176	-140
Total provision (benefit)	($655)	($111)	($74)

Provision_Benefit_for_Income_T3

Provision (Benefit) for Income Taxes - Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Provision (benefit) at statutory rate	($646)	($120)	($79)
Increases (decreases) in taxes resulting from:	'	'	'
State income taxes (net of federal benefit)	-110	-10	-5
State income change in valuation allowance (net of federal benefit)	80	3	0
Effective state income tax rate change (net of federal benefit)	-3	0	9
Alternative minimum tax credits	0	11	0
Argentina capital tax (net of federal benefit)	10	0	0
Foreign operations	5	4	0
Other	9	1	1
Total provision (benefit)	($655)	($111)	($74)

Provision_Benefit_for_Income_T4

Provision (Benefit) for Income Taxes - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Provision For Income Taxes [Line Items]	'	'	'	'
State net operating loss carryovers expire percent	'	90.00%	'	'
State net operating loss carryovers expiration year	'	'2029	'	'
Income (loss)from continuing operations before income taxes, foreign income	'	$50,000,000	$52,000,000	$40,000,000
Undistributed earnings of consolidated foreign subsidiaries	'	76,000,000	'	'
Argentine tax rate On dividends	10.00%	'	'	'
Argentine capital gain tax rate	13.50%	'	'	'
Deferred foreign income tax expense, Argentina	14,000,000	'	'	'
Deferred income tax existing on basis differences in equity investments prior to tax law enactment	12,000,000	'	'	'
US deferred income tax expense related to foreign operations	4,000,000	'	'	'
Not recognized in operating loss carryforwards	'	7,000,000	'	'
Deferred tax asset, alternative minimum tax credits	'	76,000,000	99,000,000	98,000,000
Reductions in alternative minimum tax credit	'	'	'	15,000,000
Alternative minimum tax credits	'	0	11,000,000	0
Unrecognized tax benefits	'	0	'	'
Apco	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Percentage of ownership interest contributed and transferred by Williams	'	69.00%	'	'
Federal	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Operating Loss Carryforwards	'	114,000,000	'	'
State	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Operating Loss Carryforwards	'	825,000,000	'	'
Foreign | Federal Administration of Public Income, Argentina	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Income tax rate	'	35.00%	'	'
Foreign | National Tax and Customs Direction, Columbia (DIAN)	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Income tax rate	'	25.00%	'	'
Additional income tax rate	'	9.00%	'	'
Domestic	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Income tax cash paid (refund)	'	-26,000,000	40,000,000	10,000,000
International	'	'	'	'
Provision For Income Taxes [Line Items]	'	'	'	'
Income tax cash paid (refund)	'	$14,000,000	$11,000,000	$10,000,000

Provision_Benefit_for_Income_T5

Provision (Benefit) for Income Taxes - Significant Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Deferred tax liabilities:	'	'	'
Properties and equipment	$963	$1,652	'
Other, net	36	19	'
Total deferred tax liabilities	999	1,671	'
Deferred tax assets:	'	'	'
Accrued liabilities and other	176	176	'
Alternative minimum tax credits	76	99	98
Loss carryovers	89	31	'
Other	21	0	'
Total deferred tax assets	362	306	'
Less: valuation allowance	102	19	'
Total net deferred tax assets	260	287	'
Net deferred tax liabilities	$739	$1,384	'

Contingent_Liabilities_and_Com2

Contingent Liabilities and Commitments - Additional Information (Detail) (USD $)	12 Months Ended					1 Months Ended	12 Months Ended	97 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Sep. 30, 2006	Dec. 31, 2013	Jul. 31, 2008	Dec. 31, 2012
				Long-term obligation	Purchase agreement	Royalty Litigation	Royalty Litigation	Royalty Litigation	Royalty Litigation
				Piceance	Marcellus Shale	Claim
				MMBTU	MMBTU
Loss Contingencies [Line Items]	'	'	'	'	'	'	'	'	'
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	106	'	'	'	'	'	'	'	'
Loss contingencies associated with royalty litigation	'	'	'	'	'	'	16	'	18
Litigation settlement amount	'	'	'	'	'	'	8	'	'
Commitments to provide service to an equity investee and others	389	'	'	'	'	'	'	'	'
Service commitment period	'6 years	'	'	'	'	'	'	'	'
Volume of natural gas production per day	'	'	'	200,000	200,000	'	'	'	'
Obligation expiration year	'	'	'	'2014	'	'	'	'	'
Contract term	'	'	'	'	'12 years	'	'	'	'
Total rent expenses	$27	$20	$12	'	'	'	'	'	'

Contingent_Liabilities_and_Com3

Contingent Liabilities and Commitments - Commitments Under Contracts (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]	'
2014	$224
2015	219
2016	197
2017	178
2018	167
Thereafter	578
Total	$1,563

Contingent_Liabilities_and_Com4

Contingent Liabilities and Commitments - Future Minimum Annual Rentals Under Noncancelable Operating Leases (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]	'
2014	$58
2015	50
2016	29
2017	8
2018	7
Thereafter	22
Total	$174

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended				1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 31, 2012	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2012
				If employees are 40 years or older	If employees are under age 40	Non-matching annual contribution	Non-matching annual contribution	Maximum
Employee Benefit And Retirement Plans [Line Items]	'	'	'	'	'	'	'	'
Defined contribution plan, employer matching percentage	'	'	'	'	'	'	'	6.00%
Non matching employer contribution under defined benefit contribution plan	'	'	'	8.00%	6.00%	'	'	'
Defined contribution plan, employer contribution	$16	$6	'	'	'	'	'	'
Accrued and other current liabilities	190	201	'	'	'	11	10	'
Pension expense charged by Williams	'	'	8	'	'	'	'	'
Other post retirement benefits charged by Williams (less than $1 million in 2011)	'	'	1	'	'	'	'	'
Defined Contribution Plan compensation expense charged by Williams	'	'	$4	'	'	'	'	'

StockBased_Compensation_Additi

Stock-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Based Compensation Activity [Line Items]	'	'	'
Common stock share authorized	2,000,000,000	2,000,000,000	'
Employee stock purchase plan purchase price first offering start date	1-Mar-12	'	'
Employee stock purchase plan purchase price first offering end date	30-Jun-12	'	'
Stock option exercisable period	'3 years	'	'
Stock option term	'10 years	'	'
Restricted stock units vesting period	'3 years	'	'
Unrecognized stock based compensation	$41	'	'
Value of stock option exercised during year	5	5	7
Cash received from stock option exercises	4	2	'
Unearned grant expected to be recognized in period	'3 years	'	'
Minimum	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Range of vested shares of original grant amount	0.00%	'	'
Maximum	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Range of vested shares of original grant amount	200.00%	'	'
Nonvested Restricted Stock Units	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Performance based share granted, percent of nonvested restricted stock units outstanding	17.00%	'	'
Administrative expenses	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Stock based compensation expense	31	28	18
Stock Options	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Unrecognized stock based compensation	1	'	'
Unrecognized stock based compensation, weighted average period of recognition	'2 years	'	'
Restricted Stock Units	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Unrecognized stock based compensation	$40	'	'
WPX Energy, Inc. 2011 Incentive Plan	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Common stock share authorized	11,000,000	'	'
Discount allowed on employee stock purchase plan	15.00%	'	'
Number of share purchased under stock option plan	117,000	'	'
Stock option plan, average purchase price	$14.33	'	'
WPX Energy, Inc. 2011 Incentive Plan | Maximum	'	'	'
Stock Based Compensation Activity [Line Items]	'	'	'
Number of share available for purchase under stock option plan	1,000,000	'	'

StockBased_Compensation_Summar

Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013
Option Outstanding	'
Beginning Balance (in shares)	4.1
Granted (in shares)	0.4
Exercised (in shares)	-0.4
Forfeited (in shares)	0
Expired (in shares)	0
Ending Balance (in shares)	4.1
Exercisable at end of period (in shares)	3.2
Weighted Average Exercise price	'
Beginning Balance (in dollars per share)	$12.68
Granted (in dollars per share)	$14.41
Exercised (in dollars per share)	$8.86
Forfeited (in dollars per share)	$16.46
Expired (in dollars per share)	$19.26
Ending Balance (in dollars per share)	$13.27
Exercisable at end of period (in dollars per share)	$12.62
Aggregate Intrinsic value	'
Beginning Balance	$14
Ending Balance	29
Exercisable at end of period	$25

StockBased_Compensation_Summar1

Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Parenthetical) (Detail) (Williams Employees, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Williams Employees	'	'
Schedule Of Stock Options [Line Items]	'	'
Share held by Williams' employees	344	598
Weighted average price of share held by Williams' employee	$9.24	$8.48

StockBased_Compensation_Summar2

Stock-Based Compensation - Summary of Stock Option Outstanding and Exercisable (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]	'	'
Range of Exercise Prices, Lower Limit	$20.21	$16.46
Range of Exercise Prices, Upper Limit	$20.97	$20.97
Options outstanding (in shares)	4.1	4.1
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$13.27	$12.68
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	'5 years 3 months 18 days	'
Options exercisable (in shares)	3.2	'
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$12.62	'
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	'4 years 6 months	'
$ 5.50 to $6.02	'	'
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]	'	'
Range of Exercise Prices, Lower Limit	$5.50	'
Range of Exercise Prices, Upper Limit	$6.02	'
Options outstanding (in shares)	0.8	'
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$5.95	'
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	'4 years 6 months	'
Options exercisable (in shares)	0.8	'
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$5.95	'
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	'4 years 6 months	'
$ 9.08 to $11.75	'	'
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]	'	'
Range of Exercise Prices, Lower Limit	$9.08	'
Range of Exercise Prices, Upper Limit	$11.75	'
Options outstanding (in shares)	0.9	'
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$11.34	'
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	'4 years 3 months 18 days	'
Options exercisable (in shares)	0.9	'
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$11.34	'
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	'4 years 3 months 18 days	'
$12.00 to $15.67	'	'
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]	'	'
Range of Exercise Prices, Lower Limit	$12	'
Range of Exercise Prices, Upper Limit	$15.67	'
Options outstanding (in shares)	1.1	'
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$14.45	'
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	'5 years 4 months 24 days	'
Options exercisable (in shares)	0.7	'
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$14.47	'
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	'2 years 10 months 24 days	'
$16.46 to $20.97	'	'
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]	'	'
Range of Exercise Prices, Lower Limit	$16.46	'
Range of Exercise Prices, Upper Limit	$20.97	'
Options outstanding (in shares)	1.3	'
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)	$18.17	'
Options Outstanding Weighted- Average Remaining Contractual Life (Years)	'6 years 4 months 24 days	'
Options exercisable (in shares)	0.8	'
Options exercisable, Weighted- Average Exercise Price (in dollars per share)	$18.48	'
Options exercisable, Weighted- Average Remaining Contractual Life (Years)	'5 years 10 months 24 days	'

StockBased_Compensation_Estima

Stock-Based Compensation - Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'	'	'
Weighted-average or grant date fair value of options granted	$6.04	$7.79	$0
Weighted-average conversion date fair value options granted	'	'	$8.48
Dividend yield	0.00%	0.00%	0.00%
Volatility	42.80%	43.80%	45.00%
Risk-free interest rate	1.06%	1.17%	0.38%
Expected life	'6 years	'6 years	'2 years 9 months 18 days

StockBased_Compensation_Summar3

Stock-Based Compensation - Summary of Nonvested Restricted Stock Unit Activity and Related Information (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013
Nonvested Shares	'
Beginning Balance	4.8
Granted	2.2
Forfeited	-0.2
Vested	-1.6
Ending balance	5.2
Weighted-Average Fair Value	'
Nonvested, Beginning Balance	$16.45	[1]
Granted	$14.97	[1]
Forfeited	$16.61	[1]
Vested	$11.27	[1]
Nonvested, Ending Balance	$16.97	[1]
[1]	Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

StockBased_Compensation_Other_

Stock-Based Compensation - Other Restricted Stock Unit (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
			Restricted Stock Units	Restricted Stock Units	Restricted Stock Units
					Williams
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]	'		'	'	'
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$14.97	[1]	$14.97	$17.35	$27.74
Total fair value of restricted stock units vested during the year (millions)	'		$18	$14	$10
[1]	Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Stockholders_Equity_Additional

Stockholders' Equity - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Vote
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]	'	'	'
Number of votes per share for common stockholders	1	'	'
Dividends declared (in dollars per share)	$0	$0	$0
Dividends paid (in dollars per share)	$0	$0	$0
Common Stock Subject to Mandatory Redemption	'	'	'
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]	'	'	'
Shares subject to redemption	0	'	'

Fair_Value_Measurements_Assets

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Long-term debt	$1,945	[1]	$1,617	[1]
Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Energy derivative assets	57		60
Energy derivative liabilities	122		15
Level 1 | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Energy derivative assets	30		20
Energy derivative liabilities	83		11
Level 2	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Long-term debt	1,945	[1]	1,617	[1]
Level 2 | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Energy derivative assets	26		38
Energy derivative liabilities	38		1
Level 3 | Energy Related Derivative	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Energy derivative assets	1		2
Energy derivative liabilities	$1		$3
[1]	The carrying value of total debt, excluding capital leases, was $1,918 million and $1,508 million as of December 31, 2013 and 2012, respectively.

Fair_Value_Measurements_Assets1

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Parenthetical) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Long-term debt, excluding capital lease obligations	$1,945	[1]	$1,617	[1]
Carrying value	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Long-term debt, excluding capital lease obligations	$1,918		$1,508
[1]	The carrying value of total debt, excluding capital leases, was $1,918 million and $1,508 million as of December 31, 2013 and 2012, respectively.

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]	'	'
Percentage of net fair value of derivatives portfolio expiring	99.00%	'
Expiry of net fair value of derivatives portfolio	'24 months	'
Fair value measurement with unobservable inputs reconciliation, recurring basis settlements	'	$12

Fair_Value_Measurements_Level_

Fair Value Measurements - Level 3 Fair Value Measurements Using Significant Unobservable Inputs (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'	'	'
Beginning balance	($1)	$1	$1
Realized and unrealized gains (losses) included in income (loss) from continuing operations	-2	3	15
Realized and unrealized gains (losses) included in other comprehensive income (loss)	0	0	0
Purchases, issuances, and settlements	3	-5	-12
Transfers out of Level 3	0	0	-3
Ending balance	0	-1	1
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	($1)	($1)	$1

Fair_Value_Measurements_Impair

Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Fair Value Disclosures [Abstract]	'	'		'		'
Impairment of producing properties and costs of acquired unproved reserves (Note 6)	$108	$1,055	[1],[2]	$225	[1],[3]	$367	[1],[4]
Unproved leasehold	'	317	[2]	0		0
Equity method investment (Note 4)	'	20		0		0
Asset Impairment Charges, Total	'	$1,392		$225		$367
[1]	Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
[2]	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
[3]	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
[4]	As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Fair_Value_Measurements_Impair1

Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy (Parenthetical) (Detail) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Probable Reserves

Possible Reserves

Powder River Basin

Powder River Basin

Domestic Segment

Piceance Basin [Member]

Appalachian Basin

Appalachian Basin

Appalachian Basin

Appalachian Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Piceance

Piceance

Green River

Green River

Probable Reserves

Possible Reserves

Possible Reserves

Probable Reserves

Proved Properties

Minimum

Proved Properties

Proved Properties

Unproved Properties

Probable Reserves

Possible Reserves

Minimum

Minimum

Proved Properties

Minimum

Unproved Properties

Unproved Properties

Unproved Properties

Unproved Properties

Proved Properties

Unproved Properties

Unproved Properties

Proved Properties

Proved Properties

Proved Properties

Mcfe

Mcfe

Mcfe

Mcfe

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of producing properties and costs of acquired unproved reserves

$365

$351

$546

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment charge

'

'

'

'

'

'

'

'

'

772

792

'

'

192

'

'

'

107

102

'

276

'

'

'

'

'

'

75

48

'

Proved reserve quantities of gas equivalent

'

'

'

'

'

'

'

'

'

'

'

'

299,000,000

'

'

'

'

'

'

'

'

'

'

'

294,000,000

352,000,000

'

'

'

29,000,000

Weighted average natural gas price

3.63

3.01

4.41

'

'

'

'

'

'

'

'

3.6

'

'

'

'

'

'

'

3.53

3.81

'

'

'

'

'

'

'

5.87

'

Percentage of discount rate after-tax

'

'

'

13.00%

15.00%

13.00%

18.00%

15.00%

15.00%

'

'

11.00%

'

'

'

'

'

'

'

11.00%

11.00%

'

13.00%

15.00%

'

'

'

'

11.00%

'

Impairment of producing properties and costs of acquired unproved reserves

1,055

225

367

'

'

'

'

'

'

'

'

'

'

85

65

52

91

85

102

'

'

91

'

'

'

'

88

75

'

'

Unproved leasehold property impairment, amortization and expiration

$402

$58

$95

'

'

'

'

'

'

'

$317

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives_and_Concentration_2

Derivatives and Concentration of Credit Risk - Derivative Volumes that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production (Detail)	12 Months Ended
	Dec. 31, 2013
Derivatives related to production | Crude Oil Commodity Contract One | Fixed Priced Swaps | WTI | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Fixed Price Swaps	[1]
Location	'WTI
Notional Volume	13,243	[2]
Underlying, Derivative	94.82	[3]
Derivatives related to production | Crude Oil Commodity Contract Two | Basis Swap | Brent | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Basis Swaps	[1]
Location	'Brent
Notional Volume	4,463	[2]
Underlying, Derivative	9.64	[3]
Derivatives related to production | Crude Oil Commodity Number Three | Swaptions | WTI | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2015
Contract Type	'Swaptions	[1]
Location	'WTI
Notional Volume	1,750	[2]
Underlying, Derivative	98.54	[3]
Derivatives related to production | Natural Gas Commodity Contract One | Fixed Priced Swaps | Henry Hub | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Fixed Price Swaps	[1]
Location	'Henry Hub
Notional Volume	315,000	[2]
Underlying, Derivative	4.19	[3]
Derivatives related to production | Natural Gas Commodity Contract Two | Swaptions | Henry Hub | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Swaptions	[1]
Location	'Henry Hub
Notional Volume	50,000	[2]
Underlying, Derivative	4.24	[3]
Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Costless Collars	[1]
Location	'Henry Hub
Notional Volume	165,000	[2]
Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Short | Minimum	'
Derivative [Line Items]	'
Underlying, Derivative	4.01	[3]
Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Short | Maximum	'
Derivative [Line Items]	'
Underlying, Derivative	4.64	[3]
Derivatives related to production | Natural Gas Commodity Contract Four | Basis Swap | Northeast | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Basis Swaps	[1]
Location	'Northeast
Notional Volume	23,000	[2]
Underlying, Derivative	0.09	[3]
Derivatives related to production | Natural Gas Commodity Contract Five | Basis Swap | Midcon | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Basis Swaps	[1]
Location	'MidCon
Notional Volume	39,000	[2]
Underlying, Derivative	-0.18	[3]
Derivatives related to production | Natural Gas Commodity Contract Six | Basis Swap | Rockies | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Basis Swaps	[1]
Location	'Rockies
Notional Volume	78,000	[2]
Underlying, Derivative	-0.18	[3]
Derivatives related to production | Natural Gas Commodity Contract Seven | Basis Swap | West | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Basis Swaps	[1]
Location	'West
Notional Volume	27,000	[2]
Underlying, Derivative	0.08	[3]
Derivatives related to production | Natural Gas Commodity Contract Eight | Fixed Priced Swaps | Henry Hub | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2015
Contract Type	'Fixed Price Swaps	[1]
Location	'Henry Hub
Notional Volume	35,000	[2]
Underlying, Derivative	4.38	[3]
Derivatives related to production | Natural Gas Commodity Contract Nine | Swaptions | Henry Hub | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2015
Contract Type	'Swaptions	[1]
Location	'Henry Hub
Notional Volume	35,000	[2]
Underlying, Derivative	4.38	[3]
Derivatives related to production | Natural Gas Liquids Ethane | Fixed Priced Swaps | Mont Belvieu | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Fixed Price Swaps	[1]
Location	'Mont Belvieu
Notional Volume	986	[2]
Underlying, Derivative	0.28	[3]
Derivatives related to production | Matural Gas Liquids Natural Gasoline | Fixed Priced Swaps | Mont Belvieu | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Fixed Price Swaps	[1]
Location	'Mont Belvieu
Notional Volume	822	[2]
Underlying, Derivative	2.05	[3]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract One | Fixed Priced Swaps | Multiple Location | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Fixed Price Swaps	[4]
Location	'Multiple	[5]
Notional Volume	11,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Two | Basis Swap | Multiple Location | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Basis Swaps	[4]
Location	'Multiple	[5]
Notional Volume	31,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Three | Index | Multiple Location | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Index	[4]
Location	'Multiple	[5]
Notional Volume	107,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Four | Basis Swap | Multiple Location | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2015
Contract Type	'Basis Swaps	[4]
Location	'Multiple	[5]
Notional Volume	6,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Five | Index | Multiple Location | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2015
Contract Type	'Index	[4]
Location	'Multiple	[5]
Notional Volume	43,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Six | Index | Multiple Location | Long	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2016
Contract Type	'Index	[4]
Location	'Multiple	[5]
Notional Volume	2,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Seven | Index | Multiple Location | Long	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2017
Contract Type	'Index	[4]
Location	'Multiple	[5]
Notional Volume	2,000	[2]
Underlying, Derivative	0	[6]
Derivatives primarily related to storage and transportation | Natural Gas Liquids | Fixed Priced Swaps | Multiple Location | Short	'
Derivative [Line Items]	'
Derivative Maturities Dates	'2014
Contract Type	'Fixed Price Swaps	[4]
Location	'Multiple	[5]
Notional Volume	822,000	[2]
Underlying, Derivative	0	[6]
[1]	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.
[2]	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.
[3]	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.
[4]	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.
[5]	WPX Marketing transacts at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
[6]	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 - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
	Mar. 21, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
				Williams	Williams	Domestic Segment	Domestic Segment	Domestic Segment	Domestic Segment	Maximum	Maximum
						BP Energy	BP Energy	BP Energy	Southern California Gas
Derivative [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Occurrence of future net cash flows for derivatives	'	'12 months	'	'	'	'	'	'	'	'	'
Gains or losses recognized in income from assessment of hedge	'	$0	'	'	'	'	'	'	'	'	'
Collateral posted to derivative	'	71,000,000	2,000,000	'	'	'	'	'	'	'	'
Initial margin	'	19,000,000	'	'	'	'	'	'	'	'	'
Maintenance margin	'	52,000,000	'	'	'	'	'	'	'	'	'
Net derivative liability position	'	72,000,000	5,000,000	'	'	'	'	'	'	'	'
Reduction in derivative liabilities	'	'	'	'	'	'	'	'	'	1,000,000	1,000,000
Additional collateral posted	'	20,000,000	3,000,000	'	'	'	'	'	'	'	'
Unrealized gains recognized for hedge transactions	15,000,000	'	15,000,000	'	'	'	'	'	'	'	'
Future cash flow hedged term	'	'	'3 months	'	'	'	'	'	'	'	'
Net gains reclassified into earnings within the next year	'	'	3,000,000	'	'	'	'	'	'	'	'
Net of income tax provision	'	'	2,000,000	'	'	'	'	'	'	'	'
Net credit exposure percentage	'	89.00%	'	'	'	'	'	'	'	'	'
Collateral support	'	$55,000,000	'	'	'	'	'	'	'	'	'
Percentage of consolidated revenue	'	'	'	8.00%	12.00%	15.00%	10.00%	11.00%	11.00%	'	'

Derivatives_and_Concentration_4

Derivatives and Concentration of Credit Risk - Fair Value of Energy Commodity Derivatives (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Total derivatives, Assets	$57	$60
Total derivatives, Liabilities	122	15
Designated as Hedging Instrument | Derivatives related to production	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives, Assets	0	5
Total derivatives, Liabilities	0	0
Not Designated as Hedging Instrument	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives, Assets	57	55
Total derivatives, Liabilities	122	15
Not Designated as Hedging Instrument | Legacy natural gas contracts from former power business	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives, Assets	0	2
Total derivatives, Liabilities	0	2
Not Designated as Hedging Instrument | Derivatives related to production	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives, Assets	26	33
Total derivatives, Liabilities	39	0
Not Designated as Hedging Instrument | Derivatives Related to Physical Marketing Agreements	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives, Assets	31	20
Total derivatives, Liabilities	$83	$13

Derivatives_and_Concentration_5

Derivatives and Concentration of Credit Risk - Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$5		$434		$331
Cash Flow Hedging | Accumulated Other Comprehensive Income	'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Net gain recognized in other comprehensive income (loss) (effective portion)	0		90		'
Cash Flow Hedging | Revenues	'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$5	[1]	$434	[1]	'
[1]	Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.

Derivatives_and_Concentration_6

Derivatives and Concentration of Credit Risk - Offsetting of Derivative Assets and Liabilities (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Derivative Asset [Abstract]	'		'
Gross Amount Presented on Balance Sheet	$57		$60
Netting Adjustment	-50	[1]	-10	[1]
Cash Collateral Posted(Received)	0		-2
Net Amount	7		48
Derivative Liability [Abstract]	'		'
Gross Amount Presented on Balance Sheet	-122		-15
Netting adjustment	50	[1]	10	[1]
Cash Collateral Posted(Received)	52		0
Net Amount	($20)		($5)
[1]	With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Derivatives_and_Concentration_7

Derivatives and Concentration of Credit Risk - Concentration of Receivables, Net of Allowances, by Product or Service (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Receivables [Line Items]	'	'
Account receivables	$536	$443
Sale of natural gas and related products and services	'	'
Receivables [Line Items]	'	'
Account receivables	339	289
Joint interest owners	'	'
Receivables [Line Items]	'	'
Account receivables	186	138
Other	'	'
Receivables [Line Items]	'	'
Account receivables	$11	$16

Derivatives_and_Concentration_8

Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Credit Exposure From Derivatives [Line Items]	'
Gross credit reserves	$0
Gross credit exposure from derivatives	57
Net credit reserves	0
Net credit exposure from derivatives	7
Financial institutions	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	57
Total net credit exposure from derivative contracts before credit reserve	7
Investment Grade | Financial institutions	'
Credit Exposure From Derivatives [Line Items]	'
Total gross credit exposure from derivative contracts before credit reserve	57
Total net credit exposure from derivative contracts before credit reserve	$7

Derivatives_and_Concentration_9

Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013
Standard & Poor's	'
Credit Exposure From Derivatives [Line Items]	'
Counterparties credit rating in investment grade	'BBB-
Moody's Investors Service	'
Credit Exposure From Derivatives [Line Items]	'
Counterparties credit rating in investment grade	'Baa3

Segment_Disclosures_Reconcilia

Segment Disclosures - Reconciliation of Segment Revenues and Segment Operating Income (Loss) to Revenues and Operating Income (Loss) (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	$657	$658	$815	$631	$827	$677	$775	$910	$2,761	$3,189	$3,882
Costs and expenses:	'	'	'	'	'	'	'	'	'	'	'
Lease and facility operating	'	'	'	'	'	'	'	'	308	283	262
Gathering, processing and transportation	'	'	'	'	'	'	'	'	433	506	487
Taxes other than income	'	'	'	'	'	'	'	'	141	111	134
Gas management, including charges for unutilized pipeline capacity	'	'	'	'	'	'	'	'	931	996	1,471
Exploration (Note 6)	'	'	'	'	'	'	'	'	431	83	126
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	940	966	902
Impairment of producing properties and costs of acquired unproved reserves	'	'	'	'	'	'	'	'	1,055	225	367
Gain on sale of Powder River Basin deep rights leasehold	'	'	'	'	'	'	'	'	-36	0	0
General and administrative	'	'	'	'	'	'	'	'	289	287	275
Other—net	'	'	'	'	'	'	'	'	17	12	0
Total costs and expenses	'	'	'	'	'	'	'	'	4,509	3,469	4,024
Operating income (loss)	'	'	'	'	'	'	'	'	-1,748	-280	-142
Interest expense	'	'	'	'	'	'	'	'	-108	-102	-117
Interest capitalized	'	'	'	'	'	'	'	'	5	8	9
Investment income, impairment of equity method investment and other	'	'	'	'	'	'	'	'	5	30	26
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	-1,846	-344	-224
Net capital expenditures	1,154	'	'	'	1,521	'	'	'	1,154	1,521	1,572
Total assets	8,429	'	'	'	9,456	'	'	'	8,429	9,456	10,432
Long-lived assets	12,831	'	'	'	13,484	'	'	'	12,831	13,484	12,323
Domestic	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	2,609	3,052	3,772
Costs and expenses:	'	'	'	'	'	'	'	'	'	'	'
Lease and facility operating	'	'	'	'	'	'	'	'	271	251	235
Gathering, processing and transportation	'	'	'	'	'	'	'	'	430	504	487
Taxes other than income	'	'	'	'	'	'	'	'	117	87	113
Gas management, including charges for unutilized pipeline capacity	'	'	'	'	'	'	'	'	931	996	1,471
Exploration (Note 6)	'	'	'	'	'	'	'	'	424	72	123
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	906	939	880
Impairment of producing properties and costs of acquired unproved reserves	'	'	'	'	'	'	'	'	1,052	225	367
Gain on sale of Powder River Basin deep rights leasehold	'	'	'	'	'	'	'	'	-36	'	'
General and administrative	'	'	'	'	'	'	'	'	275	273	263
Other—net	'	'	'	'	'	'	'	'	17	12	-3
Total costs and expenses	'	'	'	'	'	'	'	'	4,387	3,359	3,936
Operating income (loss)	'	'	'	'	'	'	'	'	-1,778	-307	-164
Interest expense	'	'	'	'	'	'	'	'	-108	-102	-117
Interest capitalized	'	'	'	'	'	'	'	'	5	8	9
Investment income, impairment of equity method investment and other	'	'	'	'	'	'	'	'	-16	3	6
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	-1,897	-398	-266
Net capital expenditures	1,103	'	'	'	1,463	'	'	'	1,103	1,463	1,531
Total assets	8,046	'	'	'	9,113	'	'	'	8,046	9,113	10,144
Long-lived assets	12,346	'	'	'	13,056	'	'	'	12,346	13,056	11,969
International	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	152	137	110
Costs and expenses:	'	'	'	'	'	'	'	'	'	'	'
Lease and facility operating	'	'	'	'	'	'	'	'	37	32	27
Gathering, processing and transportation	'	'	'	'	'	'	'	'	3	2	0
Taxes other than income	'	'	'	'	'	'	'	'	24	24	21
Gas management, including charges for unutilized pipeline capacity	'	'	'	'	'	'	'	'	0	0	0
Exploration (Note 6)	'	'	'	'	'	'	'	'	7	11	3
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	34	27	22
Impairment of producing properties and costs of acquired unproved reserves	'	'	'	'	'	'	'	'	3	0	0
Gain on sale of Powder River Basin deep rights leasehold	'	'	'	'	'	'	'	'	0	'	'
General and administrative	'	'	'	'	'	'	'	'	14	14	12
Other—net	'	'	'	'	'	'	'	'	0	0	3
Total costs and expenses	'	'	'	'	'	'	'	'	122	110	88
Operating income (loss)	'	'	'	'	'	'	'	'	30	27	22
Interest expense	'	'	'	'	'	'	'	'	0	0	0
Interest capitalized	'	'	'	'	'	'	'	'	0	0	0
Investment income, impairment of equity method investment and other	'	'	'	'	'	'	'	'	21	27	20
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	51	54	42
Net capital expenditures	51	'	'	'	58	'	'	'	51	58	41
Total assets	383	'	'	'	343	'	'	'	383	343	288
Long-lived assets	$485	'	'	'	$428	'	'	'	$485	$428	$354

Quarterly_Financial_Data_Summa

Quarterly Financial Data -Summarized Quarterly Financial Data (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$657	$658	$815	$631	$827	$677	$775	$910	$2,761	$3,189	$3,882
Operating costs and expenses	1,098	687	689	710	758	680	673	834	'	'	'
Income (loss) from continuing operations	-984	-116	22	-113	-103	-63	-29	-38	1,185	-245	-160
Net income (loss)	-984	-116	22	-113	-104	-61	-6	-40	-1,191	-211	-292
Amounts attributable to WPX Energy:	'	'	'	'	'	'	'	'	'	'	'
Net income (loss)	($973)	($114)	$18	($116)	($106)	($64)	($10)	($43)	($1,185)	($223)	($302)
Basic and diluted earnings (loss) per common share:	'	'	'	'	'	'	'	'	'	'	'
Income (loss) from continuing operations (in dollars per share)	($4.85)	($0.57)	$0.09	($0.58)	($0.53)	($0.33)	($0.17)	($0.21)	($5.91)	($1.23)	($0.81)

Quarterly_Financial_Data_Addit

Quarterly Financial Data - Additional Information (Detail) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 31, 2013

Dec. 31, 2013

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Powder River Basin

Kokopelli area of Piceance Basin

Kokopelli area of Piceance Basin

Quarterly Financial Data [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment Of Costs Of Producing Properties, Acquired Unproved Reserves, leasehold, and equity method investment

$1,373

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of producing properties and costs of acquired unproved reserves

'

'

'

1,055

225

367

'

85

65

52

91

85

102

69

19

Gain on sale of Powder River Basin deep rights leasehold

'

'

'

-36

0

0

-36

-36

'

'

'

'

'

'

'

Buyout of transportation agreement

9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Litigation Liability

'

7

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of producing properties and costs of acquired unproved reserves (Note 6)

'

'

$108

$1,055

[1],[2]

$225

[1],[3]

$367

[1],[4]

'

'

'

'

'

'

'

'

'

[1]

Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.

[2]

As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

[3]

As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

[4]

As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Supplementary Information [Line Items]	'	'		'		'
Operations representing total domestic and international proved reserves	'	5.00%		'		'
Equipment and facilities in support of oil and gas production excluded from capitalization	'	$329		$365		'
Equity earnings from the international equity method investee	'	23		30		24
Impairment of oil and gas properties	108	1,055	[1],[2]	225	[1],[3]	367	[1],[4]
Computation of natural gas reserves	'	'Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.		'		'
Weighted average natural gas price	'	3.63		3.01		4.41
Weighted average oil per barrel price	'	92.16		82.32		86.87
Discount rate	'	10.00%		'		'
International	'	'		'		'
Supplementary Information [Line Items]	'	'		'		'
Noncontrolling interest, percentage	31.00%	31.00%		31.00%		31.00%
Interest in Petrolera Entre Lomas S.A.	'	40.80%		'		'
Entity's Share of International Equity Method Investee	'	'		'		'
Supplementary Information [Line Items]	'	'		'		'
Interest in Petrolera Entre Lomas S.A.	40.80%	40.80%		40.80%		40.80%
Appalachian Basin	'	'		'		'
Supplementary Information [Line Items]	'	'		'		'
Impairment of oil and gas properties	'	$317		'		'
All products | Domestic	'	'		'		'
Supplementary Information [Line Items]	'	'		'		'
Proved developed reserves, revisions	'	133,000,000		'		'
Proved undeveloped reserves, revisions	'	44,000,000		'		'
Additions due to added drill locations	'	127,000,000		225,000,000		306,000,000
Additions due to new undeveloped locations	'	407,000,000		405,000,000		760,000,000
[1]	Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
[2]	As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
[3]	As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
[4]	As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

Supplemental_Oil_and_Gas_Discl3

Supplemental Oil and Gas Disclosures - Capitalization Cost (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Capitalized Expedition Cost Related To Specific Assets [Line Items]	'	'
Proved Properties	$11,699	$11,605
Unproved properties	423	1,162
Total property costs	12,122	12,767
Accumulated depreciation, depletion and amortization and valuation provisions	-5,264	-4,773
Net capitalized costs	6,858	7,994
Domestic	'	'
Capitalized Expedition Cost Related To Specific Assets [Line Items]	'	'
Proved Properties	11,349	11,295
Unproved properties	414	1,153
Total property costs	11,763	12,448
Accumulated depreciation, depletion and amortization and valuation provisions	-5,070	-4,612
Net capitalized costs	6,693	7,836
International	'	'
Capitalized Expedition Cost Related To Specific Assets [Line Items]	'	'
Proved Properties	350	310
Unproved properties	9	9
Total property costs	359	319
Accumulated depreciation, depletion and amortization and valuation provisions	-194	-161
Net capitalized costs	165	158
Entity's share of international equity method investee	'	'
Capitalized Expedition Cost Related To Specific Assets [Line Items]	'	'
Proved Properties	330	292
Unproved properties	2	1
Total property costs	332	293
Accumulated depreciation, depletion and amortization and valuation provisions	-195	-181
Net capitalized costs	$137	$112

Supplemental_Oil_and_Gas_Discl4

Supplemental Oil and Gas Disclosures - Cost Incurred (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Acquisition	$0	'	'
Domestic	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Acquisition	57	111	45
Exploration	104	23	31
Development	939	1,130	1,461
Total costs incurred	1,100	1,264	1,537
International	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Acquisition	0	0	0
Exploration	16	31	20
Development	36	35	24
Total costs incurred	52	66	44
Entity's share of international equity method investee	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Acquisition	0	0	0
Exploration	3	5	8
Development	34	35	26
Total costs incurred	$37	$40	$34

Supplemental_Oil_and_Gas_Discl5

Supplemental Oil and Gas Disclosures - Results of Operation (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	$1,937	$2,228	$2,425
Net gain (loss) on derivatives not designated as hedges	-57	66	'
Other revenues	22	8	11
Lease and facility operating	308	283	262
Gathering, processing and transportation	433	506	487
Taxes other than income	141	111	134
Exploration	431	83	126
Depreciation, depletion and amortization	940	966	902
Impairment of certain natural gas properties	902	48	276
Impairment of costs of acquired unproved reserves	153	177	91
Gain on sale of Powder River Basin deep rights leasehold	-36	0	0
General and administrative	282	281	258
Other (income) expense	17	14	0
Total costs	3,571	2,469	2,536
Results of operations	-1,634	-241	-111
Provision (benefit) for income taxes	-610	-88	-41
Exploration and production net income (loss)	-1,024	-153	-70
Natural Gas	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	1,093	1,364	1,694
Oil and Condensate Sales	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	649	491	312
Natural Gas Liquids	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	230	299	408
Domestic	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	1,785	2,091	2,315
Net gain (loss) on derivatives not designated as hedges	-57	66	'
Other revenues	6	7	7
Lease and facility operating	271	251	235
Gathering, processing and transportation	430	504	487
Taxes other than income	117	87	113
Exploration	424	72	123
Depreciation, depletion and amortization	906	939	880
Impairment of certain natural gas properties	899	48	276
Impairment of costs of acquired unproved reserves	153	177	91
Gain on sale of Powder River Basin deep rights leasehold	-36	'	'
General and administrative	268	267	246
Other (income) expense	17	14	-3
Total costs	3,449	2,359	2,448
Results of operations	-1,664	-268	-133
Provision (benefit) for income taxes	-621	-98	-49
Exploration and production net income (loss)	-1,043	-170	-84
Domestic | Natural Gas	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	1,074	1,346	1,678
Domestic | Oil and Condensate Sales	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	534	376	226
Domestic | Natural Gas Liquids	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	228	296	404
International	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	152	137	110
Net gain (loss) on derivatives not designated as hedges	0	0	'
Other revenues	16	1	4
Lease and facility operating	37	32	27
Gathering, processing and transportation	3	2	0
Taxes other than income	24	24	21
Exploration	7	11	3
Depreciation, depletion and amortization	34	27	22
Impairment of certain natural gas properties	3	0	0
Impairment of costs of acquired unproved reserves	0	0	0
Gain on sale of Powder River Basin deep rights leasehold	0	'	'
General and administrative	14	14	12
Other (income) expense	0	0	3
Total costs	122	110	88
Results of operations	30	27	22
Provision (benefit) for income taxes	11	10	8
Exploration and production net income (loss)	19	17	14
International | Natural Gas	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	19	18	16
International | Oil and Condensate Sales	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	115	115	86
International | Natural Gas Liquids	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	$2	$3	$4

Supplemental_Oil_and_Gas_Discl6

Supplemental Oil and Gas Disclosures - Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	MMcf		MMcf		MMcf
Natural Gas	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	3,458,700		4,108,900		4,036,700
Revisions	303,500		-441,300		-283,200
Purchases	'		5,800		8,000
Divestitures	-200		-217,000		-12,800
Extensions and discoveries	331,400		422,300		790,800
Production	-369,800		-420,000		-430,600
Proved reserves ending balance	3,723,600		3,458,700		4,108,900
Proved developed reserves	2,325,300		2,228,000		2,574,200
Proved undeveloped reserves	1,398,300		1,230,700		1,534,700
Oil and Condensate Sales	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	97.9		70.6		49.6
Revisions	1.1		3.4		-0.4
Divestitures	'		-0.3		'
Extensions and discoveries	29.7		31.7		27.1
Production	-8.8		-7.5		-5.7
Proved reserves ending balance	119.9		97.9		70.6
Proved developed reserves	47.3		36.2		28
Proved undeveloped reserves	72.6		61.7		42.6
Natural Gas Liquids	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	111.9		135.7		97.9
Revisions	-25.4		-21.1		22.8
Purchases	'		-1		0.3
Extensions and discoveries	8.2		8.9		25
Production	-7.6		-10.6		-10.3
Proved reserves ending balance	87.1		111.9		135.7
Proved developed reserves	49.6		66		73.3
Proved undeveloped reserves	37.5		45.9		62.4
All products	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	4,717,200,000	[1]	5,346,900,000	[1]	4,921,600,000	[1]
Revisions	158,000,000	[1]	-548,400,000	[1]	-148,900,000	[1]
Purchases	'		5,800,000	[1]	9,900,000	[1]
Divestitures	-500,000	[1]	-224,800,000	[1]	-12,800,000	[1]
Extensions and discoveries	559,200,000	[1]	666,100,000	[1]	1,103,400,000	[1]
Production	-468,500,000	[1]	-528,400,000	[1]	-526,300,000	[1]
Proved reserves ending balance	4,965,400,000	[1]	4,717,200,000	[1]	5,346,900,000	[1]
Proved developed reserves	2,906,700,000	[1]	2,841,500,000	[1]	3,182,200,000	[1]
Proved undeveloped reserves	2,058,700,000	[1]	1,875,700,000	[1]	2,164,700,000	[1]
Domestic | Natural Gas	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	3,369,100		3,982,900		3,914,200
Revisions	308,300		-404,800		-279,400
Purchases	'		5,800		8,000
Divestitures	-200		-217,000		-12,800
Extensions and discoveries	312,000		409,200		769,700
Production	-359,400		-407,000		-416,800
Proved reserves ending balance	3,629,800		3,369,100		3,982,900
Proved developed reserves	2,265,200		2,170,700		2,497,300
Proved undeveloped reserves	1,364,600		1,198,400		1,485,600
Domestic | Oil and Condensate Sales	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	76.5		47.1		24.3
Revisions	3.5		5.6		1.2
Divestitures	'		-0.3		'
Extensions and discoveries	28.8		28.5		24.3
Production	-5.9		-4.4		-2.7
Proved reserves ending balance	102.9		76.5		47.1
Proved developed reserves	36.8		23.7		13.6
Proved undeveloped reserves	66.1		52.8		33.5
Domestic | Natural Gas Liquids	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	110.4		134		95.8
Revisions	-25.4		-21.1		23
Purchases	'		-1		0.3
Extensions and discoveries	8.1		8.9		25
Production	-7.4		-10.4		-10.1
Proved reserves ending balance	85.7		110.4		134
Proved developed reserves	48.6		64.9		72.1
Proved undeveloped reserves	37.1		45.5		61.9
Domestic | All products	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	4,490,500,000	[1]	5,070,100,000	[1]	4,635,000,000	[1]
Revisions	177,200,000	[1]	-498,600,000	[1]	-134,300,000	[1]
Purchases	'		5,800,000	[1]	9,900,000	[1]
Divestitures	-500,000	[1]	-224,800,000	[1]	-12,800,000	[1]
Extensions and discoveries	533,800,000	[1]	633,800,000	[1]	1,065,500,000	[1]
Production	-439,400,000	[1]	-495,800,000	[1]	-493,200,000	[1]
Proved reserves ending balance	4,761,600,000	[1]	4,490,500,000	[1]	5,070,100,000	[1]
Proved developed reserves	2,777,700,000	[1]	2,702,600,000	[1]	3,011,500,000	[1]
Proved undeveloped reserves	1,983,900,000	[1]	1,787,900,000	[1]	2,058,600,000	[1]
International | Natural Gas	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	54,100		75,000		74,300
Revisions	-1,700		-18,000		200
Purchases	'		0		0
Divestitures	0		0		0
Extensions and discoveries	18,500		5,700		9,600
Production	-7,100		-8,600		-9,100
Proved reserves ending balance	63,800		54,100		75,000
Proved developed reserves	41,400		36,500		48,400
Proved undeveloped reserves	22,400		17,600		26,600
International | Oil and Condensate Sales	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	10.8		11.3		11.9
Revisions	-1.6		-1.1		-0.7
Divestitures	'		0		'
Extensions and discoveries	0.9		2.1		1.5
Production	-1.4		-1.5		-1.4
Proved reserves ending balance	8.7		10.8		11.3
Proved developed reserves	5.2		6.1		6.8
Proved undeveloped reserves	3.5		4.7		4.5
International | Natural Gas Liquids	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	0.7		0.8		1
Revisions	0		0		-0.1
Purchases	'		0		0
Extensions and discoveries	0.1		0		0
Production	-0.1		-0.1		-0.1
Proved reserves ending balance	0.7		0.7		0.8
Proved developed reserves	0.5		0.5		0.6
Proved undeveloped reserves	0.2		0.2		0.2
International | All products	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	122,800,000	[1]	147,200,000	[1]	151,400,000	[1]
Revisions	-11,300,000	[1]	-24,700,000	[1]	-4,600,000	[1]
Purchases	'		0	[1]	0	[1]
Divestitures	0	[1]	0	[1]	0	[1]
Extensions and discoveries	24,500,000	[1]	18,300,000	[1]	18,600,000	[1]
Production	-16,200,000	[1]	-18,000,000	[1]	-18,200,000	[1]
Proved reserves ending balance	119,800,000	[1]	122,800,000	[1]	147,200,000	[1]
Proved developed reserves	75,500,000	[1]	76,100,000	[1]	93,000,000	[1]
Proved undeveloped reserves	44,300,000	[1]	46,700,000	[1]	54,200,000	[1]
Entity's Share of International Equity Method Investee | Natural Gas	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	35,500		51,000		48,200
Revisions	-3,100		-18,500		-4,000
Purchases	'		0		0
Divestitures	0		0		0
Extensions and discoveries	900		7,400		11,500
Production	-3,300		-4,400		-4,700
Proved reserves ending balance	30,000		35,500		51,000
Proved developed reserves	18,700		20,800		28,500
Proved undeveloped reserves	11,300		14,700		22,500
Entity's Share of International Equity Method Investee | Oil and Condensate Sales	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	10.6		12.2		13.4
Revisions	-0.8		-1.1		-0.9
Divestitures	'		0		'
Extensions and discoveries	0		1.1		1.3
Production	-1.5		-1.6		-1.6
Proved reserves ending balance	8.3		10.6		12.2
Proved developed reserves	5.3		6.4		7.6
Proved undeveloped reserves	3		4.2		4.6
Entity's Share of International Equity Method Investee | Natural Gas Liquids	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	0.8		0.9		1.1
Revisions	0		0		-0.1
Purchases	'		0		0
Extensions and discoveries	0		0		0
Production	-0.1		-0.1		-0.1
Proved reserves ending balance	0.7		0.8		0.9
Proved developed reserves	0.5		0.6		0.6
Proved undeveloped reserves	0.2		0.2		0.3
Entity's Share of International Equity Method Investee | All products	'		'		'
Supplementary Information [Line Items]	'		'		'
Proved reserves beginning balance	103,900,000	[1]	129,600,000	[1]	135,200,000	[1]
Revisions	-7,900,000	[1]	-25,100,000	[1]	-10,000,000	[1]
Purchases	'		0	[1]	0	[1]
Divestitures	0	[1]	0	[1]	0	[1]
Extensions and discoveries	900,000	[1]	14,000,000	[1]	19,300,000	[1]
Production	-12,900,000	[1]	-14,600,000	[1]	-14,900,000	[1]
Proved reserves ending balance	84,000,000	[1]	103,900,000	[1]	129,600,000	[1]
Proved developed reserves	53,500,000	[1]	62,800,000	[1]	77,700,000	[1]
Proved undeveloped reserves	30,500,000	[1]	41,100,000	[1]	51,900,000	[1]
[1]	Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Supplemental_Oil_and_Gas_Discl7

Supplemental Oil and Gas Disclosures - Proved Reserves (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013
Disclosure Proved Reserves [Abstract]	'
Conversion Rate Of Oil And Ngl Quantities	'Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Supplemental_Oil_and_Gas_Discl8

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Domestic	'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'
Future cash inflows	$24,547		$18,435
Future production costs	12,148		9,836
Future development costs	3,789		3,217
Future income tax provisions	2,147		1,059
Future net cash flows	6,463		4,323
Less 10 percent annual discount for estimated timing of cash flows	-3,499		-2,374
Standardized measure of discounted future net cash inflows	2,964		1,949
International	'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'
Future cash inflows	866	[1]	968	[1]
Future production costs	360	[1]	385	[1]
Future development costs	136	[1]	136	[1]
Future income tax provisions	72	[1]	97	[1]
Future net cash flows	298	[1]	350	[1]
Less 10 percent annual discount for estimated timing of cash flows	-118	[1]	-136	[1]
Standardized measure of discounted future net cash inflows	180	[1]	214	[1]
Entity's Share of International Equity Method Investee	'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'
Future cash inflows	733	[2]	892	[2]
Future production costs	297	[2]	356	[2]
Future development costs	109	[2]	115	[2]
Future income tax provisions	95	[2]	104	[2]
Future net cash flows	232	[2]	317	[2]
Less 10 percent annual discount for estimated timing of cash flows	-85	[2]	-118	[2]
Standardized measure of discounted future net cash inflows	$147	[2]	$199	[2]
[1]	Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
[2]	Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.

Supplemental_Oil_and_Gas_Discl9

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
International	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Noncontrolling interest, percentage	31.00%	31.00%	31.00%
Interest in Petrolera Entre Lomas S.A.	40.80%	'	'
Entity's Share of International Equity Method Investee	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Interest in Petrolera Entre Lomas S.A.	40.80%	40.80%	40.80%

Recovered_Sheet1

Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Domestic	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Standardized measure of discounted future net cash flows beginning of period	$1,949	$3,591	$2,814
Sales of oil and gas produced, net of operating costs	-1,040	-778	-1,194
Net change in prices and production costs	1,198	-3,601	495
Extensions, discoveries and improved recovery, less estimated future costs	1,282	1,154	1,661
Development costs incurred during year	414	333	593
Changes in estimated future development costs	-736	50	-750
Purchase of reserves in place, less estimated future costs	'	4	15
Sale of reserves in place, loss estimated future costs	-3	-272	-20
Revisions of previous quantity estimates	239	-232	-209
Accretion of discount	225	481	395
Net change in income taxes	-540	1,194	-226
Other	-24	25	17
Net changes	1,015	-1,642	777
Standardized measure of discounted future net cash flows end of period	2,964	1,949	3,591
International	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Standardized measure of discounted future net cash flows beginning of period	214	199	198
Sales of oil and gas produced, net of operating costs	-77	-78	-64
Net change in prices and production costs	-5	46	26
Extensions, discoveries and improved recovery, less estimated future costs	0	0	0
Development costs incurred during year	37	35	23
Changes in estimated future development costs	-27	-16	-32
Purchase of reserves in place, less estimated future costs	'	0	0
Sale of reserves in place, loss estimated future costs	0	0	0
Revisions of previous quantity estimates	-17	-3	22
Accretion of discount	28	26	25
Net change in income taxes	27	5	6
Other	0	0	-5
Net changes	-34	15	1
Standardized measure of discounted future net cash flows end of period	180	214	199
Entity's Share of International Equity Method Investee	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Standardized measure of discounted future net cash flows beginning of period	199	197	186
Sales of oil and gas produced, net of operating costs	-71	-78	-61
Net change in prices and production costs	17	49	29
Extensions, discoveries and improved recovery, less estimated future costs	0	0	0
Development costs incurred during year	34	35	25
Changes in estimated future development costs	-16	-17	-30
Purchase of reserves in place, less estimated future costs	'	0	0
Sale of reserves in place, loss estimated future costs	0	0	0
Revisions of previous quantity estimates	-61	-26	18
Accretion of discount	27	27	26
Net change in income taxes	18	12	4
Other	0	0	0
Net changes	-52	2	11
Standardized measure of discounted future net cash flows end of period	$147	$199	$197

Recovered_Sheet2

Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
International	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Noncontrolling interest, percentage	31.00%	31.00%	31.00%
Interest in Petrolera Entre Lomas S.A.	40.80%	'	'
Entity's Share of International Equity Method Investee	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Interest in Petrolera Entre Lomas S.A.	40.80%	40.80%	40.80%

Schedule_II_Valuation_And_Qual1

Schedule II - Valuation And Qualifying Accounts (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for doubtful accounts - accounts and notes receivable	'		'		'
Movement in Valuation Allowances and Reserves [Roll Forward]	'		'		'
Beginning Balance	$11	[1]	$13	[1]	$16	[1]
Charged (Credited) to Costs and Expenses	-3		-2	[1]	-1	[1]
Other	'	[1]	'	[1]	'	[1]
Deductions	-1	[1]	0	[1]	-2	[1]
Ending Balance	7	[1]	11	[1]	13	[1]
Deferred tax asset valuation allowance	'		'		'
Movement in Valuation Allowances and Reserves [Roll Forward]	'		'		'
Beginning Balance	19	[1]	16	[1]	22	[1]
Charged (Credited) to Costs and Expenses	80	[1]	3	[1]	0	[1]
Other	3	[1]	'	[1]	'	[1]
Deductions	0	[1]	0	[1]	-6	[1],[2]
Ending Balance	$102	[1]	$19	[1]	$16	[1]
[1]	Deducted from related assets.
[2]	Deferred tax asset retained by Williams.