WPX Energy (WPX) 10-Q 4 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 04, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Trading Symbol	WPX
Entity Registrant Name	WPX ENERGY, INC.
Entity Central Index Key	1,518,832
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		344,335,596

Consolidated Balance Sheet (Una

Consolidated Balance Sheet (Unaudited) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 1,031	$ 38
Accounts receivable, net of allowance of $6 million as of June 30, 2016 and December 31, 2015		192	300
Derivative assets, current		101	308
Inventories		37	46
Assets classified as held for sale, current		8	178
Other		26	23
Total current assets		1,395	893
Properties and equipment (successful efforts method of accounting)		8,602	8,415
Less—accumulated depreciation, depletion and amortization		(2,184)	(1,893)
Properties and equipment, net		6,418	6,522
Derivative assets, noncurrent		21	51
Disposal Group, Including Discontinued Operation, Assets, Noncurrent		0	894
Other noncurrent assets		28	33
Total assets		7,862	8,393
Current liabilities:
Accounts payable		226	278
Accrued and other current liabilities		264	301
Liabilities associated with assets held for sale		2	140
Current portion of long-term debt, net	[1]	160	1
Derivative liabilities, current		45	13
Total current liabilities		697	733
Deferred income taxes		390	465
Long-term debt, net	[2]	2,572	3,189
Derivative liabilities, noncurrent		44	2
Asset retirement obligations		101	99
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		0	133
Other noncurrent liabilities		200	237
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; 7 million shares issued at June 30, 2016 and December 31, 2015)		339	339
Common stock (2 billion shares authorized at $0.01 par value; 334.0 million shares issued at June 30, 2016 and 275.4 million shares issued at December 31, 2015)		3	3
Additional paid-in-capital		6,697	6,164
Accumulated deficit		(3,181)	(2,971)
Total stockholders’ equity		3,858	3,535
Total liabilities and equity		$ 7,862	$ 8,393
[1]	(a) Includes debt issuance costs.
[2]	(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Consolidated Balance Sheet (Un3

Consolidated Balance Sheet (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 6	$ 6
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred Stock, Shares Issued	7,000,000	7,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued	334,008,366	275,400,000

Consolidated Statement of Opera

Consolidated Statement of Operations (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015	Jun. 30, 2016		Jun. 30, 2015
Product revenues:
Oil sales	$ 142		$ 138	$ 239		$ 250
Natural gas sales	24		26	49		67
Natural gas liquid sales	10		5	15		8
Total product revenues	176		169	303		325
Gas management	116		56	147		213
Net gain (loss) on derivatives (Note 12)	(154)		(71)	(97)		34
Other	0		0	1		2
Total revenues	138		154	354		574
Costs and expenses:
Lease and facility operating	41		32	83		67
Gathering, processing and transportation	20		16	36		33
Taxes other than income	16		16	27		31
Gas management	132		58	171		167
Exploration (Note 5)	12		6	21		13
Depreciation, depletion and amortization	163		123	315		240
Net (gain) loss on sales of assets	(4)		(208)	(202)		(277)
General and administrative	55		53	108		107
Other—net	2		3	4		25
Total costs and expenses	437		99	563		406
Operating income (loss)	(299)		55	(209)		168
Interest expense	(53)		(32)	(110)		(65)
Investment income and other	(1)		1	1		2
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(353)		24	(318)		105
Provision (benefit) for income taxes (Note 8)	(130)		1	(95)		30
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	(223)		23	(223)		75
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	25		(53)	13		(37)
Net income (loss)	(198)		(30)	(210)		38
Less: Net income (loss) attributable to noncontrolling interests	0		0	0		1
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(198)		(30)	(210)		37
Preferred Stock Dividends, Income Statement Impact	6		0	11		0
Net Income (Loss) Available to Common Stockholders, Basic	(204)		(30)	(221)		37
Amounts attributable to WPX Energy, Inc. common stockholders:
Income (Loss) from Continuing Operations Attributable to Parent	(229)		23	(234)		75
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 25		$ (53)	$ 13		$ (38)
Income (Loss) from Continuing Operations, Per Basic Share	$ (0.76)		$ 0.11	$ (0.81)		$ 0.37
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0.08		(0.25)	0.04		(0.19)
Earnings Per Share, Basic	$ (0.68)		$ (0.14)	$ (0.77)		$ 0.18
Weighted Average Number of Shares Outstanding, Basic	300.7		205	288.2		204.6
Income (Loss) from Continuing Operations, Per Diluted Share	$ (0.76)		$ 0.11	$ (0.81)		$ 0.37
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0.08		(0.25)	0.04		(0.19)
Earnings Per Share, Diluted	$ (0.68)		$ (0.14)	$ (0.77)		$ 0.18
Weighted Average Number of Shares Outstanding, Diluted	300.7	[1]	206.8	288.2	[1]	206.4
[1]	For the three and six months ended June 30, 2016, 1.1 million and 1.6 million, respectively, weighted-average nonvested restricted stock units and awards and 34.7 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) $ in Millions	Preferred Stock	Common Stock	Additional Paid-In- Capital	Accumulated Deficit	Total Stockholders’ Equity
December 31, 2015 at Dec. 31, 2015	$ 339	$ 3	$ 6,164	$ (2,971)	$ 3,535
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss) Attributable to Parent				(210)	(210)
Stock based compensation			6		6
Stock Issued During Period, Value, New Issues			538		538
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings			(11)		(11)
June 30, 2016 at Jun. 30, 2016	$ 339	$ 3	$ 6,697	$ (3,181)	$ 3,858

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015
Operating Activities(a)
Comprehensive income (loss) attributable to WPX Energy, Inc.		$ (210)	$ 38
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation Depletion And Amortization Including Discontinued Portion		324	443
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations		(82)	(17)
Provision for impairment of properties and equipment (including certain exploration expenses)		19	26
Net gain (loss) on derivatives (Note 12)		97	(34)
Derivative, Cash Received on Hedge		202	267
Amortization of stock-based awards		17	20
Net gain on sales of domestic assets and international interests		(254)	(318)
Unrealized Loss on Derivatives, including Discontinued Operations		46	0
Cash provided (used) by operating assets and liabilities:
Accounts receivable		102	176
Inventories		9	(2)
Margin deposits and customer margin deposits payable		0	21
Other current assets		3	(4)
Accounts payable		(28)	(145)
Income taxes payable		(33)	0
Accrued and other current liabilities		(103)	(33)
Accrued liabilities established in 2015 for retained transportation and gathering contracts related to discontinued operations		(30)	0
Other, including changes in other noncurrent assets and liabilities		6	(8)
Net cash provided by operating activities(a)	[1]	85	430
Investing Activities(a)
Capital expenditures	[2]	(291)	(679)
Proceeds from sales of domestic assets and international interests		1,139	772
Other		(4)	2
Net cash provided by (used in) investing activities(a)	[1]	844	95
Financing Activities
Proceeds from common stock		540	2
Dividends paid on preferred stock		(11)	0
Borrowings on credit facility		380	181
Payments on credit facility		(645)	(461)
Payments for retirement of debt		(196)	0
Payments for credit facility amendment fees		(3)	0
Other		(1)	0
Net cash provided by (used in) financing activities		64	(278)
Net increase (decrease) in cash and cash equivalents		993	247
Cash and Cash Equivalents, at Carrying Value, Including Discontinued Operations		38	70
Cash and cash equivalents at end of period		1,031	317
Increase to properties and equipment		(264)	(435)
Changes in related accounts payable and accounts receivable		(27)	(244)
Energy Related Derivative [Member]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain (loss) on derivatives (Note 12)	[3]	97	(54)
Derivative, Cash Received on Hedge		$ (201)	$ (295)
[1]	Amounts reflect activity related to discontinued operations. See Note 3 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
[2]	(b) Increase to properties and equipment(264) (435)Changes in related accounts payable and accounts receivable(27) (244)Capital expenditures(291) (679)
[3]	Includes settlements totaling $69 million and $137 million for the three months ended June 30, 2016 and 2015, respectively; and settlements totaling $201 million and $295 million for the six months ended June 30, 2016 and 2015, respectively.

Basis of Presentation and Descr

Basis of Presentation and Description of Business	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation and Description of Business	Basis of Presentation and Description of Business Description of Business Operations of our company include oil, natural gas and NGL development, production, and gas management activities primarily located in Texas, North Dakota, New Mexico and Colorado. We specialize in development and production from tight-sands and shale formations in the Delaware, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period (see Note 3 ). In addition, we had operations in the Piceance Basin in Colorado, which were sold April 8, 2016. We also had operations for a portion of 2015 in the Powder River Basin in Wyoming, which were sold on September 1, 2015 and, until January 29, 2015, we had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia. For all periods presented, the results of the Piceance Basin, Powder River Basin and Apco are reported as discontinued operations. The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.” Basis of Presentation The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2015 in Exhibit 99.1 of our Form 8-K filed on May 25, 2016. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2016 , results of operations for the three and six months ended June 30, 2016 and 2015 , changes in equity for the six months ended June 30, 2016 and cash flows for the six months ended June 30, 2016 and 2015 . The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Our continuing operations comprise a single business segment, which includes the development, production and gas management activities of oil, natural gas and NGLs in the United States. Discontinued Operations On February 8, 2016, we signed an agreement to sell our Piceance Basin operations to Terra Energy Partners LLC (“Terra”) for $910 million . This transaction closed on April 8, 2016 and we received net proceeds of $862 million . The results of operations of the Piceance Basin have been reported as discontinued operations on the Consolidated Statements of Operations (see Note 3 ). In addition, our discontinued operations include the results of the Powder River Basin sold in September 2015 and the results of our international interests sold in January 2015. See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 9 for a discussion of contingencies related to the former power business of The Williams Companies, Inc. (“Williams”) (most of which was disposed of in 2007). Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, and has updated with additional ASUs. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09, as amended, is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's Consolidated Financial Statements or related disclosures. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Company does not expect the adoption of ASU 2014-15 to have a significant impact on the Company’s Consolidated Financial Statements or related disclosures. In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, enhancing the reporting model for financial instruments. The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is only permitted under specific circumstances. The Company is currently evaluating the impact, if any, of ASU 2016-01 to the Company's Consolidated Financial Statements or related disclosures. In February 2016, the FASB issued ASU 2016-02, Leases, to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. The Company is currently evaluating the impact, if any, of ASU 2016-02 to the Company's Consolidated Financial Statements or related disclosures. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, as part of the Simplification Initiative. The areas for simplification in ASU 2016-09 involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. The Company is currently evaluating the impact, if any, of ASU 2016-09 to the Company's Consolidated Financial Statements or related disclosures.

Acquisitions (Notes)

Acquisitions (Notes)	6 Months Ended
	Jun. 30, 2016
Business Acquisition, Pro Forma Information [Abstract]
Acquisition [Text Block]	Acquisition On August 17, 2015, we completed the acquisition of privately held RKI Exploration & Production, LLC (“RKI”) (the “Acquisition”). The Acquisition qualified as a business combination and, as a result, we estimated the fair value of the underlying shares distributed, the assets acquired and the liabilities assumed as of the August 17, 2015 acquisition date as disclosed in Exhibit 99.1 of our Form 8-K filed on May 25, 2016. The following table presents the unaudited pro forma financial results for the three and six months ended June 30, 2015 as if the Acquisition and related financings had been completed January 1, 2015. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the date assumed or for the period presented, nor is such information indicative of the Company’s expected future results of operations. Three months Six months 2015 2015 (Millions) Revenues $ 198 $ 689 Net income from continuing operations attributable to WPX Energy, Inc. $ 6 $ 50

Discontinued Operations Discont

Discontinued Operations Discontinued Operations (Notes)	6 Months Ended
	Jun. 30, 2016
Discontinued operations [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Discontinued Operations On February 8, 2016, we signed an agreement with Terra to sell WPX Energy Rocky Mountain, LLC that holds our Piceance Basin operations for $910 million . The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain, LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million resulting in a gain of $52 million , subject to post-closing adjustments. We are performing certain transition services for the buyer which end during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in gas management revenue and expenses. The Piceance Basin operations are included in our domestic results presented below. Also included in the domestic results for 2015 are the operations in the Powder River Basin sold in October 2015. On May 25, 2016, we signed an agreement to buy out the remaining transportation obligations related to our Piceance Basin operations for $239 million which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment. The total commitments related to these obligations for the remainder of 2016 and thereafter were approximately $400 million as of June 30, 2016. The transaction closed July 19, 2016 and will result in a loss of $239 million to be recorded in third-quarter 2016 and will be reported in continuing operations. We currently expect the impact of the buyout of these transportation obligations to be reported in cash flow from operating activities in third-quarter 2016. On January 29, 2015, we completed the divestiture of our international interests and received net proceeds of $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date. These non-operated international holdings comprised our international segment. We recorded a pretax gain of $41 million related to this transaction during first quarter 2015. Summarized Results of Discontinued Operations Three months ended June 30, 2016 Three months ended June 30, 2015 Domestic and Total Domestic and Total (Millions) Total revenues(a) $ (4 ) $ 147 Costs and expenses: Lease and facility operating $ 1 $ 26 Gathering, processing and transportation 5 67 Taxes other than income (1 ) 4 Gas management — 1 Depreciation, depletion and amortization — 104 Impairment of assets held for sale — 6 Gain on sales of assets — (1 ) General and administrative 1 11 Other—net 2 2 Total costs and expenses 8 220 Operating income (loss) (12 ) (73 ) Investment income and other — 1 Gain on sale of domestic assets 52 — Income (loss) from discontinued operations before income taxes 40 (72 ) Provision (benefit) for income taxes 15 (19 ) Income (loss) from discontinued operations $ 25 $ (53 ) __________ (a) The three months ended June 30, 2016 includes $13 million net loss on derivatives. Six months ended June 30, 2016 Six months ended June 30, 2015 Domestic and Total Domestic International Total (Millions) Total revenues(a) $ 64 $ 324 $ 15 $ 339 Costs and expenses: Lease and facility operating $ 18 $ 58 $ 4 $ 62 Gathering, processing and transportation 48 137 — 137 Taxes other than income 1 14 3 17 Gas management — 1 — 1 Depreciation, depletion and amortization 9 203 — 203 Impairment of assets held for sale — 16 — 16 Gain on sale of assets — (1 ) — (1 ) General and administrative 8 21 1 22 Other—net 6 6 — 6 Total costs and expenses 90 455 8 463 Operating income (loss) (26 ) (131 ) 7 (124 ) Investment income and other — 3 1 4 Gain on sale of international interests — — 41 41 Gain on sale of domestic assets 52 — — — Income (loss) from discontinued operations before income taxes 26 (128 ) 49 (79 ) Provision (benefit) for income taxes(b) 13 (39 ) (3 ) (42 ) Income (loss) from discontinued operations $ 13 $ (89 ) $ 52 $ (37 ) __________ (a) The six months ended June 30, 2016 includes $33 million net loss on derivatives. (b) The six months ended June 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the six months ended June 30, 2015 includes the reversal of certain U.S. deferred tax liabilities associated with Apco. Assets and Liabilities in the Consolidated Balance Sheets attributable to Discontinued Operations The assets held for sale and liabilities associated with assets held for sale on the Consolidated Balance Sheet as of June 30, 2016 relate to certain assets and liabilities in the Appalachia Basin. The operations of the Appalachia Basin are reported in continuing operations. As of December 31, 2015, the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin operations. December 31, 2015 Total Assets classified as held for sale Current assets: Accounts receivable (including an affiliate receivable) $ 55 Derivative assets 68 Inventories 13 Other 2 Total current assets 138 Properties and equipment, net(a) 880 Derivative assets 14 Total assets classified as held for sale—discontinued operations $ 1,032 Total assets classified as held for sale—continuing operations (Note 5) 40 Total assets classified as held for sale on the Consolidated Balance Sheets $ 1,072 Liabilities associated with assets held for sale Current liabilities: Accounts payable $ 93 Accrued and other current liabilities 47 Total current liabilities 140 Asset retirement obligations 133 Total liabilities associated with assets held for sale on the Consolidated Balance Sheets $ 273 __________ (a) Includes $2,308 million impairment in Piceance Basin of the net assets. Cash Flows Attributable to Discontinued Operations Excluding income taxes and changes to working capital, total cash provided by domestic operating activities was $29 million and $90 million for the six months ended June 30, 2016 and 2015 , respectively. In addition, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $30 million for the six months ended June 30, 2016 . Cash provided by operating activities related to our international operations was $3 million for the six months ended June 30, 2015 . Total cash used in investing activities related to domestic discontinued operations was $31 million and $170 million for the six months ended June 30, 2016 and 2015 , respectively. Total cash used in investing activities related to our international operations was $15 million for the six months ended June 30, 2015 .

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share from Continuing Operations	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share from Continuing Operations	Earnings (Loss) Per Common Share from Continuing Operations The following table summarizes the calculation of earnings per share. Three months Six months 2016 2015 2016 2015 (Millions, except per-share amounts) Income (loss) from continuing operations attributable to WPX Energy, Inc. $ (223 ) $ 23 $ (223 ) $ 75 Less: Dividends on preferred stock 6 — 11 — Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ (229 ) $ 23 $ (234 ) $ 75 Basic weighted-average shares 300.7 205.0 288.2 204.6 Effect of dilutive securities(a): Nonvested restricted stock units and awards — 1.7 — 1.7 Stock options — 0.1 — 0.1 Diluted weighted-average shares 300.7 206.8 288.2 206.4 Earnings (loss) per common share from continuing operations: Basic $ (0.76 ) $ 0.11 $ (0.81 ) $ 0.37 Diluted $ (0.76 ) $ 0.11 $ (0.81 ) $ 0.37 __________ (a) For the three and six months ended June 30, 2016, 1.1 million and 1.6 million , respectively, weighted-average nonvested restricted stock units and awards and 34.7 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. The table below includes information related to stock options that were outstanding at June 30, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares. June 30, 2016 2015 Options excluded (millions) 2.4 2.0 Weighted-average exercise price of options excluded $ 16.46 $ 17.42 Exercise price range of options excluded $11.75 - $21.81 $13.46 - $21.81 Second quarter weighted-average market price $ 9.02 $ 13.18 For the six months ended June 30, 2016 and 2015, approximately 3.5 million and 1.0 million , respectively, nonvested restricted stock units were antidilutive and were excluded from the computation of diluted weighted-average shares.

Asset Sales, Other Expenses and

Asset Sales, Other Expenses and Exploration Expense	6 Months Ended
	Jun. 30, 2016
Extractive Industries [Abstract]
Asset Sales, Exploration Expenses And Other Accruals [Text Block]	Asset Sales, Other Expenses and Exploration Expenses Asset Sales On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million to a portfolio company of ISQ Global Infrastructure Fund, a fund managed by I Squared Capital. The consideration reflects $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX's development in the Gallup oil play. We are obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. Under the terms of the agreement, WPX will continue to operate, at the direction of the owner, the gathering system for an initial term of two years with the opportunity to continue in ensuing years. The gathering system consists of more than 220 miles of oil, gas and water gathering lines that WPX installed in conjunction with drilling in the Gallup oil play where it made a discovery in 2013. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and an additional gain of $5 million in second-quarter 2016 as certain in-progress construction was completed. As of June 30, 2016, the deferred gain is $26 million related to an estimated $4 million of remaining recorded obligation for in-progress construction. During May 2015, WPX completed the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast for approximately $209 million in cash. The transaction released WPX from various long-term natural gas purchase and sales obligations and future demand payment obligations associated with the transport position. As a result of this transaction, we recorded a net gain of $209 million in second-quarter 2015 on these executory contracts. During the first quarter of 2015, we sold a portion of our Appalachian Basin operations and released certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $288 million , before post-closing adjustments. Including an estimate of post-closing adjustments of $17 million , we recorded a net gain of $69 million in first-quarter 2015. Other Expenses During the first quarter of 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in Other—net on the Consolidated Statements of Operations. Exploration Expenses The following table presents a summary of exploration expenses. Three months Six months 2016 2015 2016 2015 (Millions) Geologic and geophysical costs $ 1 $ 1 $ 1 $ 2 Dry hole costs and impairments of exploratory area well costs 1 — 1 — Unproved leasehold property impairment, amortization and expiration 10 5 19 11 Total exploration expenses $ 12 $ 6 $ 21 $ 13

Inventories

Inventories	6 Months Ended
	Jun. 30, 2016
Inventory Disclosure [Abstract]
Inventories	Inventories The following table presents a summary of our inventories as of the dates indicated below. June 30, December 31, (Millions) Material, supplies and other $ 36 $ 44 Crude oil production in transit 1 2 Total inventories $ 37 $ 46

Debt and Banking Arrangements

Debt and Banking Arrangements	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Debt and Banking Arrangements	Debt and Banking Arrangements The following table presents a summary of our debt as of the dates indicated below. June 30, December 31, (Millions) 5.250% Senior Notes due 2017 $ 160 $ 355 7.500% Senior Notes due 2020 500 500 6.000% Senior Notes due 2022 1,100 1,100 8.250% Senior Notes due 2023 500 500 5.250% Senior Notes due 2024 500 500 Credit facility agreement — 265 Other — 1 Total debt $ 2,760 $ 3,221 Less: Current portion of long-term debt, net(a) 160 1 Total long-term debt $ 2,600 $ 3,220 Less: Debt issuance costs on long-term debt(b) 28 31 Total long-term debt, net(b) $ 2,572 $ 3,189 __________ (a) Includes debt issuance costs. (b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. Senior Notes During the first half of 2016, we repurchased approximately $195 million of our 5.250% Senior Notes due 2017, including $87 million we redeemed through a tender offer. Subsequent to June 30, 2016 , we repurchased $35 million of our Senior Notes due 2017. See Exhibit 99.1 of our Form 8-K filed on May 25, 2016 which includes the financial statements and footnotes for the year ended December 31, 2015 for a discussion of our previously issued senior notes. Credit Facility On March 18, 2016, the Company entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, is now a $1.2 billion senior secured revolving credit facility with a maturity date of October 28, 2019 . The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of June 30, 2016 , we were in compliance with our financial covenants and had full access to the Credit Facility subject to the Borrowing Base discussed below. During any Collateral Trigger Period, loans under the Credit Facility will be subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. As of March 18, 2016, the Borrowing Base was set at $1.025 billion . This Borrowing Base will remain in effect until the next Borrowing Base is re-determined pursuant to the Credit Facility. The next scheduled Re-determination date is October 1, 2016 and biannually thereafter. Subject to the satisfaction of certain conditions set forth in the Credit Facility, during any Collateral Trigger Period (as described below), the Company may designate Loans under the Credit Facility as either General Loans, the proceeds of which may be used for the general purposes described above, or as Development Loans, the proceeds of which shall be used solely for the development of oil and gas property owned or leased by the Company and certain of its subsidiaries. Additionally, during any Collateral Trigger Period, the Loans shall be secured and the obligations outstanding under the Credit Facility shall be guaranteed, in each case, as more particularly described below. On the date of the closing of the Credit Facility a Collateral Trigger Period shall be in effect and all Loans outstanding shall be deemed to be General Loans. The General Loans and the other General Secured Obligations outstanding under the Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Any Development Loans and any Development Secured Obligations shall be secured by certain oil, gas or other mineral properties developed with the proceeds thereof and not otherwise securing the General Secured Obligations. Such obligations will continue to be secured during any Collateral Trigger Period and such security interest shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility. The Collateral Trigger Period means, as applicable, (1) the period beginning on the date of the closing of the Credit Facility, as amended, and ending on the initial Collateral Trigger Termination Date and (2) each period beginning on a Collateral Trigger Date (as described below) and ending on the first Collateral Trigger Termination Date occurring after such Collateral Trigger Date. The Collateral Trigger Date is the first date after any Collateral Trigger Termination Date on which either (1) the Company’s Corporate Rating is Ba3 or lower (or unrated) by Moody’s or BB- or lower (or unrated) by S&P or (2) the Company elects to have the Borrowing Base apply. The Collateral Trigger Termination Date is the first date following the date of the closing of the Credit Facility and the first date following any Collateral Trigger Date, as applicable, on which (1)(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s or (2) both (i) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) is less than or equal to 3.00 to 1.00 and (ii) the Corporate Rating is (A) at least Ba1 by Moody’s and at least BB by S&P or (B) at least Ba2 by Moody’s and at least BB+ by S&P. If the Company elects to have the Borrowing Base apply, the Collateral Trigger Termination Date is the date the Company elects under the terms of the Credit Facility to no longer have the Borrowing Base apply. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings. During any Collateral Trigger Period, the Company is required to maintain a ratio of Consolidated Secured Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 3.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and 3.00 to 1.00 thereafter. During any Collateral Trigger Period, the Company may also not permit the ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter to be less than 1.0 to 1.0. Other than during a Collateral Trigger Period, the Company is required to maintain a ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 4.50 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2016 and 4.00 to 1.00 thereafter, unless at such time the Company’s Corporate Ratings are equal to, or better than, Baa3 or BBB- by at least one of S&P and Moody’s and not less than BB+ or Ba1 by the other such agency. In addition, other than during a Collateral Trigger Period, the ratio of Consolidated Indebtedness to Consolidated Total Capitalization is not permitted to be greater than 60 percent and is applicable for the life of the agreement. Furthermore, other than during a Collateral Trigger Period, the Company may not permit the ratio of Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) to Consolidated Interest Charges to be less than 2.5 to 1.00. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties. The Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments, a change of control and, during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected. If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies. Letters of Credit WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements most of which expire throughout 2016. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility. At June 30, 2016 , a total of $228 million in letters of credit have been issued, a majority of which support interstate pipeline contracts. If these letter of credit agreements are not renewed, we may issue letters of credit under our Credit Facility. As a result of the buyout of our Piceance Basin transportation obligations (see Note 13 ), we expect to eliminate approximately $162 million in letters of credit and their associated annual interest expense.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes The following table presents the provision (benefit) for income taxes from continuing operations. Three months Six months 2016 2015 2016 2015 (Millions) Current: Federal $ — $ — $ — $ — State — 1 — — — 1 — — Deferred: Federal (119 ) 6 (119 ) 33 State (11 ) (6 ) 24 (3 ) (130 ) — (95 ) 30 Total provision (benefit) $ (130 ) $ 1 $ (95 ) $ 30 The effective income tax rate for the three months ended June 30, 2016, differs from the federal statutory rate due to the effects of state income taxes. The effective income tax rate for the six months ended June 30, 2016, differs from the federal statutory rate due to state tax adjustments resulting from the sale of our Piceance Basin operations in Colorado. In the first quarter of 2016, we recorded $8 million of valuation allowances against Colorado loss and credit carryovers generated in prior years. We also increased our state effective tax rate by less than a half percent in the first quarter of 2016 to reflect changes in our expected future apportionment among the states where we continue to operate which resulted in a $14 million increase of our deferred tax liability as of the beginning of the year. The effective income tax rate for the three months and six months ended June 30, 2015, differs from the federal statutory rate due to the effects of state income taxes. We have recorded valuation allowances against deferred tax assets attributable primarily to certain state net operating loss (“NOL”) carryovers as well as our federal capital loss carryover. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. We have not recorded a valuation allowance against our federal NOL carryover, but a valuation allowance could be required in future periods if the federal NOL carryover continues to increase or circumstances change. When assessing the need for a valuation allowance for the federal NOL carryover we primarily consider future reversals of existing taxable temporary differences. The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three -year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of June 30, 2016, we do not believe that an Ownership Change has occurred for WPX, but a change could occur in the future due to shareholders with new positions in our stock greater than 5 percent . An Ownership Change did occur for RKI effective with the Acquisition which resulted in an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the Acquisition. As of June 30, 2016 , the amount of unrecognized tax benefits is not material. During the next 12 months we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of our unrecognized tax benefit. Pursuant to our tax sharing agreement with Williams, we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. We are aware of an issue the IRS has questioned related to our business for which a payment to Williams could be required. We are currently evaluating the issue and the actions we might take should the IRS propose an adjustment. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustment to this deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement.

Contingent Liabilities

Contingent Liabilities	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities	Contingent Liabilities and Commitments Royalty litigation In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs' motion for class certification. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico and violation of the New Mexico Oil and Gas Proceeds Payment Act, and seek declaratory judgment, accounting and injunctive relief. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims. Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in Colorado though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. Environmental matters The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance. Matter related to Williams’ former power business In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications. Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation , holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants' writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time. Other Indemnifications Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreement pursuant to which we divested our Piceance Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. At June 30, 2016 , we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made. In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it. Summary As of June 30, 2016 and December 31, 2015 , the Company had accrued approximately $21 million and $17 million , respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year. Commitments In conjunction with the sale of our San Juan Basin gathering system, our contractual obligations increased for gathering services to be provided by the purchaser over a ten year period. These obligations totaled approximately $366 million as of June 30, 2016. On May 25, 2016, we signed an agreement to buy out the remaining transportation obligations related to our Piceance Basin operations for $239 million which eliminated certain pipeline capacity obligations held by our marketing company with total commitments for the remainder of 2016 and thereafter of approximately $400 million . As of December 31, 2015, our total commitments for pipeline capacity were approximately $686 million . Our total remaining commitments for pipeline capacity after this transaction would be approximately $137 million as of June 30, 2016 for which we previously accrued a liability in third-quarter 2015 in conjunction with the closing of the Powder River Basin sale and exiting the basin. The balance of the liability totaled $105 million as of June 30, 2016.

Stockholder's Equity (Notes)

Stockholder's Equity (Notes)	6 Months Ended
	Jun. 30, 2016
Stockholders' Equity Attributable to Parent [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Note 10 . Stockholders’ Equity On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. See Note 13 for information regarding the conversion of a portion of the 7 million shares of our 6.25% Series A Mandatory Convertible Preferred Stock to our common stock subsequent to June 30, 2016 .

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. June 30, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 122 $ — $ 122 $ — $ 359 $ — $ 359 Energy derivative liabilities $ — $ 89 $ — $ 89 $ — $ 15 $ — $ 15 Total debt(a) $ — $ 2,619 $ — $ 2,619 $ — $ 2,495 $ — $ 2,495 __________ (a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,760 million and $3,220 million as of June 30, 2016 and December 31, 2015 , respectively. Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets. Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions. The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements. Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1. Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, calls or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions 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 over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2018. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis. Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 were a net liability of less than $1 million at June 30, 2016 , and consist primarily of natural gas index transactions that are used to manage our physical requirements. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended June 30, 2016 and 2015 . There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

Derivatives and Concentration o

Derivatives and Concentration of Credit Risk	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Derivatives and Concentration of Credit Risk	Derivatives and Concentration of Credit Risk Energy Commodity Derivatives Risk Management Activities We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of crude oil, natural gas and natural gas liquids attributable to commodity price risk. We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaptions. Derivatives related to production The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of June 30, 2016 . Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Crude Oil Crude Oil Jul -Dec 2016 Fixed Price Swaps WTI (30,712 ) $ 60.16 Crude Oil Jul -Dec 2016 Basis Swaps Midland-Cushing (5,000 ) $ (0.45 ) Crude Oil Jul -Dec 2016 Fixed Price Calls WTI (1,900 ) $ 50.70 Crude Oil 2017 Fixed Price Swaps WTI (22,804 ) $ 50.71 Crude Oil 2017 Swaptions WTI (3,264 ) $ 51.22 Crude Oil 2017 Fixed Price Calls WTI (2,000 ) $ 57.10 Crude Oil 2018 Fixed Price Swaps WTI (3,000 ) $ 60.08 Crude Oil 2018 Fixed Price Calls WTI (5,000 ) $ 58.89 Natural Gas Natural Gas Jul -Dec 2016 Fixed Price Swaps Henry Hub (146 ) $ 3.93 Natural Gas Jul -Dec 2016 Basis Swaps Permian (38 ) $ (0.17 ) Natural Gas Jul -Dec 2016 Basis Swaps San Juan (100 ) $ (0.18 ) Natural Gas 2017 Fixed Price Swaps Henry Hub (90 ) $ 2.82 Natural Gas 2017 Basis Swaps Permian (10 ) $ (0.15 ) Natural Gas 2017 Basis Swaps San Juan (33 ) $ (0.16 ) Natural Gas 2017 Fixed Price Calls Henry Hub (16 ) $ 4.50 Natural Gas 2017 Swaptions Henry Hub (65 ) $ 4.19 Natural Gas 2018 Fixed Price Calls Henry Hub (16 ) $ 4.75 Commodity Period Contract Type Location(d) Notional Volume (b) Weighted Average Physical Derivatives Natural Gas Jul -Dec 2016 Index Multiple (65 ) N/A Natural Gas 2017 Index Multiple (16 ) N/A __________ (a) Derivatives related to crude oil production are fixed price swaps, basis swaps, calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, calls and swaptions. 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) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. (c) The weighted average price for crude oil price is reported in $/Bbl and natural gas is reported in $/MMBtu. (d) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements. (e) 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. June 30, 2016 December 31, 2015 Assets Liabilities Assets Liabilities (Millions) Total derivatives $ 122 $ 89 $ 359 $ 15 We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting on derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives. Three months Six months 2016 2015 2016 2015 (Millions) Gain (loss) from derivatives related to production(a) $ (154 ) $ (68 ) $ (97 ) $ 54 Gain (loss) from derivatives related to physical marketing agreements(b) — (3 ) — (20 ) Net gain (loss) on derivatives not designated as hedges $ (154 ) $ (71 ) $ (97 ) $ 34 __________ (a) Includes settlements totaling $69 million and $137 million for the three months ended June 30, 2016 and 2015 , respectively; and settlements totaling $201 million and $295 million for the six months ended June 30, 2016 and 2015 , respectively. (b) Includes settlements totaling less than $1 million and payments totaling $5 million for the three months ended June 30, 2016 and 2015 , respectively; and settlements totaling $1 million and payments totaling $28 million for the six months ended June 30, 2016 and 2015 , respectively. The cash flow impact of our derivative activities is presented as seperate line items within the operating activities on the Consolidated Statements of Cash Flows. Offsetting of derivative assets and liabilities The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Cash Collateral Posted (Received) Net Amount June 30, 2016 (Millions) Derivative assets with right of offset or master netting agreements $ 122 $ (61 ) $ — $ 61 Derivative liabilities with right of offset or master netting agreements $ (89 ) $ 61 $ — $ (28 ) December 31, 2015 Derivative assets with right of offset or master netting agreements $ 359 $ (14 ) $ — $ 345 Derivative liabilities with right of offset or master netting agreements $ (15 ) $ 14 $ — $ (1 ) __________ (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 June 30, 2016 , we had no collateral posted to derivative counterparties, to support the aggregate fair value of our $28 million net derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of $1 million to our liability balance for our own nonperformance risk. There would have been collateral totaling $28 million 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, at June 30, 2016 . Concentration of Credit Risk Cash equivalents Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less the allowance for 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. 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 2016 and 2015, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The following table presents the gross and net credit exposure from our derivative contracts as of June 30, 2016 . Counterparty Type Gross Total Net Total (Millions) Financial institutions (Investment Grade)(a) $ 122 $ 61 Credit exposure from derivatives $ 122 $ 61 __________ (a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. Our five largest net counterparty positions represent approximately 98 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 Collateral support for our commodity agreements could include margin deposits, letters of credit, surety bonds and guarantees of payment by credit worthy parties.

Subsequent Events (Notes)

Subsequent Events (Notes)	6 Months Ended
	Jun. 30, 2016
Subsequent Event [Line Items]
Subsequent Events [Text Block]	Note 13 . Subsequent Events As previously discussed, on May 25, 2016, we signed an agreement to buy out the remaining transportation obligations related to our Piceance Basin operations for $239 million which eliminated certain pipeline capacity obligations held by our marketing company with total commitments for the remainder of 2016 and thereafter of approximately $400 million (see Note 9). The transaction closed July 19, 2016 and will result in a $239 million loss that will be reported in continuing operations in the third quarter of 2016. We currently expect the impact of the buyout of these transportation obligations to be reported in cash flow from operating activities in third-quarter 2016. In July 2016, we closed on the purchase of an additional 7,800 acres in the Delaware Basin. The acreage is located near our acreage position in Eddy County, New Mexico and brings our total position in the basin to approximately 100,000 acres. This purchase also includes nearly 425 Boe per day of production from existing wells. On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our 6.25% Series A Mandatory Convertible Preferred Stock (the “Preferred Stock”), pursuant to which each of the Preferred Holders has agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owns into shares of our common stock, par value $0.01 per share, and will in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders have agreed to convert an aggregate of 2,201,180 shares of Preferred Stock into 10,227,872 shares of our common stock in the Conversion, and we have agreed to make an aggregate cash payment to the Preferred Holders in an amount expected to be approximately $10 million . Following the Conversion, approximately 4.8 million shares of Preferred Stock will remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. The shares of common stock were issued in a transaction exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933, as amended, as an exchange exclusively with existing security holders where no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange. We will retire the shares of Preferred Stock

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2016
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Business Acquisition, Pro Forma Information [Table Text Block]	The following table presents the unaudited pro forma financial results for the three and six months ended June 30, 2015 as if the Acquisition and related financings had been completed January 1, 2015. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the date assumed or for the period presented, nor is such information indicative of the Company’s expected future results of operations. Three months Six months 2015 2015 (Millions) Revenues $ 198 $ 689 Net income from continuing operations attributable to WPX Energy, Inc. $ 6 $ 50

Discontinued Operations Disco21

Discontinued Operations Discontinued Operation (Tables)	6 Months Ended
	Jun. 30, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]	Summarized Results of Discontinued Operations Three months ended June 30, 2016 Three months ended June 30, 2015 Domestic and Total Domestic and Total (Millions) Total revenues(a) $ (4 ) $ 147 Costs and expenses: Lease and facility operating $ 1 $ 26 Gathering, processing and transportation 5 67 Taxes other than income (1 ) 4 Gas management — 1 Depreciation, depletion and amortization — 104 Impairment of assets held for sale — 6 Gain on sales of assets — (1 ) General and administrative 1 11 Other—net 2 2 Total costs and expenses 8 220 Operating income (loss) (12 ) (73 ) Investment income and other — 1 Gain on sale of domestic assets 52 — Income (loss) from discontinued operations before income taxes 40 (72 ) Provision (benefit) for income taxes 15 (19 ) Income (loss) from discontinued operations $ 25 $ (53 ) __________ (a) The three months ended June 30, 2016 includes $13 million net loss on derivatives. Six months ended June 30, 2016 Six months ended June 30, 2015 Domestic and Total Domestic International Total (Millions) Total revenues(a) $ 64 $ 324 $ 15 $ 339 Costs and expenses: Lease and facility operating $ 18 $ 58 $ 4 $ 62 Gathering, processing and transportation 48 137 — 137 Taxes other than income 1 14 3 17 Gas management — 1 — 1 Depreciation, depletion and amortization 9 203 — 203 Impairment of assets held for sale — 16 — 16 Gain on sale of assets — (1 ) — (1 ) General and administrative 8 21 1 22 Other—net 6 6 — 6 Total costs and expenses 90 455 8 463 Operating income (loss) (26 ) (131 ) 7 (124 ) Investment income and other — 3 1 4 Gain on sale of international interests — — 41 41 Gain on sale of domestic assets 52 — — — Income (loss) from discontinued operations before income taxes 26 (128 ) 49 (79 ) Provision (benefit) for income taxes(b) 13 (39 ) (3 ) (42 ) Income (loss) from discontinued operations $ 13 $ (89 ) $ 52 $ (37 ) __________ (a) The six months ended June 30, 2016 includes $33 million net loss on derivatives. (b) The six months ended June 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the six months ended June 30, 2015 includes the reversal of certain U.S. deferred tax liabilities associated with Apco.
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block]	Assets and Liabilities in the Consolidated Balance Sheets attributable to Discontinued Operations The assets held for sale and liabilities associated with assets held for sale on the Consolidated Balance Sheet as of June 30, 2016 relate to certain assets and liabilities in the Appalachia Basin. The operations of the Appalachia Basin are reported in continuing operations. As of December 31, 2015, the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin operations. December 31, 2015 Total Assets classified as held for sale Current assets: Accounts receivable (including an affiliate receivable) $ 55 Derivative assets 68 Inventories 13 Other 2 Total current assets 138 Properties and equipment, net(a) 880 Derivative assets 14 Total assets classified as held for sale—discontinued operations $ 1,032 Total assets classified as held for sale—continuing operations (Note 5) 40 Total assets classified as held for sale on the Consolidated Balance Sheets $ 1,072 Liabilities associated with assets held for sale Current liabilities: Accounts payable $ 93 Accrued and other current liabilities 47 Total current liabilities 140 Asset retirement obligations 133 Total liabilities associated with assets held for sale on the Consolidated Balance Sheets $ 273 __________ (a) Includes $2,308 million impairment in Piceance Basin of the net assets.

Earnings (Loss) Per Common Sh22

Earnings (Loss) Per Common Share from Continuing Operations (Tables)	6 Months Ended
	Jun. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Earnings (Loss) Per Common Share from Continuing Operations	The following table summarizes the calculation of earnings per share. Three months Six months 2016 2015 2016 2015 (Millions, except per-share amounts) Income (loss) from continuing operations attributable to WPX Energy, Inc. $ (223 ) $ 23 $ (223 ) $ 75 Less: Dividends on preferred stock 6 — 11 — Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ (229 ) $ 23 $ (234 ) $ 75 Basic weighted-average shares 300.7 205.0 288.2 204.6 Effect of dilutive securities(a): Nonvested restricted stock units and awards — 1.7 — 1.7 Stock options — 0.1 — 0.1 Diluted weighted-average shares 300.7 206.8 288.2 206.4 Earnings (loss) per common share from continuing operations: Basic $ (0.76 ) $ 0.11 $ (0.81 ) $ 0.37 Diluted $ (0.76 ) $ 0.11 $ (0.81 ) $ 0.37 __________ (a) For the three and six months ended June 30, 2016, 1.1 million and 1.6 million , respectively, weighted-average nonvested restricted stock units and awards and 34.7 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.
Schedule of Stock Options Outstanding Excluded from Computation of weighted-average stock	The table below includes information related to stock options that were outstanding at June 30, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares. June 30, 2016 2015 Options excluded (millions) 2.4 2.0 Weighted-average exercise price of options excluded $ 16.46 $ 17.42 Exercise price range of options excluded $11.75 - $21.81 $13.46 - $21.81 Second quarter weighted-average market price $ 9.02 $ 13.18

Exploration Expense (Tables)

Exploration Expense (Tables)	6 Months Ended
	Jun. 30, 2016
Extractive Industries [Abstract]
Exploration Expenses	The following table presents a summary of exploration expenses. Three months Six months 2016 2015 2016 2015 (Millions) Geologic and geophysical costs $ 1 $ 1 $ 1 $ 2 Dry hole costs and impairments of exploratory area well costs 1 — 1 — Unproved leasehold property impairment, amortization and expiration 10 5 19 11 Total exploration expenses $ 12 $ 6 $ 21 $ 13

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2016
Inventory Disclosure [Abstract]
Inventories	The following table presents a summary of our inventories as of the dates indicated below. June 30, December 31, (Millions) Material, supplies and other $ 36 $ 44 Crude oil production in transit 1 2 Total inventories $ 37 $ 46

Debt and Banking Arrangements (

Debt and Banking Arrangements (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Debt	The following table presents a summary of our debt as of the dates indicated below. June 30, December 31, (Millions) 5.250% Senior Notes due 2017 $ 160 $ 355 7.500% Senior Notes due 2020 500 500 6.000% Senior Notes due 2022 1,100 1,100 8.250% Senior Notes due 2023 500 500 5.250% Senior Notes due 2024 500 500 Credit facility agreement — 265 Other — 1 Total debt $ 2,760 $ 3,221 Less: Current portion of long-term debt, net(a) 160 1 Total long-term debt $ 2,600 $ 3,220 Less: Debt issuance costs on long-term debt(b) 28 31 Total long-term debt, net(b) $ 2,572 $ 3,189 __________ (a) Includes debt issuance costs. (b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Provision (Benefit) for Incom26

Provision (Benefit) for Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes from Continuing Operations	The following table presents the provision (benefit) for income taxes from continuing operations. Three months Six months 2016 2015 2016 2015 (Millions) Current: Federal $ — $ — $ — $ — State — 1 — — — 1 — — Deferred: Federal (119 ) 6 (119 ) 33 State (11 ) (6 ) 24 (3 ) (130 ) — (95 ) 30 Total provision (benefit) $ (130 ) $ 1 $ (95 ) $ 30

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
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. June 30, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 122 $ — $ 122 $ — $ 359 $ — $ 359 Energy derivative liabilities $ — $ 89 $ — $ 89 $ — $ 15 $ — $ 15 Total debt(a) $ — $ 2,619 $ — $ 2,619 $ — $ 2,495 $ — $ 2,495 __________ (a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,760 million and $3,220 million as of June 30, 2016 and December 31, 2015 , respectively.

Derivatives and Concentration28

Derivatives and Concentration of Credit Risk (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Derivative Volume that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production	The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of June 30, 2016 . Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Crude Oil Crude Oil Jul -Dec 2016 Fixed Price Swaps WTI (30,712 ) $ 60.16 Crude Oil Jul -Dec 2016 Basis Swaps Midland-Cushing (5,000 ) $ (0.45 ) Crude Oil Jul -Dec 2016 Fixed Price Calls WTI (1,900 ) $ 50.70 Crude Oil 2017 Fixed Price Swaps WTI (22,804 ) $ 50.71 Crude Oil 2017 Swaptions WTI (3,264 ) $ 51.22 Crude Oil 2017 Fixed Price Calls WTI (2,000 ) $ 57.10 Crude Oil 2018 Fixed Price Swaps WTI (3,000 ) $ 60.08 Crude Oil 2018 Fixed Price Calls WTI (5,000 ) $ 58.89 Natural Gas Natural Gas Jul -Dec 2016 Fixed Price Swaps Henry Hub (146 ) $ 3.93 Natural Gas Jul -Dec 2016 Basis Swaps Permian (38 ) $ (0.17 ) Natural Gas Jul -Dec 2016 Basis Swaps San Juan (100 ) $ (0.18 ) Natural Gas 2017 Fixed Price Swaps Henry Hub (90 ) $ 2.82 Natural Gas 2017 Basis Swaps Permian (10 ) $ (0.15 ) Natural Gas 2017 Basis Swaps San Juan (33 ) $ (0.16 ) Natural Gas 2017 Fixed Price Calls Henry Hub (16 ) $ 4.50 Natural Gas 2017 Swaptions Henry Hub (65 ) $ 4.19 Natural Gas 2018 Fixed Price Calls Henry Hub (16 ) $ 4.75 Commodity Period Contract Type Location(d) Notional Volume (b) Weighted Average Physical Derivatives Natural Gas Jul -Dec 2016 Index Multiple (65 ) N/A Natural Gas 2017 Index Multiple (16 ) N/A __________ (a) Derivatives related to crude oil production are fixed price swaps, basis swaps, calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, calls and swaptions. 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) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. (c) The weighted average price for crude oil price is reported in $/Bbl and natural gas is reported in $/MMBtu. (d) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements. (e) 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. June 30, 2016 December 31, 2015 Assets Liabilities Assets Liabilities (Millions) Total derivatives $ 122 $ 89 $ 359 $ 15
Derivative Gain (Loss)	We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting on derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives. Three months Six months 2016 2015 2016 2015 (Millions) Gain (loss) from derivatives related to production(a) $ (154 ) $ (68 ) $ (97 ) $ 54 Gain (loss) from derivatives related to physical marketing agreements(b) — (3 ) — (20 ) Net gain (loss) on derivatives not designated as hedges $ (154 ) $ (71 ) $ (97 ) $ 34 __________ (a) Includes settlements totaling $69 million and $137 million for the three months ended June 30, 2016 and 2015 , respectively; and settlements totaling $201 million and $295 million for the six months ended June 30, 2016 and 2015 , respectively. (b) Includes settlements totaling less than $1 million and payments totaling $5 million for the three months ended June 30, 2016 and 2015 , respectively; and settlements totaling $1 million and payments totaling $28 million for the six months ended June 30, 2016 and 2015 , respectively.
Gross And Net Derivative Assets and Liabilities	The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Cash Collateral Posted (Received) Net Amount June 30, 2016 (Millions) Derivative assets with right of offset or master netting agreements $ 122 $ (61 ) $ — $ 61 Derivative liabilities with right of offset or master netting agreements $ (89 ) $ 61 $ — $ (28 ) December 31, 2015 Derivative assets with right of offset or master netting agreements $ 359 $ (14 ) $ — $ 345 Derivative liabilities with right of offset or master netting agreements $ (15 ) $ 14 $ — $ (1 ) __________ (a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Gross and Net Credit Exposure from Derivative Contracts	The following table presents the gross and net credit exposure from our derivative contracts as of June 30, 2016 . Counterparty Type Gross Total Net Total (Millions) Financial institutions (Investment Grade)(a) $ 122 $ 61 Credit exposure from derivatives $ 122 $ 61 __________ (a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Basis of Presentation and Des29

Basis of Presentation and Description of Business- Additional Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Feb. 08, 2016	Jan. 29, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage			69.00%
Piceance Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		$ 910
Proceeds from Divestiture of Businesses	$ 862

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro Forma Revenue	$ 198	$ 689
Pro Forma Net Income (Loss)	$ 6	$ 50

Discontinued Operations Disco31

Discontinued Operations Discontinued Operation (Details) - USD ($) $ in Millions		3 Months Ended					6 Months Ended			12 Months Ended
		Sep. 30, 2016	Jun. 30, 2016		Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016		Jun. 30, 2015	Dec. 31, 2015	Feb. 08, 2016	Jan. 29, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain (loss) on derivatives (Note 12)			$ (154)		$ (71)		$ (97)		$ 34
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue			(4)	[1]	147		64	[2]	339
Disposal Group, Including Discontinued Operation, Lease Operating Expense			1		26		18		62
Disposal Group Including Discontinued Operation Gathering and Transportation Expense			5		67		48		137
Disposal Group, Including Discontinued Operation Taxes other than income			(1)		4		1		17
Disposal Group Gas Management			0		1		0		1
Disposal Group, Including Discontinued Operation, Depreciation and Amortization			0		104		9		203
Impairment of Oil and Gas Properties, Disposal Group			0		6		0		16
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax			0		(1)		0		(1)
Disposal Group, Including Discontinued Operation, General and Administrative Expense			1		11		8		22
Disposal Group, Including Discontinued Operation, Other Expense			2		2		6		6
Disposal Group, Including Discontinued Operation, Operating Expense			8		220		90		463
Disposal Group, Including Discontinued Operation, Operating Income (Loss)			(12)		(73)		(26)		(124)
Disposal Group Including Discontinued Operation Investment Income			0		1		0		4
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax									(41)
Disposal Group Including Discontinued Operation Income before Tax			40		(72)		26		(79)
Discontinued Operation, Tax Effect of Discontinued Operation			15		(19)		13	[3]	(42)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest			25		(53)		13		(37)
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net										$ 55
Disposal group derivative assets, current										68
Disposal Group, Including Discontinued Operation, Inventory										13
Disposal Group, Including Discontinued Operation, Other Assets, Current										2
Disposal Group Assets, Current										138
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	[4]									880
Disposal Group Derivative Assets Noncurrent										14
Disposal Group, Including Discontinued Operation, Assets										1,032
Assets Held for Sale, Continuing Operations										40
Assets of disposal group classified as held for sale										1,072
Disposal Group, Including Discontinued Operation, Accounts Payable										93
Disposal Group, Including Discontinued Operation, Accrued Liabilities										47
Disposal Group Liabilities, Current										140
Disposal Group Asset Retirement Obligation Noncurrent										133
Liabilities of disposal group associated with assets held for sale										273
Additional Disclosures [Abstract]
Derivative Asset, Fair Value, Gross Asset			122				122			359
Net derivative liability position			28				28
Increase (Decrease) in Other Accrued Liabilities							30		0
Piceance Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Results of Operations, Impairment of Oil and Gas Properties										2,308
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax									0
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax							(52)
Additional Disclosures [Abstract]
Sales price											$ 910
Proceeds from Divestiture of Businesses							862
Latin America [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue									15
Disposal Group, Including Discontinued Operation, Lease Operating Expense									4
Disposal Group Including Discontinued Operation Gathering and Transportation Expense									0
Disposal Group, Including Discontinued Operation Taxes other than income									3
Disposal Group Gas Management									0
Disposal Group, Including Discontinued Operation, Depreciation and Amortization									0
Impairment of Oil and Gas Properties, Disposal Group									0
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax						$ (41)			0
Disposal Group, Including Discontinued Operation, General and Administrative Expense									1
Disposal Group, Including Discontinued Operation, Other Expense									0
Disposal Group, Including Discontinued Operation, Operating Expense									8
Disposal Group, Including Discontinued Operation, Operating Income (Loss)									7
Disposal Group Including Discontinued Operation Investment Income									1
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax									41
Disposal Group Including Discontinued Operation Income before Tax									49
Discontinued Operation, Tax Effect of Discontinued Operation	[3]								(3)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									52
Additional Disclosures [Abstract]
Sales price						$ 291
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities									15
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities									(3)
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents												$ 17
Domestic Destination [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain (loss) on derivatives (Note 12)			(13)				(33)
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue									324
Disposal Group, Including Discontinued Operation, Lease Operating Expense									58
Disposal Group Including Discontinued Operation Gathering and Transportation Expense									137
Disposal Group, Including Discontinued Operation Taxes other than income									14
Disposal Group Gas Management									1
Disposal Group, Including Discontinued Operation, Depreciation and Amortization									203
Impairment of Oil and Gas Properties, Disposal Group									16
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax									(1)
Disposal Group, Including Discontinued Operation, General and Administrative Expense									21
Disposal Group, Including Discontinued Operation, Other Expense									6
Disposal Group, Including Discontinued Operation, Operating Expense									455
Disposal Group, Including Discontinued Operation, Operating Income (Loss)									(131)
Disposal Group Including Discontinued Operation Investment Income									3
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax			(52)		$ 0		(52)		0
Disposal Group Including Discontinued Operation Income before Tax									(128)
Discontinued Operation, Tax Effect of Discontinued Operation									(39)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									(89)
Additional Disclosures [Abstract]
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities							31		170
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities							29		$ 90
Powder River Basin [Member]
Additional Disclosures [Abstract]
Increase (Decrease) in Other Accrued Liabilities							$ 30
Piceance Basin [Member]
Additional Disclosures [Abstract]
Disposal group contract obligation expense			$ 104
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Piceance Basin [Member]
Additional Disclosures [Abstract]
Derivative Asset, Fair Value, Gross Asset										$ 48
Subsequent Event [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax		$ (239)
Additional Disclosures [Abstract]
Payments for (Proceeds from) other agreements		239
Other Commitment		$ 400
[1]	The three months ended June 30, 2016 includes $13 million net loss on derivatives.
[2]	The six months ended June 30, 2016 includes $33 million net loss on derivatives.
[3]	The six months ended June 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the six months ended June 30, 2015 includes the reversal of certain U.S. deferred tax liabilities associated with Apco.
[4]	Includes $2,308 million impairment in Piceance Basin of the net assets.

Earnings (Loss) Per Common Sh32

Earnings (Loss) Per Common Share from Continuing Operations (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015	Jun. 30, 2016		Jun. 30, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	$ (223)		$ 23	$ (223)		$ 75
Preferred Stock Dividends, Income Statement Impact	6		0	11		0
Income (Loss) from Continuing Operations Attributable to Parent	$ (229)		$ 23	$ (234)		$ 75
Weighted Average Number of Shares Outstanding, Basic	300.7		205	288.2		204.6
Weighted Average Number of Shares Outstanding, Diluted	300.7	[1]	206.8	288.2	[1]	206.4
Income (Loss) from Continuing Operations, Per Basic Share	$ (0.76)		$ 0.11	$ (0.81)		$ 0.37
Income (Loss) from Continuing Operations, Per Diluted Share	$ (0.76)		$ 0.11	$ (0.81)		$ 0.37
Non Vested Restricted Stock Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	1.1		1.7	1.6		1.7
Employee Stock Option [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements			0.1			0.1
Convertible Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements				34.7
[1]	For the three and six months ended June 30, 2016, 1.1 million and 1.6 million, respectively, weighted-average nonvested restricted stock units and awards and 34.7 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

Earnings (Loss) Per Common Sh33

Earnings (Loss) Per Common Share from Continuing Operations (Details 1) - $ / shares shares in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average exercise price of options excluded	$ 16.46	$ 17.42
Exercise price range of options excluded, lower limit	11.75	13.46
Exercise price range of options excluded, upper limit	21.81	21.81
Second quarter weighted-average market price	$ 9.02	$ 13.18
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3.5	1
Equity Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2.4	2

Exploration Expense (Details)

Exploration Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Geologic and geophysical costs	$ 1	$ 1	$ 1	$ 2
Results of Operations, Dry Hole Costs	1	0	1	0
Unproved leasehold property impairment, amortization and expiration	10	5	19	11
Total exploration expenses	$ 12	$ 6	$ 21	$ 13

Asset Sale, Other Expenses and

Asset Sale, Other Expenses and Exploration Expense Additional Information (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ 4		$ 208		$ 202	$ 277
Proceeds from sale of assets					$ 1,139	772
Loss on Contract Termination			22
Contract Term					2 years
San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	309				$ 309
Gain (Loss) on Disposition of Proved Property	5	$ 199
Deferred Gain on Sale of Property	26				$ 26
Significant Acquisitions and Disposals, Description					220
Pennsylvania [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sale of assets				$ 288
Gain (Loss) on Disposition of Proved Property				69
Post closing adjustment [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Gain (Loss) on Disposition of Proved Property				$ (17)
Cash [Member] | San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	285				$ 285
Cash [Member] | Northeast [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration			209			$ 209
Commitments [Member] | San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	24				24
Commitments [Member] | San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	$ 4				$ 4
Northeast [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal			$ 209

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Inventory [Line Items]
Materials, Supplies, and Other	$ 36	$ 44
Inventory, Total	37	46
Crude Oil [Member]
Inventory [Line Items]
Other Inventory, in Transit, Gross	$ 1	$ 2

Debt and Banking Arrangements37

Debt and Banking Arrangements (Details) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt		$ 2,760	$ 3,220
Capital Lease Obligations		0	1
Total debt		2,760	3,221
Current portion of long-term debt, net	[1]	160	1
Total long-term debt		2,600	3,220
Less: Debt issuance costs on long-term debt(b)	[2]	28	31
Long-term debt, net	[2]	2,572	3,189
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Long-term Debt		160	355
7.500% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt		500	500
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term Debt		1,100	1,100
8.250% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt		500	500
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term Debt		500	500
Revolving Credit Facility [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 0	$ 265
[1]	(a) Includes debt issuance costs.
[2]	(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Debt and Banking Arrangements -

Debt and Banking Arrangements - Debt - Additional information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.25%	5.25%
Debt Instrument Maturity Year	2,017	2,017
7.500% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%	7.50%
Debt Instrument Maturity Year	2,020	2,020
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%	6.00%
Debt Instrument Maturity Year	2,022	2,022
8.250% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.25%	8.25%
Debt Instrument Maturity Year	2,023	2,023
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.25%	5.25%
Debt Instrument Maturity Year	2,024	2,024

Debt and Banking Arrangements N

Debt and Banking Arrangements Narrative (Details)	6 Months Ended
	Jun. 30, 2016USD ($)Contract	Sep. 30, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Long-term Debt	$ 2,760,000,000		$ 3,220,000,000
Ratio Of Consolidated Indebtedness To Consolidated Capitalization Maximum	60.00%
Ratio of Consolidated EBITDAX To Consolidated Interest Minimum	2.5
Number of letter of credit agreements | Contract	3
Letters of credit issued	$ 228,000,000
Change in letters of credit outstanding	162,000,000
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility agreement	1,200,000,000
Line of Credit Facility, Maximum Borrowing Capacity during Collateral Period	$ 1,025,000,000
After December 31, 2016 [Member]
Debt Instrument [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX	4
7.500% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%		7.50%
8.250% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.25%		8.25%
Collateral Trigger Period [Member]
Debt Instrument [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX	3
Minimum Current Ratio	1
Prior to December 31, 2016 [Member]
Debt Instrument [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX	4.50
7.500% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 500,000,000		$ 500,000,000
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount	195,000,000
Debt Instrument, Repurchased Face Amount through Tender offer	$ 87,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Long-term Debt	$ 160,000,000		355,000,000
Line of Credit [Member] | Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 0		$ 265,000,000
Subsequent Event [Member] | 5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount		$ 35,000,000
Before December 31, 2017 [Member] | Collateral Trigger Period [Member]
Debt Instrument [Line Items]
Maximum Limit On Consolidated Secure Indebtedness to Consolidated EBITDAX	3.25
After December 31, 2017 [Member] | Collateral Trigger Period [Member]
Debt Instrument [Line Items]
Maximum Limit On Consolidated Secure Indebtedness to Consolidated EBITDAX	3

Provision (Benefit) for Incom40

Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Current:
Federal	$ 0	$ 0	$ 0	$ 0
State	0	1	0	0
Total current	0	1	0	0
Deferred:
Federal	(119)	6	(119)	33
State	(11)	(6)	24	(3)
Total deferred	(130)	0	(95)	30
Total provision (benefit)	$ (130)	$ 1	$ (95)	$ 30

Provision (Benefit) for Incom41

Provision (Benefit) for Income Taxes Additional Information (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Operating Loss Carryforwards [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 8
Deferred Tax Liabilities, Net	$ 14
Operating Loss Carryforwards, Limitations on Use	0.5
Maximum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Limitations on Use	P3Y

Contingent Liabilities - Additi

Contingent Liabilities - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Loss contingencies associated with royalty litigation		$ 21	$ 17
Contractual Obligation		137	$ 686
San Juan [Member]
Loss Contingencies [Line Items]
Contractual Obligation		366
Capacity [Member] | Powder River Basin [Member]
Loss Contingencies [Line Items]
Other noncurrent liabilities		$ 105
Subsequent Event [Member]
Loss Contingencies [Line Items]
Payments for (Proceeds from) other agreements	$ 239
Other Commitment	$ 400

Stockholder's Equity (Details)

Stockholder's Equity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 06, 2016	Dec. 31, 2015
Preferred Stock, Shares Issued	7,000	7,000			7,000
Proceeds from common stock	$ 538	$ 540	$ 2
Common Stock
Stock Issued During Period, Shares, New Issues	56,925
Stock Issued During Period, Shares, Other	7,425
Sale of stock, Price Per Share				$ 9.47

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 122	$ 359
Derivative Liability, Fair Value, Gross Liability		89	15
Long-term Debt		2,760	3,220
Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		122	359
Derivative Liability, Fair Value, Gross Liability		89	15
Long-term debt	[1]	2,619	2,495
Level 1 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Derivative Liability, Fair Value, Gross Liability		0	0
Long-term debt	[1]	0	0
Level 2 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		122	359
Derivative Liability, Fair Value, Gross Liability		89	15
Long-term debt	[1]	2,619	2,495
Level 3 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Derivative Liability, Fair Value, Gross Liability		0	0
Long-term debt	[1]	$ 0	$ 0
[1]	The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,760 million and $3,220 million as of June 30, 2016 and December 31, 2015, respectively.

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) $ in Millions	Jun. 30, 2016USD ($)
Maximum [Member] | Level 3
Assets And Liabilities Classified In Level 3 [Line Items]
Derivative, Fair Value, Net	$ 1

Derivatives and Concentration46

Derivatives and Concentration of Credit Risk (Details) BTU / d in Thousands	6 Months Ended
	Jun. 30, 2016bbl / dBTU / d$ / MMBtu$ / bbl
2016 [Member] | Physical Hedges [Member] | Natural Gas [Member] | Multiple
Derivative [Line Items]
Notional Volume	(65)	[1]
2017 [Member] | Physical Hedges [Member] | Natural Gas [Member] | Multiple
Derivative [Line Items]
Notional Volume	(16)	[1]
Price Risk Derivative [Member] | 2016 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(146)	[1]
Underlying, Derivative | $ / MMBtu	3.93	[2]
Price Risk Derivative [Member] | 2016 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(30,712)	[1]
Underlying, Derivative | $ / bbl	60.16	[2]
Price Risk Derivative [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(90)	[1]
Underlying, Derivative | $ / MMBtu	2.82	[2]
Price Risk Derivative [Member] | 2017 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(22,804)	[1]
Underlying, Derivative | $ / bbl	50.71	[2]
Price Risk Derivative [Member] | 2018 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(3,000)	[1]
Underlying, Derivative | $ / bbl	60.08	[2]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas [Member] | Permian [Member]
Derivative [Line Items]
Notional Volume	(38)	[1]
Underlying, Derivative | $ / MMBtu	(0.17)	[2]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Natural Gas [Member] | San Juan [Member]
Derivative [Line Items]
Notional Volume	(100)	[1]
Underlying, Derivative | $ / MMBtu	(0.18)	[2]
Basis Swap [Member] | 2016 [Member] | Derivatives related to production | Crude Oil | Midland-Cushing [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)	[1]
Underlying, Derivative | $ / bbl	(0.45)	[2]
Basis Swap [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | San Juan [Member]
Derivative [Line Items]
Notional Volume	(33)	[1]
Underlying, Derivative | $ / MMBtu	(0.16)	[2]
Swaption [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(65)	[1]
Underlying, Derivative | $ / MMBtu	4.19	[2]
Swaption [Member] | 2017 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(3,264)	[1]
Underlying, Derivative | $ / bbl	51.22	[2]
Call Option [Member] | 2016 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(1,900)	[1]
Underlying, Derivative | $ / bbl	50.70	[2]
Call Option [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(16)	[1]
Underlying, Derivative | $ / MMBtu	4.50	[2]
Call Option [Member] | 2017 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(2,000)	[1]
Underlying, Derivative | $ / bbl	57.10	[2]
Call Option [Member] | 2018 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(16)	[1]
Underlying, Derivative | $ / MMBtu	4.75	[2]
Call Option [Member] | 2018 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)	[1]
Underlying, Derivative | $ / bbl	58.89	[2]
Short Position [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | Permian [Member]
Derivative [Line Items]
Notional Volume	(10)	[1]
Underlying, Derivative | $ / MMBtu	(0.15)	[2]
[1]	Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
[2]	The weighted average price for crude oil price is reported in $/Bbl and natural gas is reported in $/MMBtu

Derivatives and Concentration47

Derivatives and Concentration of Credit Risk (Details 1) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Document Period End Date	Jun. 30, 2016
Derivative Asset, Fair Value, Gross Asset	$ 122	$ 359
Derivative Liability, Fair Value, Gross Liability	$ 89	$ 15

Derivatives and Concentration48

Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk (Details 2) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Document Period End Date				Jun. 30, 2016
Derivative, Cash Received on Hedge				$ (202)	$ (267)
Net gain (loss) on derivatives (Note 12)		$ (154)	$ (71)	(97)	34
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge		69	137	201	295
Net gain (loss) on derivatives (Note 12)	[1]	(154)	(68)	(97)	54
Derivatives Related to Physical Marketing Agreements [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge		1		1
Net gain (loss) on derivatives (Note 12)	[2]	$ 0	(3)	$ 0	(20)
Derivative, Cost of Hedge			$ 5		$ 28
[1]	Includes settlements totaling $69 million and $137 million for the three months ended June 30, 2016 and 2015, respectively; and settlements totaling $201 million and $295 million for the six months ended June 30, 2016 and 2015, respectively.
[2]	Includes settlements totaling less than $1 million and payments totaling $5 million for the three months ended June 30, 2016 and 2015, respectively; and settlements totaling $1 million and payments totaling $28 million for the six months ended June 30, 2016 and 2015, respectively.

Derivatives and Concentration49

Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk (Details 3) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Gross And Net Derivative Assets and Liabilities [Line Items]
Document Period End Date		Jun. 30, 2016
Derivative Asset, Fair Value, Gross Asset		$ 122	$ 359
Derivative Asset, Fair Value, Gross Liability	[1]	61	14
Derivative Asset, Collateral, Obligation to Return Cash, Offset		0	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		61	345
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		0	0
Derivative Liability, Fair Value, Gross Liability		(89)	(15)
Derivative Liability, Fair Value, Gross Asset	[1]	61	14
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ 28	$ 1
[1]	With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Derivatives and Concentration50

Derivatives and Concentration of Credit Risk (Details 4) $ in Millions	Jun. 30, 2016USD ($)
Credit Exposure From Derivatives [Line Items]
Gross credit exposure from derivatives, Gross Total	$ 122
Net credit exposure from derivatives	61
Financial institutions (Investment Grade)(a)
Credit Exposure From Derivatives [Line Items]
Total gross credit exposure from derivative contracts before credit reserve	122	[1]
Total net credit exposure from derivative contracts before credit reserve	$ 61	[1]
[1]	We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Derivatives and Concentration51

Derivatives and Concentration of Credit Risk - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Derivative [Line Items]
NumberOfLargestNetCounterPartyPositionsInvestmentGrade	5
Net derivative liability position	$ 28
Percentage of net credit exposure from derivatives	98.00%
Maximum [Member]
Derivative [Line Items]
Reduction in derivative liabilties	$ 1

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Millions	Jul. 28, 2016USD ($)shares	Sep. 30, 2016USD ($)aBoe$ / sharesshares	Jun. 30, 2016USD ($)$ / shares	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)$ / shares	Jun. 30, 2015USD ($)	Dec. 31, 2015$ / shares
Subsequent Event [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal			$ 4	$ 208	$ 202	$ 277
Preferred stock, par value | $ / shares			$ 0.01		$ 0.01		$ 0.01
Subsequent Event [Member]
Subsequent Event [Line Items]
Payments for (Proceeds from) other agreements		$ 239
Other Commitment		400
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		$ (239)
Net Acres | a		7,800
Area of Land | a		100,000
Production, Barrels of Oil Equivalents | Boe		425
Preferred stock, par value | $ / shares		$ 0.01
Conversion of Stock, Shares Converted | shares	2,201,180
Conversion of Stock, Shares Issued | shares	10,227,872
Payments for Repurchase of Redeemable Convertible Preferred Stock	$ 10
Preferred Stock, Shares Outstanding | shares		4,800,000