10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2016

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-35322

WPX Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	45-1836028
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification No.)
3500 One Williams Center, Tulsa, Oklahoma	74172-0172
(Address of Principal Executive Offices)	(Zip Code)

855-979-2012

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	New York Stock Exchange
6.25% Series A Mandatory Convertible Preferred Stock, $0.01 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨  No  þ

The number of shares outstanding of the registrant’s common stock at November 2, 2016 were 344,461,810.

WPX Energy, Inc.

Index

			Page
Part I.	Financial Information
	Item 1.	Financial Statements (Unaudited)
		Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	4
		Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015	5
		Consolidated Statements of Changes in Equity for the nine months ended September 30, 2016	6
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	7
		Notes to Consolidated Financial Statements	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
	Item 4.	Controls and Procedures	41
Part II.	Other Information
	Item 1.	Legal Proceedings	43
	Item 1A.	Risk Factors	43
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
	Item 3.	Defaults Upon Senior Securities	43
	Item 4.	Mine Safety Disclosures	43
	Item 5.	Other Information	43
	Item 6.	Exhibits	44

Certain matters contained in this report include forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• amounts and nature of future capital expenditures;

• crude oil, natural gas and NGL prices and demand;

• expansion and growth of our business and operations;

• financial condition and liquidity;

• business strategy;

• estimates of proved oil and natural gas reserves;

• reserve potential;

• development drilling potential;

• cash flow from operations or results of operations;

• acquisitions or divestitures; and

2

• seasonality of our business.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of prices and the availability and cost of capital;

• inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

• the strength and financial resources of our competitors;

• development of alternative energy sources;

• the impact of operational and development hazards;

• costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;

• changes in maintenance and construction costs;

• changes in the current geopolitical situation;

• our exposure to the credit risk of our customers;

• risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

• risks associated with future weather conditions;

• acts of terrorism;

• other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; and

• additional risks described in our filings with the Securities and Exchange Commission (“SEC”).

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth above. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. Forward-looking statements speak only as of the date they are made. We disclaim any obligation to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part II, Item 1A. Risk Factors in this filing and Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015.

3

WPX Energy, Inc.

Consolidated Balance Sheets

(Unaudited)

	September 30, 2016			December 31, 2015
	(Millions)
Assets
Current assets:
Cash and cash equivalents	$	623		$	38
Accounts receivable, net of allowance of $5 million as of September 30, 2016 and $6 million as of December 31, 2015	147			300
Derivative assets	79			308
Inventories	33			46
Assets classified as held for sale	7			178
Other	20			23
Total current assets	909			893
Properties and equipment (successful efforts method of accounting)	8,796			8,415
Less—accumulated depreciation, depletion and amortization	(2,314		)	(1,893		)
Properties and equipment, net	6,482			6,522
Derivative assets	31			51
Assets classified as held for sale	—			894
Other noncurrent assets	24			33
Total assets	$	7,446		$	8,393
Liabilities and Equity
Current liabilities:
Accounts payable	$	185		$	278
Accrued and other current liabilities	259			301
Liabilities associated with assets held for sale	2			140
Current portion of long-term debt, net	125			1
Derivative liabilities	53			13
Total current liabilities	624			733
Deferred income taxes	323			465
Long-term debt, net	2,574			3,189
Derivative liabilities	44			2
Asset retirement obligations	105			99
Liabilities associated with assets held for sale	—			133
Other noncurrent liabilities	142			237
Contingent liabilities and commitments (Note 9)
Equity:
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares issued at September 30, 2016 and 7 million shares issued at December 31, 2015)	232			339
Common stock (2 billion shares authorized at $0.01 par value; 344.5 million shares issued at September 30, 2016 and 275.4 million shares issued at December 31, 2015)	3			3
Additional paid-in-capital	6,799			6,164
Accumulated deficit	(3,400		)	(2,971		)
Total stockholders’ equity	3,634			3,535
Total liabilities and equity	$	7,446		$	8,393

See accompanying notes.

4

WPX Energy, Inc.

Consolidated Statements of Operations

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Revenues:	(Millions, except per-share amounts)
Product revenues:
Oil sales	$	139		$	120		$	378		$	370
Natural gas sales	37			37			86			104
Natural gas liquid sales	12			6			27			14
Total product revenues	188			163			491			488
Gas management	25			35			172			248
Net gain (loss) on derivatives (Note 12)	38			205			(59		)	239
Other	—			4			1			6
Total revenues	251			407			605			981
Costs and expenses:
Lease and facility operating	40			34			123			101
Gathering, processing and transportation	19			17			55			50
Taxes other than income	14			14			41			45
Gas management, including charges for unutilized pipeline capacity	31			43			202			210
Exploration (Note 5)	10			56			31			69
Depreciation, depletion and amortization	150			136			465			376
Net (gain) loss on sales of assets and divestment of transportation contracts (Note 5)	227			(2		)	25			(279		)
General and administrative (including non-cash equity-based compensation of $10 million, $7 million, $25 million and $24 million for the respective periods)	51			45			159			152
Acquisition costs (Note 2)	—			23			—			23
Other—net	10			8			14			33
Total costs and expenses	552			374			1,115			780
Operating income (loss)	(301		)	33			(510		)	201
Interest expense	(49		)	(65		)	(159		)	(130		)
Loss on extinguishment of acquired debt	—			(65		)	—			(65		)
Investment income and other	—			—			1			2
Income (loss) from continuing operations before income taxes	(350		)	(97		)	(668		)	8
Provision (benefit) for income taxes (Note 8)	(132		)	(27		)	(227		)	3
Income (loss) from continuing operations	(218		)	(70		)	(441		)	5
Income (loss) from discontinued operations	(1		)	(160		)	12			(197		)
Net income (loss)	(219		)	(230		)	(429		)	(192		)
Less: Net income (loss) attributable to noncontrolling interests	—			—			—			1
Comprehensive income (loss) attributable to WPX Energy, Inc.	(219		)	(230		)	(429		)	(193		)
Less: Dividends on preferred stock	4			4			15			4
Less: Loss on induced conversion of preferred stock	22			—			22			—
Net income (loss) attributable to WPX Energy, Inc. common stockholders	$	(245	)	$	(234	)	$	(466	)	$	(197	)
Amounts attributable to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	(244	)	$	(74	)	$	(478	)	$	1
Income (loss) from discontinued operations	(1		)	(160		)	12			(198		)
Net income (loss)	$	(245	)	$	(234	)	$	(466	)	$	(197	)
Basic earnings (loss) per common share (Note 4):
Income (loss) from continuing operations	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01
Income (loss) from discontinued operations	—			(0.64		)	0.04			(0.90		)
Net income (loss)	$	(0.72	)	$	(0.93	)	$	(1.54	)	$	(0.89	)
Basic weighted-average shares	341.5			251.2			302.8			220.3
Diluted earnings (loss) per common share (Note 4):
Income (loss) from continuing operations	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01
Income (loss) from discontinued operations	—			(0.64		)	0.04			(0.90		)
Net income (loss)	$	(0.72	)	$	(0.93	)	$	(1.54	)	$	(0.89	)
Diluted weighted-average shares	341.5			251.2			302.8			221.7

See accompanying notes.

5

WPX Energy, Inc.

Consolidated Statements of Changes in Equity

(Unaudited)

	WPX Energy, Inc., Stockholders
	Preferred Stock			Common Stock		Additional Paid-In- Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance at December 31, 2015	$	339		$	3	$	6,164		$	(2,971	)	$	3,535
Comprehensive income (loss) attributable to WPX Energy, Inc.	—			—		—			(429		)	(429		)
Stock based compensation	—			—		16			—			16
Issuance of common stock to public, net of offering costs	—			—		538			—			538
Conversion of preferred stock to common stock	(107		)	—		118			—			11
Loss on induced conversion of preferred stock and related conversion costs	—			—		(22		)	—			(22		)
Dividends on preferred stock	—			—		(15		)	—			(15		)
Balance at September 30, 2016	$	232		$	3	$	6,799		$	(3,400	)	$	3,634

See accompanying notes.

6

WPX Energy, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine months ended September 30,
	2016			2015
Operating Activities(a)	(Millions)
Net income (loss)	$	(429	)	$	(192	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	474			685
Deferred income tax provision (benefit)	(209		)	(138		)
Provision for impairment of properties and equipment (including certain exploration expenses)	29			78
Net (gain) loss on derivatives in continuing operations	59			(239		)
Net settlements related to derivatives in continuing operations	260			422
Net loss on derivatives included in discontinued operations	46			—
Amortization of stock-based awards	27			27
Gain on extinguishment of debt	—			81
Net (gain) loss on sales of assets and divestment of transportation contracts	(28		)	(317		)
Cash provided (used) by operating assets and liabilities:
Accounts receivable	147			232
Inventories	13			(11		)
Margin deposits and customer margin deposits payable	—			25
Other current assets	6			—
Accounts payable	(79		)	(186		)
Federal income taxes payable	(33		)	—
Accrued and other current liabilities	(97		)	22
Accrued liabilities established in 2015 for retained transportation and gathering contracts related to discontinued operations	(42		)	—
Other, including changes in other noncurrent assets and liabilities	(35		)	140
Net cash provided by operating activities(a)	109			629
Investing Activities(a)
Capital expenditures(b)	(440		)	(890		)
Proceeds from sales of assets	1,140			610
Proceeds (payments) related to divestment of transportation contracts	(238		)	209
Purchases of business, net of cash acquired	—			(1,190		)
Other	(2		)	2
Net cash provided by (used in) investing activities(a)	460			(1,259		)
Financing Activities
Proceeds from common stock	540			295
Proceeds from preferred stock	—			339
Dividends paid on preferred stock	(15		)	—
Payments related to induced conversion of preferred stock to common stock	(10		)	—
Proceeds from long-term debt	—			1,000
Borrowings on credit facility	380			756
Payments on credit facility	(645		)	(636		)
Payments for retirement of debt	(230		)	(1,055		)
Payments for credit facility amendment fees, debt issuance cost and acquisition bridge financing fees	(3		)	(40		)
Other	(1		)	—
Net cash provided by (used in) financing activities	16			659
Net increase (decrease) in cash and cash equivalents	585			29
Cash and cash equivalents at beginning of period	38			70
Cash and cash equivalents at end of period	$	623		$	99
__________
(a) Amounts reflect continuing and discontinued operations unless otherwise noted. See Note 3 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
(b) Increase to properties and equipment	$	(424	)	$	(640	)
Changes in related accounts payable and accounts receivable	(16		)	(250		)
Capital expenditures	$	(440	)	$	(890	)

See accompanying notes.

7

WPX Energy, Inc.

Notes to Consolidated Financial Statements

Note 1. Description of Business and Basis of Presentation

Description of Business

Operations of our company include oil, natural gas and NGL development, production, and gas management activities primarily located in Texas, North Dakota, New Mexico and Colorado. 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 which ended June 30, 2016 (see Note 3).    

In addition, we had other operations sold in 2015 and 2016 reported as discontinued operations, as discussed below.

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 September 30, 2016, results of operations for the three and nine months endedSeptember 30, 2016 and 2015, changes in equity for the nine months endedSeptember 30, 2016 and cash flows for the nine months endedSeptember 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 in Colorado 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, discontinued operations include the results of our Powder River Basin operations in Wyoming which were sold on September 1, 2015. Discontinued operations also include our 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 which was sold on January 29, 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. ASU 2014-09 can be applied using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is currently evaluating the method of adoption and the impact, if any, of ASU 2014-09 to the Company's Consolidated Financial Statements or related disclosures.

8

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 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.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which provides new guidance for eight specific cash flow issues. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The Company does not expect the adoption of ASU 2016-15 to have a significant impact on the Company’s Consolidated Statements of Cash Flows.

Note 2. 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. We adjusted the purchase price allocation resulting in an increase of $60 million to both properties and equipment and deferred taxes in the third quarter of 2016.

The following table presents the unaudited pro forma financial results for the three and nine months ended September 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 ended September 30,		Nine months ended September 30,
	2015		2015
	(Millions)
Revenues	$	504	$	1,193
Net income from continuing operations attributable to WPX Energy, Inc.	$	40	$	90

Note 3. 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

9

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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, subject to post-closing adjustments, resulting in a gain of $53 million. We performed certain transition services for the buyer which concluded 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.

In August 2015, we signed agreements for the sale of our Powder River Basin for $80 million. On September 1, 2015, we completed a portion of the Powder River Basin divestiture. The remaining portion of the divestiture, which related to an equity method investment in Fort Union Gas Gathering, LLC, closed on October 30, 2015. We recorded a pre-tax loss of $15 million related to this divestment during third quarter 2015. During the first and second quarters of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices for the Powder River Basin. In addition, we retained certain firm gathering and treating obligations with total commitments of $104 million through 2020 related to the Powder River properties sold. These commitments had been in excess of our production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company with total commitments through 2021 totaling $150 million, which were related to the Powder River operations. With the closing of the Powder River Basin sale and exiting this basin, we recorded $187 million of expense related to these contracts, which is included as a separate line below. This $187 million expense is the estimated present value of the $254 million in payments associated with these contracts remaining as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from third parties and discounting based on our risk adjusted borrowing rate. During third quarter 2015, we received $13 million in escrow funds as a result of terminating a previous sales contract for the Powder River Basin assets and this amount is included in Other-net expense below. The Powder River Basin operations are included in our domestic results presented below.

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 September 30, 2016			Three months ended September 30, 2015
	Domestic and Total			Domestic and Total
	(Millions)
Total revenues	$	—		$	142
Costs and expenses:
Lease and facility operating	$	—		$	22
Gathering, processing and transportation	1			68
Taxes other than income	1			4
Depreciation, depletion and amortization	—			106
General and administrative	1			13
Accrual for contract obligations retained	—			187
Other—net	(2		)	(14		)
Total costs and expenses	1			386
Operating income (loss)	(1		)	(244		)
Investment income and other	—			3
Gain (loss) on sale of domestic assets	1			(15		)
Income (loss) from discontinued operations before income taxes	—			(256		)
Provision (benefit) for income taxes	1			(96		)
Income (loss) from discontinued operations	$	(1	)	$	(160	)

10

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

	Nine months ended September 30, 2016			Nine months ended September 30, 2015
	Domestic and Total			Domestic			International			Total
	(Millions)
Total revenues(a)	$	64		$	466		$	15		$	481
Costs and expenses:
Lease and facility operating	$	18		$	80		$	4		$	84
Gathering, processing and transportation	49			205			—			205
Taxes other than income	2			18			3			21
Gas management	—			1			—			1
Depreciation, depletion and amortization	9			309			—			309
Impairment of assets held for sale	—			16			—			16
General and administrative	9			34			1			35
Accrual for contract obligations retained	—			187			—			187
Other—net	4			(9		)	—			(9		)
Total costs and expenses	91			841			8			849
Operating income (loss)	(27		)	(375		)	7			(368		)
Investment income and other	—			6			1			7
Gain (loss) on sale of domestic assets and international interests	53			(15		)	41			26
Income (loss) from discontinued operations before income taxes	26			(384		)	49			(335		)
Provision (benefit) for income taxes(b)	14			(135		)	(3		)	(138		)
Income (loss) from discontinued operations	$	12		$	(249	)	$	52		$	(197	)

__________

(a) The nine months ended September 30, 2016 includes $33 million net loss on derivatives.

(b) The nine months ended September 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the nine months ended September 30, 2015 includes the reversal of certain U.S. deferred tax liabilities associated with Apco.

11

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 September 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 $28 million and used by domestic operating activities was $59 million for the nine months ended September 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 $42 million for the nine months ended September 30, 2016. Cash provided by operating activities related to our international operations was $3 million for the nine months ended September 30, 2015. Total cash used in investing activities related to domestic discontinued operations was $32 million and $219 million for the nine months ended September 30, 2016 and 2015, respectively. Total cash used in investing activities related to our international operations was $15 million for the nine months ended September 30, 2015.

12

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 4. Earnings (Loss) Per Common Share from Continuing Operations

The following table summarizes the calculation of earnings per share.

	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	(218	)	$	(70	)	$	(441	)	$	5
Less: Dividends on preferred stock	4			4			15			4
Less: Loss on induced conversion of preferred stock	22			—			22			—
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	(244	)	$	(74	)	$	(478	)	$	1
Basic weighted-average shares	341.5			251.2			302.8			220.3
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	—			—			—			1.3
Stock options	—			—			—			0.1
Diluted weighted-average shares	341.5			251.2			302.8			221.7
Earnings (loss) per common share from continuing operations:
Basic	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01
Diluted	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01

__________

(a) The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders.

	Three months ended September 30,		Nine months ended September 30,
	2016	2015	2016	2015
	(Millions)
Weighted-average nonvested restricted stock units and awards	2.4	0.7	1.8	—
Weighted-average stock options	—	0.1	—	—
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 10)	23.8	26.7	23.8	9.0

The table below includes information related to stock options that were outstanding at September 30, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.

	September 30,
	2016		2015
Options excluded (millions)	2.4		2.6
Weighted-average exercise price of options excluded	$	16.46	$	16.16
Exercise price range of options excluded	$11.75 - $21.81		$11.46 - $21.81
Third quarter weighted-average market price	$	11.11	$	8.36

For the nine months ended September 30, 2016 and 2015, approximately 0.1 million and 1.1 million, respectively, nonvested restricted stock units were antidilutive and were excluded from the computation of diluted weighted-average shares.

13

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 5. Asset Sales, Other Expenses and Exploration Expenses

Asset Sales and Divestment of Transportation Contracts

During July 2016, we completed the divestment of the remaining transportation contracts primarily related to our Piceance Basin operations which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment to Terra. The total remaining commitments related to these contracts for the remainder of 2016 and thereafter were approximately $400 million. As a result of the divestments and net payment of $238 million, we recorded a net loss of $238 million in third-quarter 2016.

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 additional gains of $5 million and $11 million in the second and third quarters of 2016, respectively, as certain in-progress construction was completed. As of September 30, 2016, the deferred gain was $14 million related to an estimated $4 million of remaining recorded obligations 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 ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(Millions)
Geologic and geophysical costs	$	1	$	3	$	2	$	5
Dry hole costs and impairments of exploratory area well costs	—		22		1		22
Unproved leasehold property impairment, amortization and expiration	9		31		28		42
Total exploration expenses	$	10	$	56	$	31	$	69

For both the three and nine months ended September 30, 2015, dry hole costs and impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration include $21 million and $26 million, respectively, related to a non-core exploratory play where we no longer intend to continue exploration activities.

14

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 6. Inventories

The following table presents a summary of our inventories as of the dates indicated below.

	September 30, 2016		December 31, 2015
	(Millions)
Material, supplies and other	$	31	$	44
Crude oil production in transit	2		2
Total inventories	$	33	$	46

During the third quarter of 2016, we recorded an impairment of material and supplies inventory of approximately $4 million.

Note 7. Debt and Banking Arrangements

The following table presents a summary of our debt as of the dates indicated below.

	September 30, 2016		December 31, 2015
	(Millions)
5.250% Senior Notes due 2017	$	125	$	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		1
Total debt	$	2,726	$	3,221
Less: Current portion of long-term debt, net(a)	125		1
Total long-term debt	$	2,601	$	3,220
Less: Debt issuance costs on long-term debt(b)	27		31
Total long-term debt, net(b)	$	2,574	$	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 2016, we repurchased approximately $230 million of our 5.250% Senior Notes due 2017, including $87 million we redeemed through a tender offer.

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

OnMarch 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 September 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. The Borrowing Base was reaffirmed at $1.025 billion in October 2016. This Borrowing Base will remain in effect until the next

15

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Borrowing Base is re-determined pursuant to the Credit Facility. The next Scheduled Re-determination Date is April 1, 2017 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

16

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 during 2016. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility. As a result of the divestment of our Piceance Basin transportation contracts, we eliminated approximately $162 million in letters of credit and their associated annual interest expense. At September 30, 2016, a total of $66 million in letters of credit have been issued, a majority of which support interstate pipeline contracts. As these letter of credit agreements expire, we expect to issue letters of credit under our Credit Facility.

Note 8. Provision (Benefit) for Income Taxes

The following table presents the provision (benefit) for income taxes from continuing operations.

	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(Millions)
Current:
Federal	$	—		$	(4	)	$	—		$	(4	)
State	(5		)	(1		)	(5		)	(1		)
	(5		)	(5		)	(5		)	(5		)
Deferred:
Federal	(117		)	(26		)	(236		)	7
State	(10		)	4			14			1
	(127		)	(22		)	(222		)	8
Total provision (benefit)	$	(132	)	$	(27	)	$	(227	)	$	3

The effective income tax rate for the three months ended September 30, 2016, differs from the federal statutory rate due to the effects of state income taxes.

The effective income tax rate for the nine months endedSeptember 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

17

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 nine months endedSeptember 30, 2015, differs from the federal statutory rate due to the effects of state income taxes and certain nondeductible acquisition costs.

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 September 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 September 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 IRS 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.

Note 9. 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. On August 16, 2016, the court denied plaintiffs’ motion for class certification. On September 15, 2016, plaintiffs filed their motion for reconsideration and filed a second motion for class certification. 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

18

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 September 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

19

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 September 30, 2016 and December 31, 2015, the Company had accrued approximately $17 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.

Commitments

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 $363 million as of September 30, 2016.

As previously discussed in Note 5, we divested of transportation contracts in the third quarter of 2016 which eliminated certain pipeline capacity commitments for the remainder of 2016 and thereafter totaling 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 are approximately $128 million as of September 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 this liability totaled approximately $99 million as of September 30, 2016 (see Note 3).

Note 10. Stockholders’ Equity

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 agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders 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 made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million.

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 retired the shares of Preferred Stock converted in the Conversion. By entering into the Conversion and associated transactions early, we reduced cash dividend payments and continued simplifying our capital and cost structure.

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.

20

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 11. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

	September 30, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	110	$	—	$	110	$	—	$	359	$	—	$	359
Energy derivative liabilities	$	—	$	97	$	—	$	97	$	—	$	15	$	—	$	15
Total debt(a)	$	—	$	2,752	$	—	$	2,752	$	—	$	2,495	$	—	$	2,495

__________

(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,725 million and $3,220 million as of September 30, 2016 and December 31, 2015, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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 quarterly 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 September 30, 2016, and consist primarily of natural gas index transactions that are used to manage our physical requirements.

21

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended September 30, 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.

Note 12. 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.

22

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 September 30, 2016.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Crude Oil
Crude Oil	Oct -Dec 2016	Fixed Price Swaps	WTI	(30,403	)	$	60.13
Crude Oil	Oct -Dec 2016	Basis Swaps	Midland-Cushing	(5,000	)	$	(0.45	)
Crude Oil	Oct -Dec 2016	Fixed Price Calls	WTI	(1,900	)	$	50.70
Crude Oil	2017	Fixed Price Swaps	WTI	(29,554	)	$	51.31
Crude Oil	2017	Swaptions	WTI	(3,264	)	$	51.22
Crude Oil	2017	Fixed Price Calls	WTI	(4,500	)	$	56.47
Crude Oil	2018	Fixed Price Swaps	WTI	(13,000	)	$	58.33
Crude Oil	2018	Fixed Price Calls	WTI	(13,000	)	$	58.89
Natural Gas
Natural Gas	Oct -Dec 2016	Fixed Price Swaps	Henry Hub	(146	)	$	3.93
Natural Gas	Oct -Dec 2016	Basis Swaps	Permian	(38	)	$	(0.17	)
Natural Gas	Oct -Dec 2016	Basis Swaps	San Juan	(100	)	$	(0.18	)
Natural Gas	2017	Fixed Price Swaps	Henry Hub	(150	)	$	2.98
Natural Gas	2017	Basis Swaps	Permian	(58	)	$	(0.20	)
Natural Gas	2017	Basis Swaps	San Juan	(93	)	$	(0.17	)
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 Swaps	Henry Hub	(40	)	$	2.91
Natural Gas	2018	Fixed Price Calls	Henry Hub	(16	)	$	4.75
Natural Gas	2018	Swaptions	Henry Hub	(20	)	$	3.33
Commodity	Period	Contract Type	Location(d)	Notional Volume (b)		Weighted Average Price
Physical Derivatives
Natural Gas	Oct -Dec 2016	Index	Multiple	(65	)	(e)
Natural Gas	2017	Index	Multiple	(16	)	(e)

__________

(a) Derivatives related to crude oil production are fixed price swaps, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas 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 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.

23

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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.

	September 30, 2016				December 31, 2015
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Total derivatives	$	110	$	97	$	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 for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.

	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
	(Millions)
Gain (loss) from derivatives related to production(a)	$	38	$	206		$	(59	)	$	260
Gain (loss) from derivatives related to physical marketing agreements(b)	—		(1		)	—			(21		)
Net gain (loss) on derivatives	$	38	$	205		$	(59	)	$	239

__________

(a) Includes settlements totaling $59 million and $159 million for the three months ended September 30, 2016 and 2015, respectively; and settlements totaling $260 million and $454 million for the nine months ended September 30, 2016 and 2015, respectively.

(b) Includes payments totaling $4 million and $32 million for the three months and nine months ended September 30, 2015, respectively.

The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows.

24

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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)			Net Amount
September 30, 2016	(Millions)
Derivative assets with right of offset or master netting agreements	$	110		$	(69	)	$	41
Derivative liabilities with right of offset or master netting agreements	$	(97	)	$	69		$	(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 September 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 $2 million to our liability balance for our own nonperformance risk. There would have been collateral totaling $30 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 September 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,

25

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 September 30, 2016.

Counterparty Type	Gross Total		Net Total
	(Millions)
Financial institutions (Investment Grade)(a)	$	110	$	41
Credit exposure from derivatives	$	110	$	41

__________

(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 99 percent of our net credit exposure. 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.

26

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes included elsewhere in this Form 10-Q and Exhibit 99.1 of our Form 8-K filed May 25, 2016. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Form 10-Q and our 2015 Annual Report on Form 10-K.

On February 8, 2016, we signed an agreement to sell our Piceance Basin operations to Terra Energy Partners LLC (“Terra”) and closed the transaction on April 8, 2016. The results of operations of the Piceance Basin are reported as discontinued operations (see Note 3 of Notes to Consolidated Financial Statements). In addition, our discontinued operations include the results of the Powder River Basin sold in September 2015 and our international interests sold in January 2015 (see Note 3 of Notes to Consolidated Financial Statements).

Unless indicated otherwise, the following discussion relates to continuing operations.

On August 17, 2015, we completed the acquisition of privately-held RKI Exploration & Production, LLC (“RKI”). See Note 2 of Notes to Consolidated Financial Statements for further discussion of the acquisition of RKI. The 2015 results of RKI after August 17, 2015 included in the following discussions include $22 million of product revenues, $12 million of depreciation, depletion and amortization and $7 million of lease operating expenses. In addition, we incurred $104 million of acquisition related expenses during the third quarter of 2015 including $23 million of legal and advisory fees, $16 million of bridge financing fees and $65 million of expense related to the retirement of RKI's debt.

Overview

The following table presents our production volumes and financial highlights for the three and nine months ended September 30, 2016 and 2015:

	Three months ended September 30,					Nine months ended September 30,
	2016			2015		2016			2015
Production Sales Data(a):
Volumes:
Oil (MBbls)	3,576			3,123		11,069			8,927
Natural gas (MMcf)	18,845			16,901		54,428			47,646
NGLs (MBbls)	1,047			733		2,663			1,588
Combined equivalent volumes (MBoe)(b)	7,764			6,673		22,804			18,457
Per day volumes:
Oil (MBbls/d)	38.9			33.9		40.4			32.7
Natural gas (MMcf/d)	205			184		199			175
NGLs (MBbls/d)	11.4			8.0		9.7			5.8
Per day combined equivalent volumes (MBoe/d)(b)	84.4			72.5		83.2			67.6
Financial Data (millions):
Total revenues	$	251		$	407	$	605		$	981
Operating income (loss)	$	(301	)	$	33	$	(510	)	$	201
Cash capital expenditures(c)	$	149		$	211	$	440		$	890
Capital expenditure activity(d)	$	160		$	205	$	424		$	640

__________

(a) Excludes production from discontinued operations.

(b) MBoe are converted using the ratio of one barrel of oil, condensate or NGL to six thousand cubic feet of natural gas.

(c) Includes cash capital expenditures related to discontinued operations of $1 million and $49 million for the three months ended September 30, 2016 and 2015, respectively, and $32 million and $234 million for the nine months ended September 30, 2016 and 2015, respectively.

(d) Includes capital expenditures activity related to discontinued operations of $1 million and $41 million for the three months ended September 30, 2016 and 2015, respectively, and $27 million and $155 million for the nine months ended September 30, 2016 and 2015, respectively.

27

Our third-quarter 2016 operating results were $334 millionunfavorable compared to third-quarter 2015. The primary items impacting the three months ended September 30, 2016 compared to the same period in 2015 include:

• $238 million loss recorded on the divestment of transportation contracts in 2016;

• $167 million unfavorable change in net gain (loss) on derivatives;

• $46 million decrease in exploration costs for 2016 compared to 2015;

• $25 million increase in product revenues; and

• $23 million acquisition costs included in 2015 expenses.

Our year-to-date 2016 operating results were $711 millionunfavorable compared to year to date 2015. The primary items impacting the nine months ended September 30, 2016 compared to the same period in 2015 include:

• $298 million unfavorable change in net gain (loss) on derivatives;

• $89 million increase in depreciation, depletion and amortization;

• $68 million lower net gas management margin;

• $38 million lower exploration costs for 2016 compared to 2015;

• $25 million of net loss on sales of assets and divestment of transportation contracts (see Note 5 of Notes to Consolidated Financial Statements) in 2016 compared to $279 million gain for the same period in 2015;

• $23 million acquisition costs included in 2015 expenses; and

• $22 million other expense in 2015 for a termination and settlement agreement to release us from a crude oil transportation and sales agreement.

Outlook

The oil and gas industry is in a challenging environment as evidenced by volatility in the prices, the changing capital plans among our peers, reductions in workforces across the industry and concerns about liquidity. In 2016, we have taken steps to strengthen our liquidity including the issuance of common equity which provided $538 million of proceeds net of offering costs, renegotiated a secured revolving credit agreement with a $1.025 billion current capacity, and sold WPX Energy Rocky Mountain LLC, which holds our Piceance operations. Our September 30, 2016 liquidity totaled over $1.6 billion, reflecting $623 million of cash and cash equivalents and $1.025 available under the Credit Facility. Through September 30, 2016, we have reduced our near term leverage through repayment of outstanding amounts at December 31, 2015 under the Credit Facility and tendering for portions of the Senior Notes due in 2017 of which only $125 million remains outstanding as of September 30, 2016. Our next debt maturity is not until 2020. In July 2016, we completed the divestment of transportation contracts that included approximately $400 million of remaining long term transportation obligations for a net payment of $238 million. In addition, we have 30,403 Bbl per day of oil hedged at $60.13 per barrel in 2016. For 2017, we have 34,554 Bbl per day of oil hedged at $51.45 per barrel. Our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a further downturn. Over the past two years, we have been committed to the strategy of increasing oil production as a percentage of our overall production and increasing margins. This commitment has led to the transformation of the Company. Our primary focus is on the Delaware Basin assets acquired in 2015. The asset scale and concentrated acreage position will allow for efficient, low-cost development activities over a number of years that will provide additional optionality to our portfolio and a more balanced commodity mix. A substantial portion of our future capital spending will be allocated to the Delaware Basin where expected returns are attractive even in the current commodity price environment. We will also continue our development of the oil plays in the Williston and San Juan Basins.

As we continue our transformation, we have the opportunity to improve our cost structure and ensure that our organization is in alignment with our growth objectives. Throughout 2016 and into 2017, we plan to continue the cost reduction efforts through reduced drilling times, efficient use of pad design and completion activities, and collaboration with our vendors to lower costs on goods and services; however, additional savings may not be as great as those seen in the past. Additionally, we continue to challenge our levels of general and administrative costs. In February 2016, we announced our plans to close the Oklahoma City office which was accomplished in second-quarter 2016. Towards the end of the third quarter, we also had further reductions to our cost structure after completion of transition services associated with the sale of the Piceance Basin. We continue to further align our organizational size to achieve an optimal workforce conducive to the current pricing environment and future growth.

During the first nine months of 2016, we incurred $424 million in capital expenditures, primarily drilling and completions, but also includes $60 million for additional acreage acquisitions in the Delaware Basin and $27 million associated with the Piceance assets through the closing date. Our 2016 drilling and completion capital program is expected to range from $400 million to $450 million. For the full-year 2016, we expect to spend $195 million to $215 million in the Delaware Basin while running an average of three rigs to develop our acreage for the remainder of 2016 but ramping up to a total of five rigs by the end of the year. We expect to spend $130 million to $145 million in the Williston Basin and deploy one to two rigs during

28

the fourth quarter. In addition, we expect to complete three to four previously drilled but not completed wells per month through December 2016. We expect to spend $75 million to $85 million in the San Juan Basin, primarily in the Gallup Sandstone. We also expect to incur additional capital expenditures of $10 million to $20 million on midstream related projects in the Delaware Basin.

Our 2017 drilling and completion capital program is expected to range from $800 million to $860 million. Approximately half of the capital is targeted for development in the Delaware Basin. This program would fund an eight-rig program, with five in the Delaware Basin, two in the Williston Basin and one in the San Juan Basin. In 2017, we expect to complete more than 150 operated wells under this plan consisting of roughly 70-80 Delaware wells, 38-42 Williston wells and 40-46 San Juan wells.

As we execute on our long-term strategy, we continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:

• continuing to grow our oil production and reserves through the development of our positions in the Delaware Basin, Williston Basin and Gallup Sandstone in the San Juan Basin;

• continuing to pursue cost improvements and efficiency gains;

• employing new technology and operating methods;

• continuing to invest in projects to assess resources and add new development opportunities to our portfolio;

• retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and

• continuing to maintain an active economic hedging program around our commodity price risks.

Potential risks or obstacles that could impact the execution of our plan include:

• lower than anticipated energy commodity prices;

• lower than expected results from acquisitions;

• higher capital costs of developing our properties;

• lower than expected levels of cash flow from operations;

• counterparty credit and performance risk;

• general economic, financial markets or industry downturn;

• unavailability of capital either under our revolver or access to capital markets;

• changes in the political and regulatory environments;

• increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation; and

• decreased drilling success.

With the exception of potential impairments, we continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are significantly volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel for a brief time over the past five years. Our forecasted price assumptions reflect a long term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. If forecasted oil and natural gas prices were to decline, we would need to review the producing properties net book value for possible impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant. The net book value of our predominantly oil proved properties is $3.7 billion and the net book value of our predominantly natural gas proved properties is approximately $300 million. In addition, the net book value associated with unproved leasehold is approximately $2.3 billion and is primarily associated with our Delaware Basin properties. See our discussion of impairment of long-lived assets in our critical accounting estimates discussion in Exhibit 99.1 of our Form 8-K filed May 25, 2016.

29

Commodity Price Risk Management

To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 12 of Notes to Consolidated Financial Statements). We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. For the remainder of 2016 and 2017, we have the following contracts as of the date of this filing shown at weighted average volumes and basin-level weighted average prices:

Crude Oil	Oct - Dec 2016				2017
	Volume (Bbls/d)	Weighted Average Price ($/Bbl)			Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Fixed Price Swaps—WTI	30,403	$	60.13		34,554	$	51.45
Swaptions—WTI	—	$	—		3,264	$	51.22
Fixed Price Calls—WTI	1,900	$	50.70		4,500	$	56.47
Basis swaps—Midland	5,000	$	(0.45	)	—	$	—

Natural Gas	Oct - Dec 2016				2017
	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)			Volume (BBtu/d)	Weighted Average Price ($/MMBtu)
Fixed Price Swaps—Henry Hub	146	$	3.93		170	$	3.02
Swaptions—Henry Hub	—	$	—		65	$	4.19
Fixed Price Calls—Henry Hub	—	$	—		16	$	4.50
Basis swaps—Permian	38	$	(0.17	)	68	$	(0.20	)
Basis swaps—San Juan	100	$	(0.18	)	103	$	(0.18	)

Results of Operations

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. Our development and production techniques specialize in production from tight-sands and shale formations in the Delaware, Williston and San Juan Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, which include the management of various commodity contracts, such as transportation and related derivatives and the marketing of Piceance Basin volumes during a transition period which ended June 30, 2016 (see Note 3 of Notes to Consolidated Financial Statements).

Three Month-Over-Three Month Results of Operations

Revenue Analysis

	Three months ended September 30,				Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2016		2015
	(Millions)
Revenues:
Oil sales	$	139	$	120	$	19		16	%
Natural gas sales	37		37		—			—	%
Natural gas liquid sales	12		6		6			100	%
Total product revenues	188		163		25			15	%
Gas management	25		35		(10		)	(29	)%
Net gain (loss) on derivatives	38		205		(167		)	(81	)%
Other	—		4		(4		)	NM
Total revenues	$	251	$	407	$	(156	)	(38	)%

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

30

Significant variances in the respective line items of revenues are comprised of the following:

• $19 millionincrease in oil sales primarily reflects a $17 million increase related to higher production sales volumes for the three months ended September 30, 2016 as compared to 2015. The increase in production sales volumes relates to our Delaware Basin which was acquired on August 17, 2015. The Delaware Basin volumes were 14.3 MBbls per day for the three months ended September 30,2016 compared to 4.6 MBbls per day for the three months ended September 30, 2015. The following table reflects oil production prices and volumes for the three months ended September 30,2016 and 2015:

	Three months ended September 30,
	2016		2015
Oil sales (per barrel)	$	38.71	$	38.23
Impact of net cash received related to settlement of derivatives (per barrel)(a)	12.15		32.98
Oil net price including derivative settlements (per barrel)	$	50.86	$	71.21
Oil production sales volumes (MBbls)	3,576		3,123
Per day oil production sales volumes (MBbls/d)	38.9		33.9

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

• Natural gas sales remained flat as lower sales prices were offset by increased production sales volumes. The increase in our production sales volumes is primarily due to our Delaware Basin which was acquired on August 17, 2015. The following table reflects natural gas production prices and volumes for the three months ended September 30,2016 and 2015:

	Three months ended September 30,
	2016		2015
Natural gas sales (per Mcf)	$	1.97	$	2.18
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.79		3.32
Natural gas net price including derivative settlements (per Mcf)	$	2.76	$	5.50
Natural gas production sales volumes (MMcf)	18,845		16,901
Per day natural gas production sales volumes (MMcf/d)	205		184

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

• $6 millionincrease in natural gas liquids sales reflects a $3 million increase related to production sales volumes, primarily due to our Delaware Basin which was acquired on August 17, 2015, and $3 million related to higher NGL sales prices for the three month ended September 30, 2016 compared to 2015. The following table reflects NGL production prices and volumes for the three months ended September 30,2016 and 2015:

	Three months ended September 30,
	2016		2015
NGL sales (per barrel)	$	11.50	$	8.76
NGL production sales volumes (MBbls)	1,047		733
Per day NGL production sales volumes (MBbls/d)	11.4		8.0

• $10 milliondecrease in gas management revenues primarily due to lower natural gas sales volumes partially offset by higher average prices on physical natural gas sales. We experienced a similar decrease of $12 million in related gas management costs and expenses, discussed below.

• $167 millionunfavorable change in net gain (loss) on derivatives primarily relates to unfavorable changes in realized and unrealized gains (losses) on derivatives related to production. Net settlements from our derivatives were $59 million and $155 million for the three months ended September 30,2016 and 2015, respectively.

31

Cost and operating expense and operating income (loss) analysis

	Three months ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2016			2015
	(Millions)
Costs and expenses:
Lease and facility operating	$	40		$	34		$	(6	)	(18	)%
Gathering, processing and transportation	19			17			(2		)	(12	)%
Taxes other than income	14			14			—			—	%
Gas management, including charges for unutilized pipeline capacity	31			43			12			28	%
Exploration	10			56			46			82	%
Depreciation, depletion and amortization	150			136			(14		)	(10	)%
Net (gain) loss on sales of assets and divestment of transportation contracts	227			(2		)	(229		)	NM
General and administrative	51			45			(6		)	(13	)%
Acquisition costs	—			23			23			100	%
Other—net	10			8			(2		)	(25	)%
Total costs and expenses	$	552		$	374		$	(178	)	(48	)%
Operating income (loss)	$	(301	)	$	33		$	(334	)	NM

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

Significant variances in our costs and expenses are comprised of the following:

• $6 millionincrease in lease and facility operating expenses primarily related to our Delaware Basin, which was acquired on August 17, 2015, partially offset by decreases in other basins. Lease and facility operating expenses for the three months ended September 30, 2016 and 2015 included $15 million and $7 million, respectively, from our Delaware Basin. Lease and facility operating expense averaged $5.07 per Boe for the three months ended September 30, 2016 and 2015.

• $2 millionincrease in gathering, processing and transportation expenses is primarily due to the sales of our Williston Basin gathering system in the fourth quarter of 2015 and our San Juan Basin gathering system in the first quarter of 2016. Gathering, processing and transportation expenses averaged $2.51 per Boe for the three months ended September 30, 2016 and $2.53 per Boe for the same period in 2015.

• Taxes other than income remained flat for the three months ended September 30, 2016 compared to 2015. Taxes related to our Delaware Basin, which was acquired on August 17, 2015, were offset by a lower rate in the Williston Basin. Taxes other than income averaged $1.84 per Boe for the three months ended September 30, 2016 compared to $2.06 per Boe for the same period in 2015.

• $12 milliondecrease in gas management expenses is primarily due to lower natural gas purchase volumes partially offset by higher average prices on physical natural gas cost of sales, as previously discussed. Also included in gas management expenses is $6 million and $8 million for the three months ended September 30, 2016 and 2015, respectively, for unutilized pipeline capacity.

• $46 milliondecrease in exploration expenses is primarily due to 2015 dry hole costs and impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration related to a non-core exploratory play where we no longer intend to continue exploration activities.

• $14 millionincrease in depreciation, depletion and amortization is primarily due to higher production volumes from our Delaware Basin, which was acquired on August 17, 2015, partially offset by a lower rate in 2016. The lower rate is due in part to our adjusting the proved reserves used for the calculation of depletion and amortization to reflect current estimates based on recent well performance resulting in approximately $10 million of lower depreciation, depletion and amortization. This decrease was more than offset by the $7 million and $5 million increases in the first and second quarters of 2016, respectively, due to our adjusting the proved reserves used for the calculation of depletion and amortization to reflect the impact of an increase in the 12 month average price for those periods. Future decreases or increases in the 12-month average price may result in increases or decreases in our depreciation, depletion and amortization expense. During the three months ended September 30, 2016, our depreciation, depletion and amortization averaged $19.30 per Boe compared to an average $20.37 per Boe for the same period in 2015.

32

• In 2016, we recorded a $238 million loss on the divestment of transportation contracts (see Note 5 of Notes to Consolidated Financial Statements).

• General and administrative expenses include $3 million and $1 million for the three months ended September 30, 2016 and 2015, respectively, for severance and relocation costs associated with workforce reductions. We continue to challenge our levels of general and administrative costs, and we plan to further align our organizational size to achieve an optimal workforce conducive to the current pricing environment and future growth. Costs associated with non-cash equity based compensation was $10 million and $7 million for the three months ended September 30, 2016 and 2015, respectively. General and administrative expenses averaged $6.50 per Boe for the three months ended September 30,2016 compared to $6.72 per Boe for the same period in 2015. Excluding the severance and relocation costs and equity-based compensation, general and administrative expenses averaged $4.92 per Boe for 2016 and $5.54 per Boe for 2015.

• The absence of $23 million of acquisition costs in 2015 related to the acquisition of RKI (see Note 2 of Notes to Consolidated Financial Statements).

Results below operating income (loss)

	Three months ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2016			2015
	(Millions)
Operating income (loss)	$	(301	)	$	33		$	(334	)	NM
Interest expense	(49		)	(65		)	16			25	%
Loss on extinguishment of acquired debt	—			(65		)	65			100	%
Income (loss) from continuing operations before income taxes	(350		)	(97		)	(253		)	NM
Provision (benefit) for income taxes	(132		)	(27		)	105			NM
Income (loss) from continuing operations	(218		)	(70		)	(148		)	NM
Income (loss) from discontinued operations	(1		)	(160		)	159			99	%
Net income (loss) attributable to WPX Energy, Inc.	$	(219	)	$	(230	)	$	11		5	%

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

The decrease in interest expense primarily relates to $16 million of fees in 2015 associated with acquisition bridge financing arrangements related to the Acquisition. No borrowings were made under the acquisition bridge financing arrangements.

The loss on extinguishment of debt in 2015, including a make whole premium, related to the satisfaction and discharge of RKI’s senior notes at the time of the closing of the Acquisition.

Provision (benefit) for income taxes changed favorably due to a greater pre-tax loss for the three months ended September 30, 2016 compared to the same period in 2015. See Note 8 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

Income (loss) from discontinued operations in 2016 changed favorably as the sale of the Piceance Basin closed in second-quarter 2016 and the three months ended September 30, 2015 includes $15 million loss on the sale or the Powder River basin and $187 million recorded upon the exit of the Powder River Basin related to obligations under pipeline capacity, gathering and treating agreements. See Note 3 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.

33

Nine Month-Over-Nine Month Results of Operations

Revenue Analysis

	Nine months ended September 30,					Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2016			2015
	(Millions)
Revenues:
Oil sales	$	378		$	370	$	8		2	%
Natural gas sales	86			104		(18		)	(17	)%
Natural gas liquid sales	27			14		13			93	%
Total product revenues	491			488		3			1	%
Gas management	172			248		(76		)	(31	)%
Net gain (loss) on derivatives	(59		)	239		(298		)	NM
Other	1			6		(5		)	(83	)%
Total revenues	$	605		$	981	$	(376	)	(38	)%

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

Significant variances in the respective line items of revenues are comprised of the following:

• $8 millionincrease in oil sales reflects $88 million increase related to higher production sales volumes substantially offset by a $80 million related to lower sales prices for the nine months ended September 30, 2016 compared to 2015. The increase in production sales volumes relates to our Delaware Basin which was acquired on August 17, 2015. The Delaware Basin volumes were 13.4 MBbls per day for the first nine months of 2016 compared to 1.6 MBbls per day for 2015. The following table reflects oil production prices and volumes for the nine months ended September 30, 2016 and 2015:

	Nine months ended September 30,
	2016		2015
Oil sales (per barrel)	$	34.14	$	41.39
Impact of net cash received related to settlement of derivatives (per barrel)(a)	14.42		30.14
Oil net price including derivative settlements (per barrel)	$	48.56	$	71.53
Oil production sales volumes (MBbls)	11,069		8,927
Per day oil production sales volumes (MBbls/d)	40.4		32.7

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

• $18 milliondecrease in natural gas sales reflects $33 million related to lower sales prices partially offset by a $15 million increase related to higher production sales volumes for the nine months ended September 30, 2016 compared to 2015. The increase in our production sales volumes is due in part to our Delaware Basin which was acquired on August 17, 2015. The increase in sales volumes is partially offset by the impact of the sale of Appalachian Basin assets in the first quarter of 2015. The following table reflects natural gas production prices and volumes for the nine months ended September 30, 2016 and 2015:

34

	Nine months ended September 30,
	2016		2015
Natural gas sales (per Mcf)	$	1.58	$	2.18
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	1.83		3.88
Natural gas net price including derivative settlements (per Mcf)	$	3.41	$	6.06
Natural gas production sales volumes (MMcf)	54,428		47,646
Per day natural gas production sales volumes (MMcf/d)	199		175

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

• $13 millionincrease in natural gas liquids sales is primarily due to production sales volumes in our Delaware Basin, which was acquired on August 17, 2015. The following table reflects NGL production prices and volumes for the nine months ended September 30, 2016 and 2015:

	Nine months ended September 30,
	2016		2015
NGL sales (per barrel)	$	10.24	$	9.20
NGL production sales volumes (MBbls)	2,663		1,588
Per day NGL production sales volumes (MBbls/d)	9.7		5.8

• $76 milliondecrease in gas management revenues is primarily due to lower average prices on physical natural gas sales partially offset by higher natural gas sales volumes. The increase in volumes is due in part to the sale of production volumes pursuant to our purchase agreement with the buyer of the Piceance Basin operations. This agreement ended June 30, 2016. The decrease in the sales price was greater than the decrease in the purchase price as reflected in the $8 million decrease in related gas management costs and expenses, discussed below.

• $298 millionunfavorable change in net gain (loss) on derivatives primarily reflects an unfavorable change in gains (losses) on natural gas and crude derivatives related to production, primarily natural gas and crude, partially offset by a favorable change in gains (losses) on derivatives related to gas management. Settlements from our derivatives totaled $260 million for the nine months ended September 30, 2016 and net settlements were $422 million for the nine months ended September 30, 2015.

35

Cost and operating expense and operating income (loss) analysis

	Nine months ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2016			2015
	(Millions)
Costs and expenses:
Lease and facility operating	$	123		$	101		$	(22	)	(22	)%
Gathering, processing and transportation	55			50			(5		)	(10	)%
Taxes other than income	41			45			4			9	%
Gas management, including charges for unutilized pipeline capacity	202			210			8			4	%
Exploration	31			69			38			55	%
Depreciation, depletion and amortization	465			376			(89		)	(24	)%
Net (gain) loss on sales of assets and divestment of transportation contracts	25			(279		)	(304		)	NM
General and administrative	159			152			(7		)	(5	)%
Acquisition costs	—			23			23			NM
Other—net	14			33			19			58	%
Total costs and expenses	$	1,115		$	780		$	(335	)	(43	)%
Operating income (loss)	$	(510	)	$	201		$	(711	)	NM

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

Significant variances in our costs and expenses are comprised of the following:

• $22 millionincrease in lease and facility operating expenses primarily related to our Delaware Basin which was acquired on August 17, 2015 partially offset by reduced costs across our basins. Lease and facility operating expenses for the nine months ended September 30, 2016 and 2015, included $49 million and $7 million, respectively, from our Delaware Basin. Lease and facility operating expense averaged $5.37 per Boe for the nine months ended September 30, 2016 compared to $5.49 per Boe for the same period in 2015.

• $4 milliondecrease in taxes other than income primarily relates to lower commodity prices and a lower rate in the Williston Basin partially offset by the addition of the Delaware Basin, which was acquired on August 17, 2015. Taxes other than income averaged $1.79 per Boe for the nine months ended September 30, 2016 compared to $2.43 per Boe for the same period in 2015.

• $8 milliondecrease in gas management expenses is primarily due to lower average prices on physical natural gas cost of sales, as previously discussed, and lower crude purchase volumes partially offset by higher natural gas purchase volumes. Also included in gas management expenses are $27 million for both the nine months ended September 30, 2016 and 2015, respectively, for unutilized pipeline capacity.

• $38 milliondecrease in exploration expenses is primarily due to 2015 dry hole costs and impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration related to a non-core exploratory play where we no longer intend to continue exploration activities.

• $89 millionincrease in depreciation, depletion and amortization is primarily due to higher volumes in our Delaware Basin, which was acquired on August 17, 2015, partially offset by lower volumes in our other basins in 2016. The rate per Boe includes the impact of adjusting the proved reserves used for the calculation of depletion and amortization to reflect the impact of a decrease in the 12-month average price in the first and second quarters of 2016, partially offset by additional reserves in the third-quarter of 2016, reflecting current estimates based on recent well performance. Future decreases or increases in the 12-month average price may result in increases or decreases in our depreciation, depletion and amortization expense. During the nine months ended September 30, 2016, our depreciation, depletion and amortization averaged $20.40 per Boe compared to an average $20.37 per Boe for the same period in 2015.

• $25 million net loss on sales of assets and divestment of transportation contracts in 2016 primarily related to a $238 million loss on the divestment of transportation obligations offset by a net $215 gain on the sale of the San Juan Basin gathering system. The $279 million net gain in 2015 primarily related to a $209 million gain on the sale of a package of marketing contracts and release of certain related firm transportation capacity in the second quarter of 2015 and a net gain of $69 million on the sale of a portion of our Appalachian Basin assets in the first quarter of 2015. (See Note 5 of Notes to Consolidated Financial Statements).

36

• General and administrative expenses include $13 million and $16 million for the nine months ended September 30, 2016 and 2015, respectively, for severance and relocation costs associated with workforce reductions and office consolidations. We continue to challenge our levels of general and administrative costs, and we plan to further align our organizational size to achieve an optimal workforce conducive to the current pricing environment and future growth. Costs associated with non-cash equity-based compensation was $25 million and $24 million for the nine months ended September 30, 2016 and 2015, respectively. General and administrative expenses averaged $6.97 per Boe for the nine months ended September 30, 2016 compared to $8.18 per Boe for the same period in 2015. Excluding the severance and relocation costs and equity-based compensation, general and administrative expenses would have averaged $5.31 per Boe for 2016 and $5.98 per Boe for 2015.

• $23 million of acquisition costs in 2015 related to the acquisition of RKI (see Note 2 of Notes to Consolidated Financial Statements.)

• $19 milliondecrease in other expenses primarily related to expenses recorded in association with a contract termination in the first quarter of 2015 (see Note 5 of Notes to Consolidated Financial Statements).

Results below operating income (loss)

	Nine months ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2016			2015
	(Millions)
Operating income (loss)	$	(510	)	$	201		$	(711	)	NM
Interest expense	(159		)	(130		)	(29		)	(22	)%
Loss on extinguishment of acquired debt	—			(65		)	65			NM
Investment income and other	1			2			(1		)	(50	)%
Income (loss) from continuing operations before income taxes	(668		)	8			(676		)	NM
Provision (benefit) for income taxes	(227		)	3			230			NM
Income (loss) from continuing operations	(441		)	5			(446		)	NM
Income (loss) from discontinued operations	12			(197		)	209			NM
Net income (loss)	(429		)	(192		)	(237		)	123	%
Less: Net income (loss) attributable to noncontrolling interests	—			1			(1		)	(100	)%
Net income (loss) attributable to WPX Energy, Inc.	$	(429	)	$	(193	)	$	(236	)	122	%

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

The increase in interest expense primarily relates to the notes issued in the third quarter of 2015, partially offset by $16 million of fees expensed in 2015 associated with acquisition bridge financing arrangements related to the Acquisition.

The loss on extinguishment of debt in 2015, including a make whole premium, related to the satisfaction and discharge of RKI’s senior notes at the time of the closing of the Acquisition.

Provision (benefit) for income taxes in 2016 changed favorably compared to 2015 due to a pre-tax loss from continuing operations in 2016 compared to pre-tax income in 2015. See Note 8 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

Income (loss) from discontinued operations in 2016 changed favorably as the sale of the Piceance Basin closed in second-quarter 2016 resulting in a net gain of $53 million. Discontinued operation for 2015 include a $15 million loss on the sale of the Powder River Basin and $187 million recorded upon the exit of the Powder River Basin related to obligations for pipeline capacity, gathering and treating agreements. See Note 3 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.

37

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview and Liquidity

Our main sources of liquidity are cash on hand, internally generated cash flow from operations and our bank credit facility. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities. In consideration of our liquidity, we note the following:

• as of September 30, 2016, we maintained liquidity through cash, cash equivalents and available credit capacity under our credit facility; and

• our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support.

Outlook

We expect our capital structure will provide us financial flexibility to meet our requirements for working capital, capital expenditures and tax and debt payments while maintaining a sufficient level of liquidity. Our primary sources of liquidity in 2016 are expected cash flows from operations, proceeds from the issuance of equity securities, proceeds from monetization of assets and, if necessary, borrowings on our credit facility. We anticipate that the combination of these sources should be sufficient to allow us to pursue our business strategy and goals through 2018.

We note the following assumptions for the remainder of 2016:

• our planned capital expenditures, excluding acquisitions and Piceance related capital, for all of 2016 are estimated to be approximately $400 million to $450 million. As of September 30, 2016, we have incurred $397 million of capital expenditures, including $60 million for land acquisitions, and an additional $27 million related to the Piceance Basin;

• we seek to further reduce debt and we may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. As of September 30, 2016, the remaining outstanding balance of the Senior Notes due in 2017 was $125 million. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors; and

• for the remainder of 2016 we have hedged 30,403 Bbls per day of our anticipated 2016 oil production at a weighted-average price of $60.13 per barrel. WPX has natural gas derivatives totaling 145,510 MMBtu per day for the remainder of 2016, at a weighted price of $3.93 per MMBtu. WPX has hedged 34,554 Bbls per day of our anticipated 2017 oil production at a weighted-average price of $51.45 per barrel.  We have also hedged 170,000 MMBtu per day of our anticipated 2017 natural gas production at a weighted-average price of $3.02 per MMBtu.

Potential risks associated with our planned levels of liquidity and the planned capital expenditures discussed above include:

• lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices;

• higher than expected collateral obligations that may be required;

• higher capital costs for developing our properties;

• significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold;

• reduced access to our credit facility pursuant to our financial covenants; and

• higher than expected operating costs.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses throughout 2016 and beyond. In addition, we continually evaluate the level of our 2016 capital program given our expectations of our cash on hand and forecasted cash flows for the remainder of 2016. Our internal and external sources of consolidated liquidity include cash generated from operations, cash and cash equivalents on hand, and our available credit facility capacity. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities.

Equity Offering

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 10 of Notes to Consolidated Financial Statements).        

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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 is a senior secured revolving credit facility with $1.2 billion in commitments and a maturity date of October 28, 2019. Since the time of closing of the Credit Facility, a Collateral Trigger Period has been in effect. During a Collateral Trigger Period, Loans will be subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. As of October 2016, the Borrowing Base was reaffirmed at $1.025 billion and will remain in effect until the next date the Borrowing Base is re-determined pursuant to the Credit Facility. 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 September 30, 2016, we were in compliance with our financial covenants, had full access to the Credit Facility and did not have any outstanding borrowings. For additional information regarding the terms of our Credit Facility see Note 7 of Notes to Consolidated Financial Statements.

We currently have three bilateral, uncommitted letter of credit agreements most of which expire during 2016. These agreements allow us to preserve our liquidity under our Credit Facility while providing support to our ability to meet performance obligation needs for, among other items, various interstate pipeline contracts into which we have entered. These unsecured agreements incorporate similar terms as those in the Credit Facility. As a result of the divestment of our Piceance Basin transportation contracts, we eliminated approximately $162 million in letters of credit and their associated annual interest expense. At September 30, 2016, a total of $66 million in letters of credit have been issued, a majority of which provide support for interstate pipeline contracts. As these letter of credit agreements expire, we expect to issue letters of credit under our Credit Facility.

Sources (Uses) of Cash

	Nine months ended September 30,
	2016		2015
	(Millions)
Net cash provided (used) by:
Operating activities	$	109	$	629
Investing activities	460		(1,259		)
Financing activities	16		659
Increase (decrease) in cash and cash equivalents	$	585	$	29

Operating activities

Our net cash provided by operating activities for the nine months ended September 30, 2016 decreased from the same period in 2015 primarily due to an unfavorable change in net settlements related to derivatives, lower net gas management revenues and expenses, income taxes paid in 2016 and lower commodity prices, partially offset by higher production volumes. Excluding changes in working capital, total cash provided by operating activities related to discontinued operations was approximately $28 million for the nine months ended September 30, 2016. Excluding changes in working capital, total cash used by operating activities related to discontinued operations was approximately $56 million for the nine months ended September 30, 2015.

Investing activities

Cash capital expenditures for drilling and completions were $351 million and $774 million for the nine months ended September 30, 2016 and 2015, respectively. Cash capital expenditures for drilling and completions related to our Piceance Basin were $26 million and $204 million for the nine months ended September 30, 2016 and 2015, respectively. Capital expenditures incurred for drilling and completions were $342 million and $555 million during the nine months ended September 30, 2016 and 2015, respectively. Capital expenditures incurred for drilling and completions related to our Piceance Basin were $22 million and $142 million during the nine months ended September 30, 2016 and 2015, respectively. In addition, expenditures related to international were $15 million for the nine months ended September 30, 2015.

Cash provided by investing activities in 2016 was also impacted by a $238 million divestment of certain transportation contracts (see Note 9 of Notes to the Consolidated Financial Statements). Cash used by investing activities in 2015 also includes $209 million for the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast during May 2015 (see Note 5 of Notes to Consolidated Financial Statements).

On August 17, 2015 we successfully closed the purchase of RKI and paid approximately $1.2 billion in cash, net of cash acquired and net of certain distributions.

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Significant components related to proceeds from the sale of our domestic assets and international interests are comprised of the following:

2016

•$862 million for the sale of WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations to Terra Energy Partners, LLC (see Note 3 of Notes to Consolidated Financial Statements).

•$280 million for the sale of our San Juan Basin gathering system to a portfolio company of ISQ Global Infrastructure Fund, a fund managed by I Squared Capital during the first quarter of 2016 (see Note 5 of Notes to Consolidated Financial Statements).

2015

•$50 million for the portion of our Powder River Basin asset sale that closed in the third quarter of 2015 (see Note 3 of Notes to Consolidated Financial Statements).

•$271 million for the sale of a portion of our Appalachian Basin operations and release of certain firm transportation capacity to Southwestern Energy Company during the first quarter of 2015 (see Note 5 of Notes to Consolidated Financial Statements).

•$291 million after expenses but before $17 million of cash on hand at Apco as of the closing date, for the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol (see Note 3 of Notes to Consolidated Financial Statements).

Financing activities

2016

On June 6, 2016, we completed an equity offering of 56.925 million shares of our common stock for net proceeds of approximately $538 million.

Net cash provided by financing activities for the nine months ended September 30, 2016 also reflects net repayments under the Credit Facility of $265 million, $230 million repayment of our Senior Notes due 2017, $15 million of preferred stock dividends, and $10 million of cash paid as an inducement for the conversion of preferred stock to common stock.

2015

On July 22, 2015 we completed equity offerings of 30 million shares of our common stock for net proceeds of approximately $292 million and 6.25% series A mandatory convertible preferred stock for net proceeds of approximately $339 million.

On July 22, 2015, we completed a debt offering of (a) $500 million aggregate principal amount of 7.500% senior unsecured notes due 2020 and (b) $500 million aggregate principal amount of 8.250% senior unsecured notes due 2023.

Cash provided by financing activities for the nine months ended September 30, 2015 also included cash used to retire $600 million of outstanding debt on RKI's revolving credit facility and $455 million for the satisfaction and discharge of RKI's senior notes which included a $55 million make-whole premium.

Net cash provided by financing activities for the nine months ended September 30, 2015 was also impacted by borrowings under the Credit Facility in excess of repayments. In August, 2015 we utilized borrowings under the credit facility for the acquisition of RKI.

Contractual Obligations

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 $363 million as of September 30, 2016.

Following the sale of our Piceance Basin operations and the subsequent divestment of the remaining transportation contracts in the Piceance Basin (see Note 9 of Notes to Consolidated Financial Statements), our total contractual obligations for transportation and storage decreased from approximately $686 million as of December 31, 2015 to approximately $128 million as of September 30, 2016.

Off-Balance Sheet Financing Arrangements

We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at September 30, 2016 or at December 31, 2015.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first nine months of 2016.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of oil, natural gas and natural gas liquids as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our marketing trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Notes 11 and 12 of Notes to Consolidated Financial Statements.

We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.

We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.

Trading

Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was zero at September 30, 2016 and December 31, 2015. The value at risk for contracts held for trading purposes was zero at September 30, 2016 and December 31, 2015.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our energy commodity purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $13 million and $344 million at September 30, 2016 and December 31, 2015, respectively.

The value at risk for derivative contracts held for nontrading purposes was $34 million at September 30, 2016 and $19 million at December 31, 2015. During the last 12 months, our value at risk for these contracts ranged from a high of $34 million to a low of $19 million.

Item 4. Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (“Disclosure Controls”) or our internal control over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. The design of any system of controls is

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also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in internal controls during the third quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 9 of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

Item 1A. Risk Factors

Risk Factor resulting from the June 2016 Equity Offering

Our ability to utilize our net operating loss (“NOL”) carryovers for income tax purposes to reduce future taxable income will be limited if we undergo an ownership change.

Beginning with our 2015 tax year, we generated an NOL that is being carried forward to future years. In the event that we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”)), our NOL carryovers generated prior to the ownership change would be subject to annual limitations, which could defer or eliminate our ability to utilize these tax losses against future taxable income. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns 5% or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50% over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Although we do not anticipate an “ownership change” resulting in limitations under Section 382 on the use of our NOLs for income tax purposes, future changes in the ownership of our stock could result in the application of such limitations.

In addition, Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K, for the year ended December 31, 2015, includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed as of September 30, 2016.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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EXHIBITS

Exhibit No.	Description
2.1**	Agreement and Plan of Merger, dated October 2, 2014, by and among Pluspetrol Resources Corporation, Pluspetrol Black River Corporation and Apco Oil and Gas International Inc. (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on October 7, 2014)
2.2**	Agreement and Plan of Merger, dated as of July 13, 2015, by and among RKI Exploration & Production, LLC, WPX Energy, Inc. and Thunder Merger Sub LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
2.3**	Membership Interest Purchase Agreement by and Among WPX Energy Holdings, LLC, as Seller, WPX Energy, Inc., solely for purposes of Section 14.15, and Terra Energy Partners LLC, as Purchaser, dated February 8, 2016 (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2016)
3.1	Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
3.2	Certificate of Amendment of Amended and Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
3.3	Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 21, 2014)
3.4	Certificate of Designations for 6.25% Series A Mandatory Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
4.1	Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)
4.2	Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.3	First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.4	Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
10.1	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)
10.2	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
10.3	Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
10.4	Form of Change in Control Agreement between WPX Energy, Inc. and CEO (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 23, 2012) (1)
10.5	Form of Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 23, 2012) (1)

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Exhibit No.	Description
10.6	WPX Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 29, 2013) (1)
10.7	WPX Energy, Inc. 2011 Employee Stock Purchase Plan (incorporated herein by reference to Exhibit 4.4 to WPX Energy, Inc.’s registration statement on Form S-8 (File No. 333-178388) filed with the SEC on December 8, 2011) (1)
10.8	Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011) (1)
10.9	Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.10	Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.11	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015) (1)
10.12	Form of Stock Option Agreement between WPX Energy, Inc. and Section 16 Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014) (1)
10.13	WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
10.14	WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
10.15	Retirement Agreement, dated December 16, 2013, between WPX Energy, Inc. and Ralph A. Hill (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on December 17, 2013)
10.16	Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.17	Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.18	Form of 2014 Time-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.19	Form of 2014 Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.20	Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.21	Form of Performance-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.6 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.22	Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)

45

Exhibit No.	Description
10.23	Separation and Release Agreement, dated July 28, 2014, between WPX Energy, Inc. and James J. Bender (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
10.24	WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 19, 2014) (1)
10.25	Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)
10.26	Form of Voting and Support Agreement, dated as of July 13, 2015, by and between WPX Energy, Inc. and the Member signatory thereto (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
10.27	First Amendment to the Amended and Restated Credit Agreement, dated as of July 16, 2015, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as existing Administrative Agent and existing Swingline Lender, and Wells Fargo Bank, National Association, as successor Administrative Agent and successor Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
10.28	Commitment Increase Agreement for Amended and Restated Credit Agreement, dated as of July 31, 2015, among WPX Energy, Inc., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, and the Issuing Banks thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on August 6, 2015)
10.29	Registration Rights Agreement dated August 17, 2015, among WPX Energy, Inc. and the signatures thereto (incorporated herein by reference to Exhibit 10.35 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015)
10.30	Second Amendment to the Amended and Restated Credit Agreement, dated as of March 18, 2016, by and among WPX Energy, Inc., as the borrower thereunder, the financial institutions party thereto from time to time, as lenders, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 22, 2016)
10.31	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
10.32	Form of Severance and Restrictive Covenant Agreement between WPX Energy, Inc. and Marcia MacLeod (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
10.33*	Form of Severance and Restrictive Covenant Agreement between WPX Energy, Inc. and Michael Fiser (1)
12*	Computation of Ratio of Earnings to Fixed Charges
31.1*	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

*	Filed herewith
**	All schedules to the Merger Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the SEC upon request
(1)	Management contract or compensatory plan or arrangement

46

47

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WPX Energy, Inc. (Registrant)
By:	/s/ Stephen L. Faulkner
	Stephen L. Faulkner Controller (Principal Accounting Officer)

Date: November 3, 2016

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EX-10.33

Exhibit 10.33

SEVERANCE AND RESTRICTIVE COVENANT AGREEMENT

This SEVERANCE AND RESTRICTIVE COVENANT AGREEMENT (this “Agreement”), effective this 16th of August, 2016 (“Effective Date”) by and between WPX Energy, Inc.,WPX Energy Services Company, LLC, and their respective subsidiaries and affiliates (collectively the “Company”), and Michael Fiser (the “Executive”), sets forth the terms and understandings regarding the Executive’s separation from the Company.

WHEREAS, the Executive currently serves as SVP Marketing; and

WHEREAS, the Executive’s employment is to be terminated; and

WHEREAS, the Company is providing to the Executive severance benefits pursuant to the WPX Energy Executive Severance Pay Plan (“Plan”), subject to the Executive’s timely execution of this Agreement and the Release described herein and subject to the Executive’s satisfaction of all other terms and conditions described in the Plan and this Agreement; and

WHEREAS, the Executive and the Company wish to settle their mutual rights and obligations arising in connection with the Executive’s service with the Company and the Executive’s separation from such service; and

WHEREAS, in consideration of the rights and benefits under this Agreement, the Executive has agreed to enter into certain covenants for the benefit of the Company as set forth herein.

NOW, THEREFORE, in consideration of the mutual covenants and promises herein contained, including the restrictive covenants, the Company and the Executive hereby agree as follows:

1. Separation from Service

(a) Employment Termination. The Executive’s employment shall be terminated on September 2, 2016 (the “Termination Date”). Effective on the Termination Date, the Executive hereby resigns from any and all officer and director positions the Executive may have with the Company and its subsidiaries and affiliates. The Executive shall promptly execute any additional documentation the Company may request to reflect such resignations.

(b) Transition Period. For the period from the Effective Date through the Termination Date (such period, the “Transition Period”), the Executive shall continue as an employee of the Company and shall perform such duties and responsibilities as shall be reasonably requested by the Board of Directors or the Chief Executive Officer (“CEO”) of the Company, including as necessary to effect a smooth and effective transition of the Executive’s duties and responsibilities. During the Transition Period, the Executive shall remain subject to all applicable Company policies and procedures, including without limitation the Company’s securities trading policies for officers and directors.

2. Compensation

(a) Base Salary through Termination Date. The Executive shall be entitled to continue to receive the Executive’s current annual base salary through the Termination Date, which shall be paid in accordance with the Company’s normal payroll practices.

(b) Employee Benefits. Until the Termination Date, the Executive shall continue to be entitled to participate as an active employee in those employee benefit plans and programs in which the Executive currently participates, subject to the terms and conditions of such plans. Effective as of the Termination Date, the Executive’s active participation in such plans shall cease, and the Executive shall continue to have all rights to accrued and vested benefits under such plans in accordance with their terms.

3. Severance Benefits and Conditions

(a) Severance Payment. Subject to Section 3(e), the Executive shall receive a severance payment equal to the sum of:

(1)Four hundred eighty-six thousand dollars ($486,000) which is equal to 1.5x the Executive’s “Base Salary”, as such term is defined in the Plan, plus

(2)an additional payment of $316,828.05 which is equal to the Executive’s “Average AIP Payment” as such term is defined in the Plan.

(b) COBRA Equivalent Payment. Subject to Section 3(e), if the Executive is enrolled in Company-sponsored medical and prescription coverage on the Executive’s Termination Date, the Executive will receive an additional severance payment equal to the monthly premium for Consolidated Omnibus Budget Reconciliation Act (“COBRA”) continuation coverage for the medical and prescription coverage elected by the Executive and in effect on such date multiplied by twelve (12) (the “COBRA Equivalent Payment”). Dental, vision and health care flexible spending account coverage premiums will not be included in determining such payment.

(c)Additional Payment.Subject to Section 3(e), although such payment is not required to be made to the Executive pursuant to the Plan or any other agreement, policy, practice, incentive compensation plan or award agreement, in lieu of the equity award that was communicated to Executive in 2016 and disclosed via Form 4, Company will pay Executive in the amount of $400,000.00, less applicable withholdings required by law. Nothing in this Agreement should be construed as an indication or affirmation that Executive was otherwise entitled to an equity award or payment in lieu of an equity award for the year 2016 and by agreeing to accept this Additional Payment, in accordance with the terms of this Agreement, Executive specifically waives any and all claims, known and unknown, related to any equity awards for 2016 that were or were not granted to Executive.

(d) Time of Severance Payment. Subject to Section 3(e) and Section 21, payment of the amounts described in Sections 3(a), (b) and (c) shall be made during the sixty (60) day period following the Termination Date. If such amounts could be paid in more than one calendar year, they will be paid in the latest calendar year in which the payment could be made.

(e) Release of Claims. The rights, payments, and benefits to be provided to the Executive under this Agreement are subject to the Executive’s execution and delivery to the Company and non-revocation of an effective general release and waiver of claims in the form attached hereto as Exhibit A (the “Release”), which must be executed and delivered to the Company during the fifty (50) day period following the Termination Date.

(f) Employment Status. This Agreement is not intended to and does not alter the Executive’s status as an at-will employee or create a contract of employment for any definite period

of time.

(g)Rehire. In the event the Executive is rehired by the Company after the receipt of benefits described in Sections 3(a) and (b), the Executive shall be subject to the repayment provisions described in Section 3.6 of the Plan.

(h)Outplacement Services. The Company will pay up to $25,000 for executive outplacement services provided to the Executive by a reputable third party outplacement provider approved by the Company, provided that such expenses must be incurred within nine (9) months after the Executive’s Termination Date, but in all events no payments for such outplacement services will be made after fifteen (15) months following the Participant’s Termination Date.

4. Accrued Rights. The Company shall pay and provide to the Executive in accordance with its customary practices: (i) all base salary earned but not yet paid through the Termination Date, (ii) reimbursement for any and all business expenses properly incurred prior to the Termination Date, payable in accordance with and subject to the terms of the Company’s reimbursement policy and submitted for reimbursement within sixty (60) days of the Termination Date, and (iii) any employee benefits required to be provided to the Executive pursuant to the terms of the Company’s employee benefit plans and as required by applicable law.

5. Outstanding Equity Awards. All outstanding stock options, restricted stock units, or other forms of equity compensation held by the Executive as of the Termination Date shall be governed by the terms of the incentive compensation plans and award agreements pursuant to which such awards were issued to the Executive, with the Termination Date constituting the date of the Executive’s termination of service for purposes of such grants.

6. Indemnification. The Executive (i) shall be indemnified and held harmless by the Company on the same terms as other executive officers and directors to the greatest extent permitted under applicable law as the same now exists or may hereafter be amended and the Company’s by-laws as such exist on the Termination Date, or such greater rights that may be provided by amendment to such by-laws from time to time, if the Executive was, is or is threatened to be made to a party to any pending, completed, or threatened action, suit, arbitration, alternative dispute resolution mechanism, investigation, administrative hearing, or any other proceeding whether civil, criminal, administrative, or investigative, and whether formal or informal, by reason of the fact that the Executive is or was, or had agreed to become, a director, officer, employee, agent, or fiduciary of the Company or any other entity which the Executive is or was serving at the request of the Company, against all expenses (including reasonable attorneys’ fees) and all claims, damages, liabilities, and losses incurred or suffered by the Executive or to which the Executive may become subject for any reason, and (ii) shall be entitled to advancement of any such indemnifiable expenses in accordance with the Company’s by-laws as such exist on the Termination Date, or such greater rights that may be provided by amendment to such by-laws from time to time.

7. Directors’ and Officers’ Insurance. The Executive shall be entitled to coverage under a directors’ and officers’ liability insurance policy issued in favor of Companyin an amount no less than, and on the same terms as those provided to, other executive officers and directors of the Company.

8. Restrictive Covenants

(a) Confidential Information. The Executive acknowledges that in the course of performing services for the Company and its affiliates, the Executive may have obtained information, observations, and data (including but not limited to information concerning current or prospective

exploration and development activities, information concerning business strategies or plans, financial information relating to the business of the Company or its subsidiaries and affiliates, accounts, customers, vendors, employees, and other affairs) that is not otherwise in the public domain (collectively, “Confidential Information”). The Executive recognizes that all such Confidential Information is the sole and exclusive property of the Company and its affiliates or of third parties to which the Company or an affiliate owes a duty of confidentiality, that it is the Company’s policy to safeguard and keep confidential all such Confidential Information, and that disclosure of Confidential Information to an unauthorized third party would cause irreparable damage to the Company and its affiliates. The Executive agrees that, except as required by the duties of the Executive’s employment with the Company or any of its affiliates and except in connection with enforcing the Executive’s rights under this Agreement or if compelled by a court or governmental agency, in each case provided that prior written notice is given to the Company, the Executive will not, without the written consent of the Company, willfully disseminate or otherwise disclose, directly or indirectly, any Confidential Information disclosed to the Executive or otherwise obtained by the Executive during the Executive’s employment with the Company or its affiliates, and will take all necessary precautions to prevent disclosure to any unauthorized individual or entity (whether or not such individual or entity is employed or engaged by, or is otherwise affiliated with, the Company or any affiliate), and will use the Confidential Information solely for the benefit of the Company and its affiliates and will not use the Confidential Information for the benefit of any other individual or entity nor permit its use for the benefit of the Executive. These obligations shall continue during and after the Executive’s termination from service and for so long as the Confidential Information remains Confidential Information. For the avoidance of doubt, nothing in the foregoing shall preclude the Executive from disclosing Confidential Information for purposes of reporting a violation of state or federal law to a relevant law enforcement agency, including, without limitation, to the Securities and Exchange Commission pursuant to Section 21F of the Securities Exchange Act of 1934 or any similar provision of state or federal law and the rules and regulations promulgated thereunder.

(b) Non-Competition. From the date hereof and continuing for six (6) months following the Termination Date, the Executive agrees that without the written consent of the Company, the Executive shall not at any time, directly or indirectly, in any capacity:

(i) engage or participate in, become employed by, serve as a director of, or render advisory or consulting or other services in connection with, any energy business and any individual or entity (and any branch, office or operation thereof) which engages in, or proposes to engage in (with the Executive’s assistance) any of the following in which the Executive has been engaged in the twelve (12) months preceding the Termination Date: the exploration and/or production of oil or gas which is located anywhere in the United States (a “Competitive Business”); provided, however, that after the Termination Date, this Section 8(b)(i) shall not preclude the Executive from (A) being an employee of, or consultant to, any business unit of a Competitive Business if (x) such business unit does not qualify as a Competitive Business in its own right and (y) the Executive does not have any direct or indirect involvement in, or responsibility for, any operations of such Competitive Business that cause it to qualify as a Competitive Business, or (B) with the approval of an Authorized Company Executive, being a consultant to, an advisor to, a director of, or an employee of a Competitive Business (for purposes of this Section 8(b), an “Authorized Company Executive” shall mean the individual then serving as the Chief Executive Officer); or

(ii) make or retain any financial investment, whether in the form of equity or debt, or own any interest, in any Competitive Business. Nothing in this subsection shall, however,

restrict the Executive from making an investment in any Competitive Business if such investment does not (A) represent more than 1% of the aggregate market value of the outstanding capital stock or debt (as applicable) of such Competitive Business, (B) give the Executive any right or ability, directly or indirectly, to control or influence the policy decisions or management of such Competitive Business, or (C) create a conflict of interest between the Executive’s duties to the Company and its affiliates or under this Agreement and the Executive’s interest in such investment.

(c) Non-Solicitation. From the date hereof and continuing for twelve (12) months following the Termination Date, the Executive agrees that without the written consent of the Company, the Executive shall not at any time, directly or indirectly, in any capacity:

(i) cause or attempt to cause any employee, director, or consultant of the Company or an affiliate to terminate his or her relationship with the Company or an affiliate;

(ii) employ, engage as a consultant or adviser, or solicit the employment or engagement as a consultant or adviser, of any employee of the Company or an affiliate (other than by the Company or its affiliates), or cause or attempt to cause any person or entity to do any of the foregoing;

(iii) interfere with the relationship of the Company or an affiliate with, or endeavor to entice away from the Company or an affiliate, any person or entity who or which at any time during the period commencing twelve (12) months prior to the Termination Date was or is, to the Executive’s knowledge, a material customer or material supplier of, or maintained a material business relationship with, the Company or an affiliate; or;

(iv) solicit the sale of goods, services or a combination of goods and services from the established customers of the Company or an affiliate.

(d)Non-Disparagement.

(i) The Executive agrees not to make, or cause to be made, any statement, observation or opinion, or communicate any information (whether oral or written, directly or indirectly) that (A) accuses or implies that the Company or any of its affiliates, together with their respective present or former officers, directors, partners, stockholders, employees, and agents, and each of their predecessors, successors, and assigns, engaged in any wrongful, unlawful or improper conduct, whether relating to the Executive’s employment (or the separation therefrom), the business or operations of the Company or otherwise; or (B) disparages, impugns, or in any way reflects adversely upon the business or reputation of the Company or any of its affiliates, together with their respective present or former officers, directors, partners, stockholders, employees, and agents, and each of their predecessors, successors, and assigns.

(ii) The Company agrees that it will not, and will instruct the members of the Board of Directors of the Company and the executive officers of the Company to not, disparage or denigrate the Executive orally or in writing (including, without limitation, any comments or statements relating to the Executive’s performance at the Company).

(iii) Notwithstanding anything contained herein to the contrary, nothing herein shall be deemed to preclude the Executive or the Company from providing truthful testimony or

information pursuant to subpoena, court order, or other similar legal or regulatory process, provided, that to the extent permitted by law, the Executive will promptly inform the Company of any such obligation prior to participating in any such proceedings.

(e)Duty to Inform.

The Executive agrees to inform any employer, business, entity, or individual with whom the Executive becomes associated in a business capacity during the term of the restrictions of this Section 8 of Executive’s obligations under this Section 8.

(f) Reasonableness of Restrictive Covenants.

(i) The Executive acknowledges that the covenants contained in this Agreement are reasonable in the scope of the activities restricted, the geographic area covered by the restrictions, and the duration of the restrictions, and that such covenants are reasonably necessary to protect the Company’s legitimate interests in its Confidential Information, its proprietary work, and in its relationships with its employees, customers, suppliers, and agents.

(ii) The Company has, and the Executive has had an opportunity to, consult with their respective legal counsel and to be advised concerning the reasonableness and propriety of such covenants. The Executive acknowledges that the Executive’s observance of the covenants contained herein will not deprive the Executive of the ability to earn a livelihood or to support the Executive’s dependents.

(g) Right to Injunction: Survival of Undertakings.

(i) In recognition of the confidential nature of the Confidential Information, and in recognition of the necessity of the limited restrictions imposed by this Agreement, the Executive and the Company agree that it would be impossible to measure solely in money the damages which the Company would suffer if the Executive were to breach any ofthe Executive’s obligations hereunder. The Executive acknowledges that any breach of any provision of this Agreement would irreparably injure the Company. Accordingly, the Executive agrees that if the Executive breaches any of the provisions of Section 8 of this Agreement, the Company shall be entitled, in addition to any other remedies to which the Company may be entitled under this Agreement or otherwise, to an injunction to be issued by a court of competent jurisdiction, to restrain any breach, or threatened breach, of any provision of this Agreement without the necessity of posting a bond or other security therefore, and the Executive hereby waives any right to assert any claim or defense that the Company has an adequate remedy at law for any such breach.

(ii) If a court determines that any covenant included in this Section 8 is unenforceable in whole or in part because of such covenant’s duration or geographical or other scope, such court shall have the power to modify the duration or scope of such provision, as the case may be, so as to cause such covenant as so modified to be enforceable. Furthermore, if a court determines that a certain form of remedy or relief sought by the Company for the breach of a covenant included in this Section 8 is unavailable under applicable law, such a finding shall not prohibit the Company from obtaining a different form of remedy or relief with respect to such breach which such court has not found to be unavailable.

(iii) All of the provisions of this Agreement shall survive any separation from service of the Executive.

(h) Effect of Breach of Covenants. If a court of competent jurisdiction shall have found that the Executive is in material breach of any restrictive covenant contained in this Agreement or the Release, the Executive forfeits the Executive’s right to receive any payment or benefit under this Agreement and shall pay to the Company the value of any payment or benefit previously received by the Executive under this Agreement.

9. Cooperation. Following the Termination Date, the Executive agrees to fully cooperate with and provide reasonable assistance to the Company and its counsel in connection with any general business matters, transition of work, agency investigations or audits or litigation or corporate matters, and to be reasonably available to the Company to do so at times and locations as to not interfere with the Executive’s duties and responsibilities to any future employer, job seeking opportunities, or any personal responsibilities.

10. Return of Company Property.The Executive shall promptly following the Termination Date return to the Company all documents, records, files, and other information and property belonging or relating to the Company, its affiliates, customers, clients, or employees. The Executive acknowledges that all such materials are, and will remain, the exclusive property of the Company, and the Executive may not retain originals or copies of such materials without the express written approval of the Company. Any Company-related information shall be expunged from any home equipment, and any office connectivity or other continued internet or similar services provided by the Company shall cease.

11. Recoupment. Notwithstanding anything herein to the contrary, this Agreement shall not impact any rights or restrictions under the Company’s Recoupment Policy for incentive compensation, as adopted by the Board of Directors of the Company and referred to in the Company’s most recent proxy statement filed with the Securities and Exchange Commission, as such Recoupment Policy may be amended from time to time, and the Executive acknowledges and agrees the Executive remains subject to the terms of such policy following the Termination Date.

12. Severability. In the event that any one or more of the provisions of this Agreement are held to be invalid, illegal, or unenforceable, the validity, legality, and enforceability of the remainder of this Agreement shall not in any way be affected or impaired thereby.

13. Waiver. No waiver by either party of any breach by the other party of any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of any other provision or condition at the time or at any prior or subsequent time.

14. Governing Law. This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of Oklahoma, without reference to its choice of law rules.

15. Withholding. The Company shall deduct or withhold, or require the Executive to remit to the Company, the minimum statutory amount to satisfy federal, state or local taxes required by law or regulation to be withheld with respect to any benefit provided hereunder.

16. Entire Agreement. This Agreement, including all other agreements expressly incorporated or referred to herein, shall constitute the entire agreement and understanding of the parties with respect to the subject matter herein and supersedes all prior agreements, arrangements and understandings, written or oral, between the parties with respect to the subject matter herein. The Executive acknowledges that the Executive is not eligible for and shall not receive any additional separation or severance payment under any plan or

program maintained by the Company. The Executive acknowledges and agrees that the Executive is not relying on any representations or promises by any representative of the Company concerning the meaning of any aspect of this Agreement or the Release. This Agreement and the Release may not be altered or modified other than in a writing signed by the Executive and an authorized representative of the Company.

17. Notices. All notices given hereunder shall be given in writing, shall specifically refer to this Agreement and shall be personally delivered or sent by telecopy or other electronic facsimile transmission or by registered or certified mail, return receipt requested, at the address set forth below or at such other address as may hereafter be designated by notice given in compliance with the terms hereof:

If to the Executive:At the most recent address on the Company’s records

If to the Company:WPX Energy, Inc.

3500 One Williams Center

Tulsa, Oklahoma 74172-0172

Attention: General Counsel

Facsimile: (539) 573-5608

If notice is mailed, such notice shall be effective upon mailing, or if notice is personally delivered or sent by telecopy or other electronic facsimile transmission, it shall be effective upon receipt.

18. Successors and Assigns. This Agreement is intended to bind and inure to the benefit of and be enforceable by the Executive, the Company and their respective heirs, successors and assigns, except that the Executive may not assign the Executive’s rights or delegate the Executive’s obligations hereunder without the prior written consent of the Company.

19. Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.

20. Section 409A.

(a) Compliance. The intent of the parties is that payments and benefits under this Agreement are either exempt from or comply with Section 409A of the Internal Revenue Code (“Section 409A”), and this Agreement shall be interpreted to that end. The parties acknowledge and agree that the interpretation of Section 409A and its application to the terms of this Agreement is uncertain and may be subject to change as additional guidance and interpretations become available. In no event whatsoever shall the Company be liable for any tax, interest or penalties that may be imposed on the Executive by Section 409A or any damages for failing to comply with Section 409A.

(b) Six Month Delay for Specified Employees. If any payment, compensation or other benefit provided to the Executive in connection with the Executive’s separation from service is determined, in whole or in part, to constitute “nonqualified deferred compensation” within the meaning of Section 409A and the Executive is a “specified employee” as defined in Section 409A, no part of such payments shall be paid before the day that is six (6) months plus one (1) day after the Termination Date or, if earlier, the Executive’s death (the “New Payment Date”). The aggregate of any payments that otherwise would have been paid to the Executive during the period between the Termination Date and the New Payment Date shall be paid to the Executive in a lump sum on such New Payment Date. Thereafter, any payments that remain outstanding as of the day immediately following the New Payment Date shall be paid without delay over the time period originally scheduled, in accordance with the terms of this Agreement.

(c) Separation from Service. A separation from service shall not be deemed to have occurred for purposes of any provision of this Agreement providing for the payment of any amounts or benefits subject to Section 409A upon or following a separation from service until such separation is also a “separation from service” within the meaning of Section 409A and for purposes of any such provision of this Agreement, references to a “resignation,” “termination,” “terminate,” “termination of employment” or like terms shall mean separation from service.

(d) Payments for Reimbursements and In-Kind Benefits. All reimbursements for costs and expenses under this Agreement shall be paid in no event later than the end of the calendar year following the calendar year in which the Executive incurs such expense. With regard to any provision herein that provides for reimbursement of costs and expenses or in-kind benefits, except as permitted by Section 409A, (i) the right to reimbursement or in-kind benefits shall not be subject to liquidation or exchange for another benefit, and (ii) the amount of expenses eligible for reimbursements or in-kind benefits provided during any taxable year shall not affect the expenses eligible for reimbursement or in-kind benefits to be provided in any other taxable year.

(e) Payments within Specified Number of Days. Whenever a payment under this Agreement specifies a payment period with reference to a number of days, the actual date of payment shall be within the sole discretion of the Company.

(f) Installments as Separate Payment. If under this Agreement, an amount is paid in two (2) or more installments, for purposes of Section 409A, each installment shall be treated as a separate payment.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the dates set forth below.

WPX ENERGY, INC.

By: /s/ Richard E. Muncrief

Date: August 16, 2016

Title:President and Chief Executive Officer

WPX ENERGY SERVICES COMPANY, LLC

By: /s/ Richard E. Muncrief

Date: August 16, 2016

Title:President and Chief Executive Officer

EXECUTIVE:

By: /s/ Michael Fiser

Date: August 16, 2016

[Signature Page to Severance and Restrictive Covenant Agreement]

Exhibit A

RELEASE AGREEMENT

This RELEASE AGREEMENT (this “Release”), dated , 20___, by and between WPX Energy, Inc., WPX Energy Services Company, LLC, and their respective subsidiaries and affiliates (collectively the “Company”), and Michael Fiser (the “Executive”).

WHEREAS, the Executive and the Company have entered into a Severance and Restrictive Covenant Agreement dated _____________________, 20___ (the “Severance Agreement”);

NOW THEREFORE, in consideration for receiving separation benefits under the Severance Agreement and in consideration of the representations, covenants and mutual promises set forth in this Release, the parties agree as follows:

1. Release. Except with respect to all of the Company’s obligations under the Severance Agreement, the Executive, and the Executive’s heirs, executors, assigns, agents, legal representatives, and personal representatives, hereby releases, acquits and forever discharges the Company, its agents, subsidiaries, affiliates, and their respective officers, directors, agents, servants, employees, attorneys, shareholders, partners, members, managers, successors, assigns and affiliates (the “Released Parties”), of and from any and all claims, liabilities, demands, causes of action, costs, expenses, attorney’s fees, damages, indemnities and obligations of every kind and nature, in law, equity, or otherwise, known and unknown, suspected and unsuspected, disclosed and undisclosed, arising out of or in any way related to agreements, events, acts or conduct at any time prior to the execution of this Release that arose out of or were related to the Executive’s employment with the Company or the Executive’s separation from service with the Company including, but not limited to, claims or demands related to wages, salary, bonuses, commissions, stock, stock options, or any other ownership interests in the Company, vacation pay, fringe benefits, expense reimbursements, sabbatical benefits, severance benefits, or any other form of compensation or equity or thing of value whatsoever; claims pursuant to under Title VII of the Civil Rights Act of 1964 as amended by the Civil Rights Act of 1991, 42 U.S.C. § 2000e, et seq.; 42 U.S.C. § 1981; 42 U.S.C. § 1983; 42 U.S.C. § 1985; 42 U.S.C. § 1986; the Equal Pay Act of 1963, 29 U.S.C. § 206(d); the National Labor Relations Act, as amended, 29 U.S.C. § 160, et seq.; the Americans With Disabilities Act of 1990, 42 U.S.C. § 12101, et seq.; the Employee Retirement Income Security Act of 1974, as amended, (“ERISA”), 29 U.S.C. § 1001, et seq.; the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, 29 U.S.C.§ 621, et seq.; the Family and Medical Leave Act of 1993, 29 U.S.C.§ 2601 et seq.; the Equal Pay Act; the Rehabilitation Act of 1973; the federal Worker Adjustment and Retraining Notification Act (as amended) and similar laws in other jurisdictions; the Oklahoma Anti-Discrimination Act, Okla. Stat., tit. 25, §§ 1101, et seq., and any claims for wrongful discharge, breach of contract, breach of the implied covenant of good faith and fair dealing, fraud, discrimination, harassment, defamation, infliction of emotional distress, termination in violation of public policy, retaliation, including workers’ compensation retaliation under state statutes, tort law; contract law; wrongful discharge; discrimination; fraud; libel; slander; defamation; harassment; emotional distress; breach of the implied covenant of good faith and fair dealing; or claims for whistle-blowing, or other claims arising under any local, state or federal regulation, statute or common law. This Release does not apply to the payment of any and all benefits and/or monies earned, accrued, vested or otherwise owing, if any, to the Executive under the terms of a Company sponsored tax qualified retirement or savings plan and/or any non-qualified deferred compensation plan(s) sponsored by the Company, except that the Executive hereby releases and waives any claims thatthe Executive’s separation from service was to avoid payment of such benefits or payments, and that, as a result of the Executive’s separation, the Executive is entitled to additional benefits or payments. Additionally, this Release does not apply to the indemnification provided or any other payments or benefits to which the Executive is entitled pursuant to the Severance

Agreement (including, without limitation, in the outstanding equity awards referenced in Section 5 thereof). This Release does not apply to any claim or rights which might arise out of the actions of the Company after the date the Executive signs this Release or any other claims or rights that Executive is prohibited from waiving under applicable law.

2. Covenant Not to Sue. By signing this Release, the Executive covenants, agrees, represents and warrants that the Executive has not filed and will not in the future file any lawsuits, complaints, petitions or accusatory pleadings in a court of law or in conjunction with a dispute resolution program against any of the Released Parties based upon, arising out of or in any way related to any event or events occurring prior to the signing of this Release, including, without limitation,the Executive’s employment with any of the Released Parties or the termination thereof. Nothing in this Release shall limit the Executive’s right to file a charge or complaint with any state or federal agency or to participate or cooperate in such a matter. However, the Executive expressly waives all rights to recovery for any damages or compensation awarded as a result of any suit or proceeding brought by any third party or governmental agency on the Executive’s behalf. For the avoidance of doubt, the foregoing does not extend to any monetary award from a law enforcement agency, including, without limitation, the Securities and Exchange Commission, relating to reporting by the Executive of a violation of state or federal law.

3. No Assignment of Claims. By signing this Release, the Executive further covenants, agrees, represents and warrants that the Executive has not heretofore assigned or transferred, or purported to assign or transfer, to any person or entity, any claim or any portion thereof or interest therein and acknowledges that this Release shall be binding upon the Executive and upon the Executive’s heirs, administrators, representatives, executors, successors, and assigns, and shall inure to the benefit of each of the Released Parties, and to their heirs, administrators, representatives, executors, successors, and assigns.

4. No Release of Vested Benefits or Health and Welfare Benefits. Except as to claims based grants or failure to grant equity in 2016, by signing this Release, the Executive does not release or discharge any right to any vested, deferred benefit in any qualified employee benefit plan which provides for retirement, pension, savings, thrift and/or employee stock ownership or any benefit due the Executive as a participant in any employee health and welfare plan, as such terms are used under ERISA, which is maintained by any of the Released Parties that employed the Executive.

5. No Admission of Liability. Notwithstanding the provisions of this Release and the payments to be made by the Company to the Executive hereunder, the Released Parties do not admit any manner of liability to the Executive. This Release has been entered into as a means of settling any and all disputes between the Released Parties and the Executive.

6. No Inducement. The Executive agrees that no promise or inducement to enter into this Release has been offered or made except as set forth in this Release or the Severance Agreement, that the Executive is entering into this Release without any threat or coercion and without reliance or any statement or representation made on behalf of the Company or by any person employed by or representing the Company, except for the written provisions and promises contained in this Release or the Severance Agreement.

7. Damages. The parties agree that damages incurred as a result of a breach of this Release will be difficult to measure. It is, therefore, further agreed that, in addition to any other remedies, equitable relief will be available in the case of a breach of this Release. It is also agreed that, in the event the Executive files a claim against the Company with respect to a claim released by the Executive herein (other than a proceeding before the EEOC), the Company may withhold, retain, or require reimbursement of all or any portion of the benefits and Separation Payment under the Severance Agreement until such claim is withdrawn by the Executive.

8. Advice of Counsel; Time to Consider; Revocation. The Executive acknowledges the following:

(a) The Executive has read this Release, and understands its legal and binding effect. The Executive is acting voluntarily and of the Executive’s own free will in executing this Release.

(b) The Executive has been advised to seek and has had the opportunity to seek legal counsel in connection with this Release.

(c) The Executive was given at least forty-five (45) days to consider the terms of this Release before signing it.

The Executive understands that, if the Executive signs this Release, the Executive may revoke it within seven (7) days after signing it by delivering written notification of intent to revoke within that seven (7) day period. The Executive understands that this Release will not be effective until after the seven (7) day period has expired.

9. Severability. If all or any part of this Release is declared by any court, arbitrator or governmental authority to be unlawful, invalid, void or unenforceable, such unlawfulness, invalidity or unenforceability shall not affect the validity or enforceability of any other portion of this Release. Any section or a part of a section declared to be unlawful, invalid, void or unenforceable shall, if possible, be construed in a manner which will give effect to the terms of the section to the fullest extent possible while remaining lawful and valid. To the extent that any provision of this Release is adjudicated to be unlawful, invalid, void or unenforceable because it is overbroad, that provision shall not be void but rather shall be limited only to the extent required by applicable law and enforced as so limited. The parties expressly acknowledge and agree that this Section is reasonable in view of the parties’ respective interests.

10. Amendment. This Release shall not be altered, amended, or modified except by written instrument executed by the Company and the Executive. A waiver of any portion of this Release shall not be deemed a waiver of any other portion of this Release.

11. Counterparts. This Release may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same instrument.

12. Headings. The headings of this Release are not part of the provisions hereof and shall not have any force or effect.

13. Rules of Construction. Reference to a specific law shall include such law, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing or superseding such section.

14. Applicable Law. The provisions of this Release shall be interpreted and construed in accordance with the laws of the State of Oklahoma without regard to its choice of law principles.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, the parties hereto have executed this Release as of the dates set forth below.

WPX ENERGY, INC.

By: /s/

Date: _______________________________

Title:_______________________________

WPX ENERGY SERVICES COMPANY, LLC

By: /s/

Date:_______________________________

Title: ________________________________

EXECUTIVE:

By: /s/

Date: _______________________________

[Signature Page to Release Agreement]

EX-12.1

Exhibit 12

WPX Energy, Inc.

Computation of Ratio of Earnings to Fixed Charges

	Nine months ended September 30,
	2016
	(Millions)
Earnings:
Income (loss) from continuing operations before income taxes	$	(668	)
Less: Equity earnings, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees	(1		)
Income (loss) before income taxes and equity earnings	(669		)
Add:
Fixed Charges:
Interest accrued, including proportionate share from 50% owned investees and unconsolidated majority-owned investees (a)	159
Rental expense representative of interest factor	5
Total fixed charges	164
Total earnings as adjusted	$	(505	)
Fixed charges	$	164
Ratio of earnings to fixed charges	(b)
Preferred dividend requirement	$	6
Combined fixed charges and preferred dividends	170
Ratio of earnings to combined fixed charges and preferred dividends	(c)

__________

(a) Does not include interest related to income taxes, including interest related to liabilities for uncertain tax positions, which is included in provision (benefit) for income taxesin our Consolidated Statements of Operations.

(b) Earnings are inadequate to cover fixed charges by $669 million.

(c) Earnings are inadequate to cover combined fixed charges and preferred dividends by $675 million.

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Richard E. Muncrief, certify that:

1.I have reviewed this quarterly report on Form 10-Q of WPX Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 3, 2016

/s/ Richard E. Muncrief

Richard E. Muncrief

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, J. Kevin Vann, certify that:

1.I have reviewed this quarterly report on Form 10-Q of WPX Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 3, 2016

/s/ J. Kevin Vann

J. Kevin Vann

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of WPX Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Richard E. Muncrief

Richard E. Muncrief

President and Chief Executive Officer

November 3, 2016

/s/ J. Kevin Vann

J. Kevin Vann

Senior Vice President and Chief Financial Officer

November 3, 2016

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 02, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	WPX
Entity Registrant Name	WPX ENERGY, INC.
Entity Central Index Key	0001518832
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		344,461,810

XML

Consolidated Balance Sheet (Unaudited) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 623	$ 38
Accounts receivable, net of allowance of $5 million as of September 30, 2016 and $6 million as of December 31, 2015		147	300
Derivative assets, current		79	308
Inventories		33	46
Assets classified as held for sale, current		7	178
Other		20	23
Total current assets		909	893
Properties and equipment (successful efforts method of accounting)		8,796	8,415
Less—accumulated depreciation, depletion and amortization		(2,314)	(1,893)
Properties and equipment, net		6,482	6,522
Derivative assets, noncurrent		31	51
Assets classified as held for sale, noncurrent		0	894
Other noncurrent assets		24	33
Total assets		7,446	8,393
Current liabilities:
Accounts payable		185	278
Accrued and other current liabilities		259	301
Liabilities associated with assets held for sale		2	140
Current portion of long-term debt, net	[1]	125	1
Derivative liabilities, current		53	13
Total current liabilities		624	733
Deferred income taxes		323	465
Long-term debt, net	[2]	2,574	3,189
Derivative liabilities, noncurrent		44	2
Asset retirement obligations		105	99
Liabilities associated with assets held for sale, Noncurrent		0	133
Other noncurrent liabilities		142	237
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares issued at September 30, 2016 and 7 million shares issued at December 31, 2015)		232	339
Common stock (2 billion shares authorized at $0.01 par value; 344.5 million shares issued at September 30, 2016 and 275.4 million shares issued at December 31, 2015)		3	3
Additional paid-in-capital		6,799	6,164
Accumulated deficit		(3,400)	(2,971)
Total stockholders’ equity		3,634	3,535
Total liabilities and equity		$ 7,446	$ 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.

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Consolidated Balance Sheet (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 5	$ 6
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred Stock, Shares Issued	4,800,000	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	344,535,601	275,400,000

XML

Consolidated Statement of Operations (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Product revenues:
Oil sales		$ 139	$ 120	$ 378	$ 370
Natural gas sales		37	37	86	104
Natural gas liquid sales		12	6	27	14
Total product revenues		188	163	491	488
Gas management		25	35	172	248
Net gain (loss) on derivatives (Note 12)		38	205	(59)	239
Other		0	4	1	6
Total revenues		251	407	605	981
Costs and expenses:
Lease and facility operating		40	34	123	101
Gathering, processing and transportation		19	17	55	50
Taxes other than income		14	14	41	45
Gas management, including charges for unutilized pipeline capacity		31	43	202	210
Exploration (Note 5)		10	56	31	69
Depreciation, depletion and amortization		150	136	465	376
Net (gain) loss on sales of assets and divestment of transportation contracts (Note 5)		227	(2)	25	(279)
General and administrative (including non-cash equity-based compensation of $10 million, $7 million, $25 million and $24 million for the respective periods)	[1]	51	45	159	152
Acquisition Costs (Note 2)		0	23	0	23
Other—net		10	8	14	33
Total costs and expenses		552	374	1,115	780
Operating income (loss)		(301)	33	(510)	201
Interest expense		(49)	(65)	(159)	(130)
Loss on extinguishment of acquired debt		0	(65)	0	(65)
Investment income and other		0	0	1	2
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest		(350)	(97)	(668)	8
Provision (benefit) for income taxes (Note 8)		(132)	(27)	(227)	3
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		(218)	(70)	(441)	5
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		(1)	(160)	12	(197)
Net income (loss)		(219)	(230)	(429)	(192)
Less: Net income (loss) attributable to noncontrolling interests		0	0	0	1
Comprehensive Income (Loss), Net of Tax, Attributable to Parent		(219)	(230)	(429)	(193)
Preferred Stock Dividends, Income Statement Impact		4	4	15	4
Preferred Stock Conversions, Inducements		22	0	22	0
Net Income (Loss) Available to Common Stockholders, Basic		(245)	(234)	(466)	(197)
Amounts attributable to WPX Energy, Inc. common stockholders:
Income (Loss) from Continuing Operations Attributable to Parent		(244)	(74)	(478)	1
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent		$ (1)	$ (160)	$ 12	$ (198)
Income (Loss) from Continuing Operations, Per Basic Share		$ (0.72)	$ (0.29)	$ (1.58)	$ 0.01
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share		0.00	(0.64)	0.04	(0.90)
Earnings Per Share, Basic		$ (0.72)	$ (0.93)	$ (1.54)	$ (0.89)
Weighted Average Number of Shares Outstanding, Basic		341.5	251.2	302.8	220.3
Income (Loss) from Continuing Operations, Per Diluted Share		$ (0.72)	$ (0.29)	$ (1.58)	$ 0.01
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share		0.00	(0.64)	0.04	(0.90)
Earnings Per Share, Diluted		$ (0.72)	$ (0.93)	$ (1.54)	$ (0.89)
Weighted Average Number of Shares Outstanding, Diluted	[2]	341.5	251.2	302.8	221.7

[1] General and administrative expense includes non-cash equity-based compensation of $10 million and $7 million for the three months ended September 30, 2016 and 2015, respectively; and $25 million and $24 million for the nine months ended September 30, 2016 and 2015, respectively.

[2] The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders. Three monthsended September 30, Nine monthsended September 30, 2016 2015 2016 2015 (Millions)Weighted-average nonvested restricted stock units and awards2.4 0.7 1.8 —Weighted-average stock options— 0.1 — —Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 10)23.8 26.7 23.8 9.0

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Consolidated Statement of Operations (parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Non-cash equity-based compensation expense	$ 10	$ 7	$ 25	$ 24

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Consolidated Statement of Changes in Equity (Unaudited) - 9 months ended Sep. 30, 2016 - USD ($) $ in Millions	Total	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					(429)	(429)
Stock based compensation				16		16
Stock Issued During Period, Value, New Issues				538		538
Conversion of Stock, Amount Issued		(107)		118		11
Preferred Stock Conversions, Inducements	$ (22)			(22)		(22)
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings				(15)		(15)
September 30, 2016 at Sep. 30, 2016		$ 232	$ 3	$ 6,799	$ (3,400)	$ 3,634

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Consolidated Statements of Cash Flows - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Operating Activities(a)
Comprehensive income (loss) attributable to WPX Energy, Inc.		$ (429)	$ (192)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation Depletion And Amortization Including Discontinued Portion		474	685
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations		(209)	(138)
Provision for impairment of properties and equipment (including certain exploration expenses)		29	78
Net gain (loss) on derivatives (Note 12)		59	(239)
Derivative, Cash Received on Hedge		260	422
Unrealized Loss on Derivatives, including Discontinued Operations		46	0
Amortization of stock-based awards		27	27
Gain (Loss) on Extinguishment of Debt		0	(81)
Net (gain) loss on sales of assets and divestment of transportation contracts		(28)	(317)
Cash provided (used) by operating assets and liabilities:
Accounts receivable		147	232
Inventories		13	(11)
Margin deposits and customer margin deposits payable		0	25
Other current assets		6	0
Accounts payable		(79)	(186)
Federal income taxes payable		(33)	0
Accrued and other current liabilities		(97)	22
Accrued liabilities established in 2015 for retained transportation and gathering contracts related to discontinued operations		(42)	0
Other, including changes in other noncurrent assets and liabilities		(35)	140
Net cash provided by operating activities(a)	[1]	109	629
Investing Activities(a)
Capital expenditures	[2]	(440)	(890)
Proceeds from sales of assets		1,140	610
Payments for (Proceeds from) Investments		(238)	209
Payments to Acquire Investments		0	1,190
Other		(2)	2
Net cash provided by (used in) investing activities(a)	[1]	460	(1,259)
Financing Activities
Proceeds from common stock		540	295
Proceeds from Issuance of Preferred Stock and Preference Stock		0	339
Dividends paid on preferred stock		(15)	0
Payments for Repurchase of Redeemable Convertible Preferred Stock		(10)	0
Proceeds from Issuance of Long-term Debt		0	1,000
Borrowings on credit facility		380	756
Payments on credit facility		(645)	(636)
Payments for retirement of debt		(230)	(1,055)
Payments for credit facility amendment fees, debt issuance cost and acquisition bridge financing fees		(3)	(40)
Other		(1)	0
Net cash provided by (used in) financing activities		16	659
Net increase (decrease) in cash and cash equivalents		585	29
Cash and Cash Equivalents, at Carrying Value, Including Discontinued Operations		38	70
Cash and cash equivalents at end of period		623	99
Increase to properties and equipment		(424)	(640)
Changes in related accounts payable and accounts receivable		(16)	(250)
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]	59	(260)
Derivative, Cash Received on Hedge		$ 260	$ 454

[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(424) (640)Changes in related accounts payable and accounts receivable(16) (250)Capital expenditures(440) (890)

[3] Includes settlements totaling $59 million and $159 million for the three months ended September 30, 2016 and 2015, respectively; and settlements totaling $260 million and $454 million for the nine months ended September 30, 2016 and 2015, respectively.

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Basis of Presentation and Description of Business

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Basis of Presentation and Description of Business

Description of Business and Basis of Presentation

Description of Business

Operations of our company include oil, natural gas and NGL development, production, and gas management activities primarily located in Texas, North Dakota, New Mexico and Colorado. 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 which ended June 30, 2016 (see Note 3).    

In addition, we had other operations sold in 2015 and 2016 reported as discontinued operations, as discussed below.

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 September 30, 2016, results of operations for the three and nine months endedSeptember 30, 2016 and 2015, changes in equity for the nine months endedSeptember 30, 2016 and cash flows for the nine months endedSeptember 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 in Colorado 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, discontinued operations include the results of our Powder River Basin operations in Wyoming which were sold on September 1, 2015. Discontinued operations also include our 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 which was sold on January 29, 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. ASU 2014-09 can be applied using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is currently evaluating the method of adoption and 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 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.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which provides new guidance for eight specific cash flow issues. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The Company does not expect the adoption of ASU 2016-15 to have a significant impact on the Company’s Consolidated Statements of Cash Flows.

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Acquisitions (Notes)

9 Months Ended

Sep. 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. We adjusted the purchase price allocation resulting in an increase of $60 million to both properties and equipment and deferred taxes in the third quarter of 2016.

The following table presents the unaudited pro forma financial results for the three and nine months ended September 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 ended September 30,		Nine months ended September 30,
	2015		2015
	(Millions)
Revenues	$	504	$	1,193
Net income from continuing operations attributable to WPX Energy, Inc.	$	40	$	90

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Discontinued Operations Discontinued Operations (Notes)

9 Months Ended

Sep. 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, subject to post-closing adjustments, resulting in a gain of $53 million. We performed certain transition services for the buyer which concluded 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.

In August 2015, we signed agreements for the sale of our Powder River Basin for $80 million. On September 1, 2015, we completed a portion of the Powder River Basin divestiture. The remaining portion of the divestiture, which related to an equity method investment in Fort Union Gas Gathering, LLC, closed on October 30, 2015. We recorded a pre-tax loss of $15 million related to this divestment during third quarter 2015. During the first and second quarters of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices for the Powder River Basin. In addition, we retained certain firm gathering and treating obligations with total commitments of $104 million through 2020 related to the Powder River properties sold. These commitments had been in excess of our production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company with total commitments through 2021 totaling $150 million, which were related to the Powder River operations. With the closing of the Powder River Basin sale and exiting this basin, we recorded $187 million of expense related to these contracts, which is included as a separate line below. This $187 million expense is the estimated present value of the $254 million in payments associated with these contracts remaining as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from third parties and discounting based on our risk adjusted borrowing rate. During third quarter 2015, we received $13 million in escrow funds as a result of terminating a previous sales contract for the Powder River Basin assets and this amount is included in Other-net expense below. The Powder River Basin operations are included in our domestic results presented below.

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 September 30, 2016			Three months ended September 30, 2015
	Domestic and Total			Domestic and Total
	(Millions)
Total revenues	$	—		$	142
Costs and expenses:
Lease and facility operating	$	—		$	22
Gathering, processing and transportation	1			68
Taxes other than income	1			4
Depreciation, depletion and amortization	—			106
General and administrative	1			13
Accrual for contract obligations retained	—			187
Other—net	(2		)	(14		)
Total costs and expenses	1			386
Operating income (loss)	(1		)	(244		)
Investment income and other	—			3
Gain (loss) on sale of domestic assets	1			(15		)
Income (loss) from discontinued operations before income taxes	—			(256		)
Provision (benefit) for income taxes	1			(96		)
Income (loss) from discontinued operations	$	(1	)	$	(160	)

	Nine months ended September 30, 2016			Nine months ended September 30, 2015
	Domestic and Total			Domestic			International			Total
	(Millions)
Total revenues(a)	$	64		$	466		$	15		$	481
Costs and expenses:
Lease and facility operating	$	18		$	80		$	4		$	84
Gathering, processing and transportation	49			205			—			205
Taxes other than income	2			18			3			21
Gas management	—			1			—			1
Depreciation, depletion and amortization	9			309			—			309
Impairment of assets held for sale	—			16			—			16
General and administrative	9			34			1			35
Accrual for contract obligations retained	—			187			—			187
Other—net	4			(9		)	—			(9		)
Total costs and expenses	91			841			8			849
Operating income (loss)	(27		)	(375		)	7			(368		)
Investment income and other	—			6			1			7
Gain (loss) on sale of domestic assets and international interests	53			(15		)	41			26
Income (loss) from discontinued operations before income taxes	26			(384		)	49			(335		)
Provision (benefit) for income taxes(b)	14			(135		)	(3		)	(138		)
Income (loss) from discontinued operations	$	12		$	(249	)	$	52		$	(197	)

__________

(a) The nine months ended September 30, 2016 includes $33 million net loss on derivatives.

(b) The nine months ended September 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the nine months ended September 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 September 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 $28 million and used by domestic operating activities was $59 million for the nine months ended September 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 $42 million for the nine months ended September 30, 2016. Cash provided by operating activities related to our international operations was $3 million for the nine months ended September 30, 2015. Total cash used in investing activities related to domestic discontinued operations was $32 million and $219 million for the nine months ended September 30, 2016 and 2015, respectively. Total cash used in investing activities related to our international operations was $15 million for the nine months ended September 30, 2015.

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Earnings (Loss) Per Common Share from Continuing Operations

9 Months Ended

Sep. 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 ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	(218	)	$	(70	)	$	(441	)	$	5
Less: Dividends on preferred stock	4			4			15			4
Less: Loss on induced conversion of preferred stock	22			—			22			—
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	(244	)	$	(74	)	$	(478	)	$	1
Basic weighted-average shares	341.5			251.2			302.8			220.3
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	—			—			—			1.3
Stock options	—			—			—			0.1
Diluted weighted-average shares	341.5			251.2			302.8			221.7
Earnings (loss) per common share from continuing operations:
Basic	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01
Diluted	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01

__________

(a) The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders.

	Three months ended September 30,		Nine months ended September 30,
	2016	2015	2016	2015
	(Millions)
Weighted-average nonvested restricted stock units and awards	2.4	0.7	1.8	—
Weighted-average stock options	—	0.1	—	—
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 10)	23.8	26.7	23.8	9.0

The table below includes information related to stock options that were outstanding at September 30, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.

	September 30,
	2016		2015
Options excluded (millions)	2.4		2.6
Weighted-average exercise price of options excluded	$	16.46	$	16.16
Exercise price range of options excluded	$11.75 - $21.81		$11.46 - $21.81
Third quarter weighted-average market price	$	11.11	$	8.36

For the nine months ended September 30, 2016 and 2015, approximately 0.1 million and 1.1 million, respectively, nonvested restricted stock units were antidilutive and were excluded from the computation of diluted weighted-average shares.

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Asset Sales, Other Expenses and Exploration Expense

9 Months Ended

Sep. 30, 2016

Extractive Industries [Abstract]

Asset Sales, Exploration Expenses And Other Accruals [Text Block]

Asset Sales, Other Expenses and Exploration Expenses

Asset Sales and Divestment of Transportation Contracts

During July 2016, we completed the divestment of the remaining transportation contracts primarily related to our Piceance Basin operations which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment to Terra. The total remaining commitments related to these contracts for the remainder of 2016 and thereafter were approximately $400 million. As a result of the divestments and net payment of $238 million, we recorded a net loss of $238 million in third-quarter 2016.

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 additional gains of $5 million and $11 million in the second and third quarters of 2016, respectively, as certain in-progress construction was completed. As of September 30, 2016, the deferred gain was $14 million related to an estimated $4 million of remaining recorded obligations 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 ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(Millions)
Geologic and geophysical costs	$	1	$	3	$	2	$	5
Dry hole costs and impairments of exploratory area well costs	—		22		1		22
Unproved leasehold property impairment, amortization and expiration	9		31		28		42
Total exploration expenses	$	10	$	56	$	31	$	69

For both the three and nine months ended September 30, 2015, dry hole costs and impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration include $21 million and $26 million, respectively, related to a non-core exploratory play where we no longer intend to continue exploration activities.

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Inventories

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Inventories

Inventories

The following table presents a summary of our inventories as of the dates indicated below.

	September 30, 2016		December 31, 2015
	(Millions)
Material, supplies and other	$	31	$	44
Crude oil production in transit	2		2
Total inventories	$	33	$	46

During the third quarter of 2016, we recorded an impairment of material and supplies inventory of approximately $4 million.

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Debt and Banking Arrangements

9 Months Ended

Sep. 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.

	September 30, 2016		December 31, 2015
	(Millions)
5.250% Senior Notes due 2017	$	125	$	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		1
Total debt	$	2,726	$	3,221
Less: Current portion of long-term debt, net(a)	125		1
Total long-term debt	$	2,601	$	3,220
Less: Debt issuance costs on long-term debt(b)	27		31
Total long-term debt, net(b)	$	2,574	$	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 2016, we repurchased approximately $230 million of our 5.250% Senior Notes due 2017, including $87 million we redeemed through a tender offer.

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

OnMarch 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 September 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. The Borrowing Base was reaffirmed at $1.025 billion in October 2016. 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 April 1, 2017 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 during 2016. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility. As a result of the divestment of our Piceance Basin transportation contracts, we eliminated approximately $162 million in letters of credit and their associated annual interest expense. At September 30, 2016, a total of $66 million in letters of credit have been issued, a majority of which support interstate pipeline contracts. As these letter of credit agreements expire, we expect to issue letters of credit under our Credit Facility.

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Provision (Benefit) for Income Taxes

9 Months Ended

Sep. 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 ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(Millions)
Current:
Federal	$	—		$	(4	)	$	—		$	(4	)
State	(5		)	(1		)	(5		)	(1		)
	(5		)	(5		)	(5		)	(5		)
Deferred:
Federal	(117		)	(26		)	(236		)	7
State	(10		)	4			14			1
	(127		)	(22		)	(222		)	8
Total provision (benefit)	$	(132	)	$	(27	)	$	(227	)	$	3

The effective income tax rate for the three months ended September 30, 2016, differs from the federal statutory rate due to the effects of state income taxes.

The effective income tax rate for the nine months endedSeptember 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 nine months endedSeptember 30, 2015, differs from the federal statutory rate due to the effects of state income taxes and certain nondeductible acquisition costs.

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 September 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 September 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 IRS 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.

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Contingent Liabilities

9 Months Ended

Sep. 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. On August 16, 2016, the court denied plaintiffs’ motion for class certification. On September 15, 2016, plaintiffs filed their motion for reconsideration and filed a second motion for class certification. 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 September 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 September 30, 2016 and December 31, 2015, the Company had accrued approximately $17 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.

Commitments

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 $363 million as of September 30, 2016.

As previously discussed in Note 5, we divested of transportation contracts in the third quarter of 2016 which eliminated certain pipeline capacity commitments for the remainder of 2016 and thereafter totaling 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 are approximately $128 million as of September 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 this liability totaled approximately $99 million as of September 30, 2016 (see Note 3).

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Stockholder's Equity (Notes)

9 Months Ended

Sep. 30, 2016

Stockholders' Equity Attributable to Parent [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

Note 10. Stockholders’ Equity

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 agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders 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 made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million.

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 retired the shares of Preferred Stock converted in the Conversion. By entering into the Conversion and associated transactions early, we reduced cash dividend payments and continued simplifying our capital and cost structure.

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.

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Fair Value Measurements

9 Months Ended

Sep. 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.

	September 30, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	110	$	—	$	110	$	—	$	359	$	—	$	359
Energy derivative liabilities	$	—	$	97	$	—	$	97	$	—	$	15	$	—	$	15
Total debt(a)	$	—	$	2,752	$	—	$	2,752	$	—	$	2,495	$	—	$	2,495

__________

(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,725 million and $3,220 million as of September 30, 2016 and December 31, 2015, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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 quarterly 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 September 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 September 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.

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Derivatives and Concentration of Credit Risk

9 Months Ended

Sep. 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 September 30, 2016.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Crude Oil
Crude Oil	Oct -Dec 2016	Fixed Price Swaps	WTI	(30,403	)	$	60.13
Crude Oil	Oct -Dec 2016	Basis Swaps	Midland-Cushing	(5,000	)	$	(0.45	)
Crude Oil	Oct -Dec 2016	Fixed Price Calls	WTI	(1,900	)	$	50.70
Crude Oil	2017	Fixed Price Swaps	WTI	(29,554	)	$	51.31
Crude Oil	2017	Swaptions	WTI	(3,264	)	$	51.22
Crude Oil	2017	Fixed Price Calls	WTI	(4,500	)	$	56.47
Crude Oil	2018	Fixed Price Swaps	WTI	(13,000	)	$	58.33
Crude Oil	2018	Fixed Price Calls	WTI	(13,000	)	$	58.89
Natural Gas
Natural Gas	Oct -Dec 2016	Fixed Price Swaps	Henry Hub	(146	)	$	3.93
Natural Gas	Oct -Dec 2016	Basis Swaps	Permian	(38	)	$	(0.17	)
Natural Gas	Oct -Dec 2016	Basis Swaps	San Juan	(100	)	$	(0.18	)
Natural Gas	2017	Fixed Price Swaps	Henry Hub	(150	)	$	2.98
Natural Gas	2017	Basis Swaps	Permian	(58	)	$	(0.20	)
Natural Gas	2017	Basis Swaps	San Juan	(93	)	$	(0.17	)
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 Swaps	Henry Hub	(40	)	$	2.91
Natural Gas	2018	Fixed Price Calls	Henry Hub	(16	)	$	4.75
Natural Gas	2018	Swaptions	Henry Hub	(20	)	$	3.33
Commodity	Period	Contract Type	Location(d)	Notional Volume (b)		Weighted Average Price
Physical Derivatives
Natural Gas	Oct -Dec 2016	Index	Multiple	(65	)	(e)
Natural Gas	2017	Index	Multiple	(16	)	(e)

__________

(a) Derivatives related to crude oil production are fixed price swaps, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas 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 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.

	September 30, 2016				December 31, 2015
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Total derivatives	$	110	$	97	$	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 for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.

	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
	(Millions)
Gain (loss) from derivatives related to production(a)	$	38	$	206		$	(59	)	$	260
Gain (loss) from derivatives related to physical marketing agreements(b)	—		(1		)	—			(21		)
Net gain (loss) on derivatives	$	38	$	205		$	(59	)	$	239

__________

(a) Includes settlements totaling $59 million and $159 million for the three months ended September 30, 2016 and 2015, respectively; and settlements totaling $260 million and $454 million for the nine months ended September 30, 2016 and 2015, respectively.

(b) Includes payments totaling $4 million and $32 million for the three months and nine months ended September 30, 2015, respectively.

The cash flow impact of our derivative activities is presented as separate 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)			Net Amount
September 30, 2016	(Millions)
Derivative assets with right of offset or master netting agreements	$	110		$	(69	)	$	41
Derivative liabilities with right of offset or master netting agreements	$	(97	)	$	69		$	(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 September 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 $2 million to our liability balance for our own nonperformance risk. There would have been collateral totaling $30 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 September 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 September 30, 2016.

Counterparty Type	Gross Total		Net Total
	(Millions)
Financial institutions (Investment Grade)(a)	$	110	$	41
Credit exposure from derivatives	$	110	$	41

__________

(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 99 percent of our net credit exposure. 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.

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Acquisitions (Tables)

9 Months Ended

Sep. 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 nine months ended September 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 ended September 30,		Nine months ended September 30,
	2015		2015
	(Millions)
Revenues	$	504	$	1,193
Net income from continuing operations attributable to WPX Energy, Inc.	$	40	$	90

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Discontinued Operations Discontinued Operation (Tables)

9 Months Ended

Sep. 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 September 30, 2016			Three months ended September 30, 2015
	Domestic and Total			Domestic and Total
	(Millions)
Total revenues	$	—		$	142
Costs and expenses:
Lease and facility operating	$	—		$	22
Gathering, processing and transportation	1			68
Taxes other than income	1			4
Depreciation, depletion and amortization	—			106
General and administrative	1			13
Accrual for contract obligations retained	—			187
Other—net	(2		)	(14		)
Total costs and expenses	1			386
Operating income (loss)	(1		)	(244		)
Investment income and other	—			3
Gain (loss) on sale of domestic assets	1			(15		)
Income (loss) from discontinued operations before income taxes	—			(256		)
Provision (benefit) for income taxes	1			(96		)
Income (loss) from discontinued operations	$	(1	)	$	(160	)

	Nine months ended September 30, 2016			Nine months ended September 30, 2015
	Domestic and Total			Domestic			International			Total
	(Millions)
Total revenues(a)	$	64		$	466		$	15		$	481
Costs and expenses:
Lease and facility operating	$	18		$	80		$	4		$	84
Gathering, processing and transportation	49			205			—			205
Taxes other than income	2			18			3			21
Gas management	—			1			—			1
Depreciation, depletion and amortization	9			309			—			309
Impairment of assets held for sale	—			16			—			16
General and administrative	9			34			1			35
Accrual for contract obligations retained	—			187			—			187
Other—net	4			(9		)	—			(9		)
Total costs and expenses	91			841			8			849
Operating income (loss)	(27		)	(375		)	7			(368		)
Investment income and other	—			6			1			7
Gain (loss) on sale of domestic assets and international interests	53			(15		)	41			26
Income (loss) from discontinued operations before income taxes	26			(384		)	49			(335		)
Provision (benefit) for income taxes(b)	14			(135		)	(3		)	(138		)
Income (loss) from discontinued operations	$	12		$	(249	)	$	52		$	(197	)

__________

(a) The nine months ended September 30, 2016 includes $33 million net loss on derivatives.

(b) The nine months ended September 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the nine months ended September 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 September 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.

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Earnings (Loss) Per Common Share from Continuing Operations (Tables)

9 Months Ended

Sep. 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 ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	(218	)	$	(70	)	$	(441	)	$	5
Less: Dividends on preferred stock	4			4			15			4
Less: Loss on induced conversion of preferred stock	22			—			22			—
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	(244	)	$	(74	)	$	(478	)	$	1
Basic weighted-average shares	341.5			251.2			302.8			220.3
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	—			—			—			1.3
Stock options	—			—			—			0.1
Diluted weighted-average shares	341.5			251.2			302.8			221.7
Earnings (loss) per common share from continuing operations:
Basic	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01
Diluted	$	(0.72	)	$	(0.29	)	$	(1.58	)	$	0.01

__________

(a) The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders.

	Three months ended September 30,		Nine months ended September 30,
	2016	2015	2016	2015
	(Millions)
Weighted-average nonvested restricted stock units and awards	2.4	0.7	1.8	—
Weighted-average stock options	—	0.1	—	—
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 10)	23.8	26.7	23.8	9.0

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 September 30, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.

	September 30,
	2016		2015
Options excluded (millions)	2.4		2.6
Weighted-average exercise price of options excluded	$	16.46	$	16.16
Exercise price range of options excluded	$11.75 - $21.81		$11.46 - $21.81
Third quarter weighted-average market price	$	11.11	$	8.36

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Exploration Expense (Tables)

9 Months Ended

Sep. 30, 2016

Extractive Industries [Abstract]

Exploration Expenses

The following table presents a summary of exploration expenses.

	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(Millions)
Geologic and geophysical costs	$	1	$	3	$	2	$	5
Dry hole costs and impairments of exploratory area well costs	—		22		1		22
Unproved leasehold property impairment, amortization and expiration	9		31		28		42
Total exploration expenses	$	10	$	56	$	31	$	69

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Inventories (Tables)

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Inventories

The following table presents a summary of our inventories as of the dates indicated below.

	September 30, 2016		December 31, 2015
	(Millions)
Material, supplies and other	$	31	$	44
Crude oil production in transit	2		2
Total inventories	$	33	$	46

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Debt and Banking Arrangements (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Debt

The following table presents a summary of our debt as of the dates indicated below.

	September 30, 2016		December 31, 2015
	(Millions)
5.250% Senior Notes due 2017	$	125	$	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		1
Total debt	$	2,726	$	3,221
Less: Current portion of long-term debt, net(a)	125		1
Total long-term debt	$	2,601	$	3,220
Less: Debt issuance costs on long-term debt(b)	27		31
Total long-term debt, net(b)	$	2,574	$	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.

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Provision (Benefit) for Income Taxes (Tables)

9 Months Ended

Sep. 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 ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(Millions)
Current:
Federal	$	—		$	(4	)	$	—		$	(4	)
State	(5		)	(1		)	(5		)	(1		)
	(5		)	(5		)	(5		)	(5		)
Deferred:
Federal	(117		)	(26		)	(236		)	7
State	(10		)	4			14			1
	(127		)	(22		)	(222		)	8
Total provision (benefit)	$	(132	)	$	(27	)	$	(227	)	$	3

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 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.

	September 30, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	110	$	—	$	110	$	—	$	359	$	—	$	359
Energy derivative liabilities	$	—	$	97	$	—	$	97	$	—	$	15	$	—	$	15
Total debt(a)	$	—	$	2,752	$	—	$	2,752	$	—	$	2,495	$	—	$	2,495

__________

(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,725 million and $3,220 million as of September 30, 2016 and December 31, 2015, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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Derivatives and Concentration of Credit Risk (Tables)

9 Months Ended

Sep. 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 September 30, 2016.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Crude Oil
Crude Oil	Oct -Dec 2016	Fixed Price Swaps	WTI	(30,403	)	$	60.13
Crude Oil	Oct -Dec 2016	Basis Swaps	Midland-Cushing	(5,000	)	$	(0.45	)
Crude Oil	Oct -Dec 2016	Fixed Price Calls	WTI	(1,900	)	$	50.70
Crude Oil	2017	Fixed Price Swaps	WTI	(29,554	)	$	51.31
Crude Oil	2017	Swaptions	WTI	(3,264	)	$	51.22
Crude Oil	2017	Fixed Price Calls	WTI	(4,500	)	$	56.47
Crude Oil	2018	Fixed Price Swaps	WTI	(13,000	)	$	58.33
Crude Oil	2018	Fixed Price Calls	WTI	(13,000	)	$	58.89
Natural Gas
Natural Gas	Oct -Dec 2016	Fixed Price Swaps	Henry Hub	(146	)	$	3.93
Natural Gas	Oct -Dec 2016	Basis Swaps	Permian	(38	)	$	(0.17	)
Natural Gas	Oct -Dec 2016	Basis Swaps	San Juan	(100	)	$	(0.18	)
Natural Gas	2017	Fixed Price Swaps	Henry Hub	(150	)	$	2.98
Natural Gas	2017	Basis Swaps	Permian	(58	)	$	(0.20	)
Natural Gas	2017	Basis Swaps	San Juan	(93	)	$	(0.17	)
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 Swaps	Henry Hub	(40	)	$	2.91
Natural Gas	2018	Fixed Price Calls	Henry Hub	(16	)	$	4.75
Natural Gas	2018	Swaptions	Henry Hub	(20	)	$	3.33
Commodity	Period	Contract Type	Location(d)	Notional Volume (b)		Weighted Average Price
Physical Derivatives
Natural Gas	Oct -Dec 2016	Index	Multiple	(65	)	(e)
Natural Gas	2017	Index	Multiple	(16	)	(e)

__________

(a) Derivatives related to crude oil production are fixed price swaps, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas 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 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.

	September 30, 2016				December 31, 2015
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Total derivatives	$	110	$	97	$	359	$	15

Derivative Gain (Loss)

The following table presents the net gain (loss) related to our energy commodity derivatives.

	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
	(Millions)
Gain (loss) from derivatives related to production(a)	$	38	$	206		$	(59	)	$	260
Gain (loss) from derivatives related to physical marketing agreements(b)	—		(1		)	—			(21		)
Net gain (loss) on derivatives	$	38	$	205		$	(59	)	$	239

__________

(a) Includes settlements totaling $59 million and $159 million for the three months ended September 30, 2016 and 2015, respectively; and settlements totaling $260 million and $454 million for the nine months ended September 30, 2016 and 2015, respectively.

(b) Includes payments totaling $4 million and $32 million for the three months and nine months ended September 30, 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)			Net Amount
September 30, 2016	(Millions)
Derivative assets with right of offset or master netting agreements	$	110		$	(69	)	$	41
Derivative liabilities with right of offset or master netting agreements	$	(97	)	$	69		$	(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 September 30, 2016.

Counterparty Type	Gross Total		Net Total
	(Millions)
Financial institutions (Investment Grade)(a)	$	110	$	41
Credit exposure from derivatives	$	110	$	41

__________

(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.

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Basis of Presentation and Description of Business- Additional Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 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

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Acquisitions (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2016
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro Forma Revenue	$ 504	$ 1,193
Pro Forma Net Income (Loss)	$ 40	$ 90
Fair Value Adjustment [Domain]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Business Combination Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Assets			$ 60
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			$ 60

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Discontinued Operations Discontinued Operation (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended				12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2016		Sep. 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)		$ 38	$ 205		$ (59)		$ 239
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue		0	142		64	[1]	481
Disposal Group, Including Discontinued Operation, Lease Operating Expense		0	22		18		84
Disposal Group Including Discontinued Operation Gathering and Transportation Expense		1	68		49		205
Disposal Group, Including Discontinued Operation Taxes other than income		1	4		2		21
Disposal Group Gas Management					0		1
Disposal Group, Including Discontinued Operation, Depreciation and Amortization		0	106		9		309
Impairment of Oil and Gas Properties, Disposal Group					0		16
Disposal Group, Including Discontinued Operation, General and Administrative Expense		1	13		9		35
Disposal group contract obligation expense		0	187		0		187
Disposal Group, Including Discontinued Operation, Other Expense					4
Disposal Group, Including Discontinued Operation, Other Income		(2)	(14)				(9)
Disposal Group, Including Discontinued Operation, Operating Expense		1	386		91		849
Disposal Group, Including Discontinued Operation, Operating Income (Loss)		(1)	(244)		(27)		(368)
Disposal Group Including Discontinued Operation Investment Income		0	3		0		7
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax		238					(26)
Disposal Group Including Discontinued Operation Income before Tax		0	(256)		26		(335)
Discontinued Operation, Tax Effect of Discontinued Operation		1	(96)		14	[2]	(138)	[2]
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		(1)	(160)		12		(197)
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	[3]								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]
Contractual Obligation		128			128				686
Derivative Asset, Fair Value, Gross Asset		110			110				359
Other Commitment		400			400
Increase (Decrease) in Other Accrued Liabilities					42		0
Powder River Basin [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Impairment of Oil and Gas Properties, Disposal Group									16
Disposal group contract obligation expense							187
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax									15
Additional Disclosures [Abstract]
Sales price									80
Contractual Obligation									254
Escrow Deposits Related to Property Sales									13
Increase (Decrease) in Other Accrued Liabilities					42
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, Provision for Loss (Gain) on Disposal, before Income Tax					(53)
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
Disposal Group, Including Discontinued Operation, General and Administrative Expense							1
Disposal group contract obligation expense							0
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, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax				$ (41)
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	[2]						(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)					33
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue							466
Disposal Group, Including Discontinued Operation, Lease Operating Expense							80
Disposal Group Including Discontinued Operation Gathering and Transportation Expense							205
Disposal Group, Including Discontinued Operation Taxes other than income							18
Disposal Group Gas Management							1
Disposal Group, Including Discontinued Operation, Depreciation and Amortization							309
Impairment of Oil and Gas Properties, Disposal Group							16
Disposal Group, Including Discontinued Operation, General and Administrative Expense							34
Disposal group contract obligation expense							187
Disposal Group, Including Discontinued Operation, Other Income							(9)
Disposal Group, Including Discontinued Operation, Operating Expense							841
Disposal Group, Including Discontinued Operation, Operating Income (Loss)							(375)
Disposal Group Including Discontinued Operation Investment Income							6
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax		(1)	$ 15		(53)		15
Disposal Group Including Discontinued Operation Income before Tax							(384)
Discontinued Operation, Tax Effect of Discontinued Operation							(135)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest							(249)
Additional Disclosures [Abstract]
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities					32		219
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities					$ 28		$ 59
Piceance Basin [Member]
Disposal Group, Including Discontinued Operation, Income Statement 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
Capacity [Member] | Discontinued Operations [Member]
Additional Disclosures [Abstract]
Contractual Obligation									150
Gathering and Treating [Member] | Discontinued Operations [Member]
Additional Disclosures [Abstract]
Contractual Obligation									$ 104

[1] The nine months ended September 30, 2016 includes $33 million net loss on derivatives.

[2] The nine months ended September 30, 2016 includes a valuation allowance on certain state tax carryovers. International for the nine months ended September 30, 2015 includes the reversal of certain U.S. deferred tax liabilities associated with Apco.

[3] Includes $2,308 million impairment in Piceance Basin of the net assets.

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Earnings (Loss) Per Common Share from Continuing Operations (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 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		$ (218)	$ (70)	$ (441)	$ 5
Preferred Stock Dividends, Income Statement Impact		4	4	15	4
Preferred Stock Conversions, Inducements		22	0	22	0
Income (Loss) from Continuing Operations Attributable to Parent		$ (244)	$ (74)	$ (478)	$ 1
Weighted Average Number of Shares Outstanding, Basic		341.5	251.2	302.8	220.3
Weighted Average Number of Shares Outstanding, Diluted	[1]	341.5	251.2	302.8	221.7
Income (Loss) from Continuing Operations, Per Basic Share		$ (0.72)	$ (0.29)	$ (1.58)	$ 0.01
Income (Loss) from Continuing Operations, Per Diluted Share		$ (0.72)	$ (0.29)	$ (1.58)	$ 0.01
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		2.4	0.7	1.8	1.3
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		0.0	0.1	0.0	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		23.8	26.7	23.8	9.0

[1] The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders. Three monthsended September 30, Nine monthsended September 30, 2016 2015 2016 2015 (Millions)Weighted-average nonvested restricted stock units and awards2.4 0.7 1.8 —Weighted-average stock options— 0.1 — —Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 10)23.8 26.7 23.8 9.0

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Earnings (Loss) Per Common Share from Continuing Operations (Details 1) - $ / shares shares in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average exercise price of options excluded	$ 16.46	$ 16.16
Exercise price range of options excluded, lower limit	11.75	11.46
Exercise price range of options excluded, upper limit	21.81	21.81
Third quarter weighted-average market price	$ 11.11	$ 8.36
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	0.1	1.1
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	2.6

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Exploration Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Geologic and geophysical costs	$ 1	$ 3	$ 2	$ 5
Dry hole costs and impairments of exploratory area well costs	0	22	1	22
Unproved leasehold property impairment, amortization and expiration	9	31	28	42
Total exploration expenses	$ 10	$ 56	$ 31	$ 69

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Asset Sale, Other Expenses and Exploration Expense Additional Information (Details) - USD ($) $ in Millions	3 Months Ended					9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2016	Sep. 30, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property impairment, amortization and expiration	$ 9			$ 31		$ 28	$ 42
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	(227)			2		(25)	279
Proceeds from sale of assets						$ 1,140	610
Loss on Contract Termination					$ 22
Contract Term						2 years
Other Commitment	400					$ 400
Payments for (Proceeds from) Investments						238	(209)
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	(238)						26
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	11	$ 5	$ 199
Deferred Gain on Sale of Property	14					$ 14
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
Other Property [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property impairment, amortization and expiration							21
Unproved leasehold property impairment, amortization and expiration							$ 26
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

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Inventories (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Inventory [Line Items]
Inventory Write-down	$ 4
Materials, Supplies, and Other	31	$ 44
Inventory, Total	33	46
Crude Oil [Member]
Inventory [Line Items]
Other Inventory, in Transit, Gross	$ 2	$ 2

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Debt and Banking Arrangements (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt		$ 2,725	$ 3,220
Capital Lease Obligations		1	1
Total debt		2,726	3,221
Current portion of long-term debt, net	[1]	125	1
Total long-term debt		2,601	3,220
Less: Debt issuance costs on long-term debt(b)	[2]	27	31
Long-term debt, net	[2]	2,574	3,189
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Long-term Debt		125	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.

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Debt and Banking Arrangements - Debt - Additional information (Detail)	9 Months Ended	12 Months Ended
	Sep. 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	2017	2017
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	2020	2020
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%	6.00%
Debt Instrument Maturity Year	2022	2022
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	2023	2023
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.25%	5.25%
Debt Instrument Maturity Year	2024	2024

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Debt and Banking Arrangements Narrative (Details)	9 Months Ended
	Sep. 30, 2016 USD ($) Contract	Dec. 31, 2015
Debt Instrument [Line Items]
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	$ 66,000,000
Change in letters of credit outstanding	162,000,000
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility agreement	1,200,000,000.0
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	4.00
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	3.00
Minimum Current Ratio	1.0
Prior to December 31, 2016 [Member]
Debt Instrument [Line Items]
Limit On Consolidated Indebtedness to Consolidated EBITDAX	4.50
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount	$ 230,000,000
Debt Instrument, Repurchased Face Amount through Tender offer	$ 87,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.25%
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	3.00

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Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Current:
Federal	$ 0	$ (4)	$ 0	$ (4)
State	(5)	(1)	(5)	(1)
Total current	(5)	(5)	(5)	(5)
Deferred:
Federal	(117)	(26)	(236)	7
State	(10)	4	14	1
Total deferred	(127)	(22)	(222)	8
Total provision (benefit)	$ (132)	$ (27)	$ (227)	$ 3

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Provision (Benefit) for Income Taxes Additional Information (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2016	Sep. 30, 2016
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

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Contingent Liabilities - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Loss contingencies associated with royalty litigation	$ 17	$ 17
Contractual Obligation	128	$ 686
Other Commitment	400
San Juan [Member]
Loss Contingencies [Line Items]
Contractual Obligation	363
Capacity [Member] | Powder River Basin [Member]
Loss Contingencies [Line Items]
Other noncurrent liabilities	$ 99

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Stockholder's Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Jun. 06, 2016	Dec. 31, 2015
Common stock, par value	$ 0.01		$ 0.01			$ 0.01
Conversion of Stock, Shares Converted			2,201,180
Conversion of Stock, Shares Issued			10,227,872
Payments for Repurchase of Redeemable Convertible Preferred Stock			$ 10	$ 0
Preferred Stock, Shares Outstanding	4,800,000		4,800,000
Preferred Stock Conversions, Inducements	$ 22	$ 0	$ 22	0
Proceeds from common stock			$ 540	$ 295
Common Stock
Stock Issued During Period, Shares, New Issues			56,925,000
Stock Issued During Period, Shares, Other			7,425,000
Sale of stock, Price Per Share					$ 9.47
Additional Paid-In- Capital
Preferred Stock Conversions, Inducements			$ 22
Stock Issued During Period, Value, New Issues			$ 538

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Fair Value Measurements (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 110	$ 359
Derivative Liability, Fair Value, Gross Liability		97	15
Long-term Debt		2,725	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		110	359
Derivative Liability, Fair Value, Gross Liability		97	15
Long-term debt	[1]	2,752	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		110	359
Derivative Liability, Fair Value, Gross Liability		97	15
Long-term debt	[1]	2,752	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 $2,725 million and $3,220 million as of September 30, 2016 and December 31, 2015, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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

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Derivatives and Concentration of Credit Risk (Details) BTU / d in Thousands	9 Months Ended
	Sep. 30, 2016 bbl / d BTU / 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	(30,403)	[1]
Underlying, Derivative | $ / bbl	60.13	[2]
Price Risk Derivative [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(150)	[1]
Underlying, Derivative | $ / MMBtu	2.98	[2]
Price Risk Derivative [Member] | 2017 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(29,554)	[1]
Underlying, Derivative | $ / bbl	51.31	[2]
Price Risk Derivative [Member] | 2018 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(40)	[1]
Underlying, Derivative | $ / MMBtu	2.91	[2]
Price Risk Derivative [Member] | 2018 [Member] | Derivatives related to production | Crude Oil | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(13,000)	[1]
Underlying, Derivative | $ / bbl	58.33	[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] | Permian [Member]
Derivative [Line Items]
Notional Volume	(58)	[1]
Basis Swap [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | San Juan [Member]
Derivative [Line Items]
Notional Volume	(93)	[1]
Underlying, Derivative | $ / MMBtu	(0.17)	[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]
Swaption [Member] | 2018 [Member] | Derivatives related to production | Natural Gas [Member] | Henry Hub
Derivative [Line Items]
Notional Volume	(20)	[1]
Underlying, Derivative | $ / MMBtu	3.33	[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	(4,500)	[1]
Underlying, Derivative | $ / bbl	56.47	[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	(13,000)	[1]
Underlying, Derivative | $ / bbl	58.89	[2]
Short Position [Member] | 2017 [Member] | Derivatives related to production | Natural Gas [Member] | Permian [Member]
Derivative [Line Items]
Underlying, Derivative | $ / MMBtu	(0.20)	[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 is reported in $/Bbl and natural gas is reported in $/MMBtu

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Derivatives and Concentration of Credit Risk (Details 1) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 110	$ 359
Derivative Liability, Fair Value, Gross Liability	$ 97	$ 15

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Derivatives and Concentration of Credit Risk (Details 2) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge				$ 260	$ 422
Net gain (loss) on derivatives (Note 12)		$ 38	$ 205	(59)	239
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge		59	159	260	454
Net gain (loss) on derivatives (Note 12)	[1]	38	206	(59)	260
Derivatives Related to Physical Marketing Agreements [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on derivatives (Note 12)	[2]	$ 0	(1)	$ 0	(21)
Derivative, Cost of Hedge			$ 4		$ 32

[1] Includes settlements totaling $59 million and $159 million for the three months ended September 30, 2016 and 2015, respectively; and settlements totaling $260 million and $454 million for the nine months ended September 30, 2016 and 2015, respectively.

[2] Includes payments totaling $4 million and $32 million for the three months and nine months ended September 30, 2015, respectively.

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Derivatives and Concentration of Credit Risk (Details 3) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Gross And Net Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 110	$ 359
Derivative Asset, Fair Value, Gross Liability	[1]	(69)	(14)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		41	345
Derivative Liability, Fair Value, Gross Liability		(97)	(15)
Derivative Liability, Fair Value, Gross Asset	[1]	69	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.

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Derivatives and Concentration of Credit Risk (Details 4) $ in Millions	Sep. 30, 2016 USD ($)
Credit Exposure From Derivatives [Line Items]
Gross credit exposure from derivatives, Gross Total	$ 110
Net credit exposure from derivatives	41
Financial institutions (Investment Grade)(a)
Credit Exposure From Derivatives [Line Items]
Total gross credit exposure from derivative contracts before credit reserve	110	[1]
Total net credit exposure from derivative contracts before credit reserve	$ 41	[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.

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Derivatives and Concentration of Credit Risk - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Derivative [Line Items]
NumberOfLargestNetCounterPartyPositionsInvestmentGrade	5
Net derivative liability position	$ 28
Percentage of net credit exposure from derivatives	99.00%
Derivative Liability, Fair Value of Collateral	$ 30
Maximum [Member]
Derivative [Line Items]
Reduction in derivative liabilties	$ 2