10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

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

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  R    No  £

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  £    No  R

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  R    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  R    No  £

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R

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	R		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  R

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $4,832,711,197.

The number of shares outstanding of the registrant’s common stock outstanding at February 25, 2015 was 203,877,415.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement to be delivered to stockholders in connection with its 2015 Annual Meeting of Stockholders are incorporated by reference into Part III.

WPX ENERGY, INC.

FORM 10-K

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	3
	WPX Energy, Inc.	3
	Business Overview and Properties	4
	Regulatory Matters	16
	Environmental Matters	18
	Competition	24
	Employees	24
	Financial Information about Segments	24
	Financial Information about Geographic Areas	24
	Website Access to Reports and Other Information	25
Item 1A.	Risk Factors	26
Item 1B.	Unresolved Staff Comments	41
Item 2.	Properties	41
Item 3.	Legal Proceedings	41
Item 4.	Mine Safety Disclosures	41
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	42
Item 6.	Selected Financial Data	43
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8.	Financial Statements and Supplementary Data	66
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	117
Item 9A.	Controls and Procedures	117
Item 9B.	Other Information	117
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	118
Item 11.	Executive Compensation	118
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	118
Item 13.	Certain Relationships and Related Transactions, and Director Independence	118
Item 14.	Principal Accountant Fees and Services	118
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	119

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CERTAIN DEFINITIONS

The following oil and gas measurements and industry and other terms are used in this Form 10-K. As used herein, production volumes represent sales volumes, unless otherwise indicated.

Barrel—means one barrel of petroleum products that equals 42 U.S. gallons.

BBtu/d—means one billion BTUs per day.

Bcfe—means one billion cubic feet of gas equivalent determined using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

British Thermal Unit or BTU—means a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

FERC—means the Federal Energy Regulatory Commission.

Fractionation—means the process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane.

LOE—means lease and other operating expense excluding production taxes, ad valorem taxes and gathering, processing and transportation fees.

Mbbls—means one thousand barrels.

Mbbls/d—means one thousand barrels per day.

Mboe—means one thousand barrels of oil equivalent.

Mboe/d—means one thousand barrels of oil equivalent per day.

Mcf—means one thousand cubic feet.

Mcfe—means one thousand cubic feet of gas equivalent using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

MMbbls—means one million barrels.

MMBtu—means one million BTUs.

MMBtu/d—means one million BTUs per day.

MMcf—means one million cubic feet.

MMcf/d—means one million cubic feet per day.

MMcfe—means one million cubic feet of gas equivalent using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

MMcfe/d—means one million cubic feet of gas equivalent per day using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

NGLs—means natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications.

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PART I

In this report, WPX (which includes WPX Energy, Inc. and, unless the context otherwise requires, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to WPX as the “Company” or “WPX Energy.”

Throughout this report we “incorporate by reference” certain information in parts of other documents filed with the Securities and Exchange Commission (the “SEC”). The SEC allows us to disclose important information by referring to it in that manner. Please refer to such documents for information.

We are making forward-looking statements in this report. In “Item 1A: Risk Factors” we discuss some of the risk factors that could cause actual results to differ materially from those stated in the forward-looking statements.

Item 1. Business

WPX ENERGY, INC.

Incorporated in 2011, we are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserves base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our oil positions in the Williston Basin in North Dakota and the San Juan Basin in the southwestern United States.

We have built a geographically diverse portfolio of natural gas and oil reserves through organic development and strategic acquisitions. Our domestic proved reserves at December 31, 2014 were 4,360 Bcfe. Our domestic reserves reflect a mix of 72 percent natural gas, 18 percent crude oil and 10 percent NGLs. During 2014, we replaced our domestic production for all commodities at a rate of 94 percent. For oil alone, we replaced 421 percent of our oil production. Our Piceance Basin operations form the majority of our proved reserves and current production, providing a low-cost, scalable asset base.

Our principal areas of operation are the Piceance Basin in Colorado, the Williston Basin in North Dakota, and the San Juan Basin in New Mexico and Colorado. Our principal executive office is located at 3500 One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 855-979-2012.

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BUSINESS OVERVIEW AND PROPERTIES

Our Business Strategy

Our business strategy is to increase shareholder value by increasing production over time of oil, natural gas, and NGLs, expanding our margins, and finding and developing reserves.

• Focused, Long-Term Portfolio Management. We are focused on long-term profitable growth. Our objective over time is to grow our production within our cash flow. With that in mind, we continuously evaluate the performance of our assets and, when appropriate, we consider divestitures of assets that are underperforming or which are no longer a part of our strategic focus. With regard to our core assets in the Piceance, Williston, and San Juan Basins, we expect to allocate capital to the most profitable opportunities based on commodity price cycles and other market conditions, enabling us to grow our reserves and production in a manner that maximizes our returns on investments.

• Build Asset Scale. We expect to opportunistically acquire acreage positions in areas where we feel we can establish significant scale and replicate cost-efficient development practices. We may also consider other “bolt-on” transactions that are directed at driving operational efficiencies through increased scale. We can manage costs by focusing on the establishment of large scale, contiguous acreage blocks where we can operate a majority of the properties. We believe this strategy allows us to better achieve economies of scale and apply continuous technological improvements in our operations. We have a history of acquiring undeveloped properties that meet our expected return requirements and other acquisition criteria to expand upon our existing positions as well as acquiring undeveloped acreage in new geographic areas that offer significant resource potential.

• Margin Expansion thru Focus on Costs. We believe we can expand our margins by focusing on opportunities to reduce our cost structure. As we rationalize our portfolio and reduce our areas of focus to core basins, we have the opportunity to improve our cost structure and ensure that our organization is in alignment with our margin growth objectives. 

• Continue Oil Development and Increase Optionality. We believe that efforts to develop our oil properties will yield a more balanced commodity mix in our production, providing us with the option of focusing on the commodity with the best returns under different market conditions. This optionality, we believe, will place us in a position where we can better protect and grow our cash flows. We have engaged and will continue to engage in commodity derivative hedging activities to maintain a degree of cash flow stability. Typically, we target hedging approximately 50 percent of expected revenue from domestic production during a current calendar year in order to strike an appropriate balance of commodity price upside with cash flow protection, although we may vary from this level based on our perceptions of market risk. We have hedged approximately three-fourths of our anticipated 2015 natural gas production at a weighted average price of $4.10 per MMbtu, and approximately two-thirds of anticipated 2015 oil production at a weighted average price of $94.88 per barrel.

Significant Properties

Our principal areas of operation are the Piceance Basin, Williston Basin and San Juan Basin.

Piceance Basin

We entered the Piceance Basin in May 2001 with the acquisition of Barrett Resources and since that time have grown to become the largest natural gas producer in Colorado. Our Piceance Basin properties currently comprise our largest area of concentrated development drilling. We operate 4,742 wells in the Piceance Basin and also own interest in 318 wells operated by others. We hold 196,149 net acres in the Piceance Basin.

During 2014, we operated an average of 8.5 drilling rigs in the basin, including 6.2 in the Piceance Valley, 1.6 in the Piceance Highlands and 0.7 in the Piceance Niobrara. In response to lower commodity prices, we expect to operate 3.5 rigs in the Piceance Basin in 2015. In 2014, we had an average of 564 MMcf per day of net gas production from our Piceance Basin properties along with an average of 14.7 Mbbls per day of NGLs and 1.9 Mbbls per day of condensate recovered from our Piceance Basin properties. Capital expenditures were approximately $523 million which included the completion of 269 gross (252 net) wells in 2014. As of December 31, 2014, another 46 gross operated wells were awaiting completions. A large majority of our natural gas production in this basin currently is gathered through a system owned by Williams Partners L.P. and delivered to markets through a number of interstate pipelines.

The Piceance Basin is located in northwestern Colorado. Our operations in the basin are divided into two areas: the Piceance Valley and the Piceance Highlands. Our Piceance Valley area includes operations along the Colorado River valley and is the more developed area where we have produced consistent, repeatable results. The Piceance Highlands, which are those areas at higher elevations above the river valley, contain vast development opportunities that position us well for growth in the

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future as infrastructure expands and efficiency improvements continue. Our development activities in the basin are primarily focused on the Williams Fork section within the Mesaverde formation. The Williams Fork can be over 2,000 feet in thickness and is comprised of multiple tight, interbedded, lenticular sandstone lenses encountered at depths ranging from 6,000 to 9,000 feet. In order to maximize producing rates and recovery of natural gas reserves we must hydraulically fracture the well using a fluid system comprised of 99 percent water and sand. Advancements in completion technology, including the use of microseismic data, have enabled us to more effectively stimulate the reservoir and recover a greater percentage of the natural gas in place.

In early 2013, we announced a successful discovery in the Niobrara Shale formation which has the potential to significantly increase our natural gas reserves and daily production in future years. The discovery well produced an initial high of 16 MMcf per day at a flowing pressure of 7,300 pounds per square inch. Additional drilling thus far has validated the existence of a highly pressured continuous gas accumulation capable of producing pipeline quality gas. Future drilling will focus on driving down costs while optimizing completion techniques. The Niobrara and Mancos Shales are generally located at depths of 10,000 to 13,000 feet. We have the lease rights to approximately 160,000 net acres of the Niobrara/Mancos Shale play that underlies our expansive leasehold position in the Piceance Basin. Substantial gathering and processing infrastructure is in place to accommodate additional gas volumes from the area, as is take-away capacity from the basin. Gas produced from the Niobrara and Mancos Shales can be processed without modification to existing gas treatment facilities.

Williston Basin

In December 2010, we acquired leasehold positions of approximately 85,800 net acres in the Williston Basin. All of these properties are on the Fort Berthold Indian Reservation in North Dakota and we are the primary operator. Based on our geologic interpretation of the Bakken formation, the evolution of completion techniques, our own drilling results as well as the publicly available drilling results for other operators in the basin, we believe that a substantial portion of our Williston Basin acreage is prospective in the Bakken and Three Forks formations, the primary targets for all of the well locations in our current drilling inventory. We operate 177 wells in the Williston Basin and also own interest in 19 wells operated by others. We hold 85,483 net acres in the Williston Basin.

During 2014, we operated an average of 4.8 rigs on our Williston Basin properties and we had an average of 22.3 Mboe per day of net production from our Williston Basin wells. In response to lower oil prices we expect to operate 1.4 rigs in the Williston Basin in 2015. Capital expenditures were approximately $632 million which included the completion of 55 gross (45 net) wells in 2014. As of December 31, 2014, another 25 gross operated wells were awaiting completion.

We are developing oil reserves through horizontal drilling in the Middle Bakken and the Upper Three Forks Shale oil formations. Based on our subsurface geological analysis, we believe that our position lies in an area of the basin with substantial potential recovery for Bakken and Three Forks formation oil.

Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada, covering approximately 202,000 square miles, of which 143,000 square miles are in the United States. The basin produces oil and natural gas from numerous producing horizons including the Bakken, Three Forks, Madison and Red River formations.

The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of three lithologic members referred to as the Upper, Middle and Lower Bakken Shales. The formation ranges up to 150 feet thick and is a continuous and structurally simple reservoir. The upper and lower shales are highly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The Middle Bakken, which varies in composition from a silty dolomite to shaly limestone or sand, serves as the productive formation and is a critical reservoir for commercial production. Generally, the Bakken formation is found at vertical depths of 8,500 to 11,500 feet.

The Three Forks formation, generally found immediately under the Bakken formation, has also proven to contain productive reservoir rock. The Three Forks formation typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish Sand. The Three Forks formation is an unconventional carbonate play. Similar to the Bakken formation, the Three Forks formation is being exploited utilizing the same horizontal drilling and advanced completion techniques as the Bakken development. Drilling in the Three Forks formation began in mid-2008 and many operators are drilling wells targeting this formation.

Our acreage in the Williston Basin, as well as a portion of our acreage in the Piceance Basin, is leased to us by or with the approval of the federal government or its agencies, and is subject to federal authority, the National Environmental Policy Act (“NEPA”), the Bureau of Indian Affairs or other regulatory regimes that require governmental agencies to evaluate the potential environmental impacts of a proposed project on government owned lands. These regulatory regimes impose obligations on the

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federal government and governmental agencies that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals and could result, in certain instances, in the cancellation of existing leases.

San Juan Basin

We first acquired properties in the San Juan Basin as part of The Williams Companies, Inc. (“Williams”) acquisition of Northwest Energy in 1983. Our San Juan Basin properties include holdings across the basin producing primarily from the Mesaverde, Fruitland Coal and Mancos Shale formations which are predominantly gas bearing. We operate four units in New Mexico (Rosa, Cox Canyon, Northwest Lybrook and South Chaco) and also operate the Northeast Chaco CA (Communitized Area), as well as a number of non-unit properties.  We operate in three major areas of Colorado (Northwest Cedar Hills, Ignacio and Bondad). We operate 945 wells in the San Juan Basin and also own interest in 2,319 wells operated by other operators in New Mexico and Colorado. We hold approximately 134,000 net acres in the gas window of the basin.

In 2013, we announced a successful oil discovery in the Mancos Gallup Sandstone in the San Juan Basin that has the potential to significantly increase our oil production and reserves in future years. In 2014, we announced that we executed multiple transactions to own or control over 53,000 additional acres in the heart of the San Juan Basin’s Gallup oil window. At December 31, 2014, our leasehold position in the oil window of the San Juan Basin was approximately 85,000 net acres of which we own or control, and we are targeting additional acreage.

During 2014, we operated an average of 2.3 rigs in the San Juan Basin on our oil properties and we expect to operate 2.3 rigs in the San Juan Basin in 2015. We had an average of 139 MMcfe per day of net production from our San Juan Basin properties which included 3.9 Mbbls per day of oil. Capital expenditures were approximately $568 million which included the completion of 47 gross (44 net) wells from our oil properties. As of December 31, 2014, another 10 gross operated wells were awaiting completion.

The San Juan Basin is one of the oldest and most prolific coal bed methane plays in the world. The Fruitland coal bed extends to depths of approximately 4,200 feet with net thickness ranging from zero to 100 feet. The Mesaverde play is the top producing tight gas play in the basin with total thickness ranging from 500 to 2,500 feet. The Mesaverde is underlain by the upper Mancos Shale and overlain by the Lewis Shale. The Mancos Shale, locally referred to as the Gallup Sandstone, is found at a depth of approximately 5,400 feet and is fine-grained sandstone interval of approximately 150 feet thick. The Mancos Shale includes both oil and natural gas.

Some of our acreage in the San Juan Basin is leased to us by or with the approval of the federal government or its agencies, including the United States Forest Service, Bureau of Land Management (“BLM”), the Bureau of Indian Affairs, and the Federal Indian Minerals Office. These particular leases are subject to federal authority, including the National Environmental Policy Act, and require governmental agencies to evaluate the potential environmental impacts of a proposed project on government owned lands. These regulatory regimes impose obligations on the federal government and governmental agencies that may result in legal challenges and potentially lengthy delays in obtaining both permits to drill and rights of way.

Other Properties

Our other holdings, amounting to approximately 3 percent of our assets, are primarily comprised of gas reserves in the Appalachian Basin in Pennsylvania. Approximately 95 percent of our Appalachian Basin assets were sold in January 2015.

Acquisitions and Divestitures

On June 4, 2014, we announced that we had completed the sale of working interests in some of our historical Piceance Basin wells to Legacy Reserves LP for a sales price of $355 million subject to customary post-closing adjustments. Our undeveloped locations in the Piceance Basin were not included in the transaction, which was limited to a graduated working interest in certain of our proved developed producing wells drilled prior to 2009. The working interests represented approximately 300 Bcfe of proved reserves, or approximately 6 percent of our year-end 2013 proved reserves.

On August 18, 2014, we announced that we have agreed to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million in cash. We continue to negotiate the divestiture. The original sales agreement was scheduled to terminate February 13, 2015, but both parties agreed to extend the time table. If the agreement does not successfully close in March, WPX has the option to terminate the transaction. Additionally, we have recorded an impairment of $45 million in December 2014 to reduce the net assets to the probability weighted average of estimated sales prices that may be achieved. Reserves in the basin are estimated to be 200 Bcfe and fourth-quarter production was 143 MMcf per day, which includes operated and non-operated working interests in approximately 5,000 wells. Since 2011, our drilling activities in the basin have been minimal therefore resulting in declining production and production in the basin has amounted to less than 13 percent of our total domestic annual production in 2014. In our financial statements, we have reclassified our Powder River

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operations as discontinued operations in accordance with the provisions of “Presentation of Financial Statements” in the Accounting Standards Codification.

On August 26, 2014, we announced that we closed an agreement to jointly develop nearly 400 future wells in our Trail Ridge properties in the Piceance Basin with TRDC LLC, a subsidiary of Houston-based G2X Energy. As part of the joint agreement, we received $40 million in cash for 49 percent of our working interest in approximately 100 proved developed producing Trail Ridge wells in the Piceance Basin. During the carry period we will pay 28 percent of the Trail Ridge development and receive 51 percent of the production and reserves until TRDC has completed its $170 million funding commitment. The joint development agreement is for the Williams Forks and Iles formations and does not include deeper opportunities in the Mancos and Niobrara shales.

On January 29, 2015, we announced that we had completed the disposition of our international interests upon the successful merger of Apco Oil and Gas International Inc. (“Apco”) with a subsidiary of privately held Pluspetrol Resources Corporation. We received approximately $294 million for the disposition of our 69 percent controlling equity interest in Apco. In connection with the transaction, we also sold additional Argentina-related assets to Pluspetrol. Together, these non-operated international holdings comprised less than 5 percent of our 2014 year-end proved reserves. In our financial statements, we have reclassified our international operations to discontinued operations in accordance with the provision of “Presentation of Financial Statements” in the Accounting Standards Codification.

On February 2, 2015, we announced that we had completed the sale of our operations in northeast Pennsylvania, including the release of certain firm transportation capacity, to Southwestern Energy Company, for approximately $300 million. The transaction included physical operations covering approximately 46,700 acres, roughly 50 million cubic feet per day of net natural gas production, and 63 operated horizontal wells, primarily in Susquehanna County, Pennsylvania. The transfer in the firm transportation capacity in connection with the sale resulted in our release from approximately $24 million per year in annual demand obligations associated with the transport.

In 2014, we executed multiple transactions to control approximately 53,000 additional acres in the heart of the San Juan Basin’s Gallup oil window. These transactions included 28 Bcfe of proved reserves. We may from time to time dispose of producing properties and undeveloped acreage positions if we believe they no longer fit into our strategic plan.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. In addition, leases on Native American reservations are subject to Bureau of Indian Affairs and other approvals unique to those locations. As is customary in the industry in the case of undeveloped properties, a limited investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time which can result in litigation and delay or loss of our ability to realize the benefits of our leases.

Reserves and Production Information

We have significant oil and gas producing activities primarily in the Piceance, Williston and San Juan Basins located in the United States. Prior to the divestiture in January 2015, we had international oil and gas producing activities, primarily in Argentina. Proved reserves related to international activities were less than 5 percent of our total international and domestic proved reserves as of December 31, 2014. Accordingly, unless specifically stated otherwise, the information in the remainder of this Item 1 relates only to the oil and gas activities in the United States.

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Oil and Gas Reserves

The following table sets forth our estimated domestic net proved developed and undeveloped reserves expressed by product and on a natural gas equivalent basis for the reporting periods December 31, 2014, 2013 and 2012.

	As of December 31, 2014
	Gas (MMcf)	Oil (Mbbls)	NGL (Mbbls)	Equivalent (MMcfe)	%
Proved Developed	2,089,974	60,012	43,955	2,713,770	62%
Proved Undeveloped	1,059,617	70,817	26,885	1,645,831	38%
Total Proved-Domestic	3,149,591	130,829	70,840	4,359,601

	As of December 31, 2013
	Gas (MMcf)	Oil (Mbbls)	NGL (Mbbls)	Equivalent (MMcfe)	%
Proved Developed	2,265,204	36,828	48,587	2,777,695	58%
Proved Undeveloped	1,364,552	66,102	37,128	1,983,930	42%
Total Proved-Domestic	3,629,756	102,930	85,715	4,761,625

	As of December 31, 2012
	Gas (MMcf)	Oil (Mbbls)	NGL (Mbbls)	Equivalent (MMcfe)	%
Proved Developed	2,170,681	23,740	64,910	2,702,579	60%
Proved Undeveloped	1,198,392	52,807	45,449	1,787,928	40%
Total Proved-Domestic	3,369,073	76,547	110,359	4,490,507

The following table sets forth our estimated domestic net proved reserves for our largest areas of activity expressed by product and on a gas equivalent basis as of December 31, 2014.

	As of December 31, 2014
	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Equivalent (MMcfe)
Piceance Basin	2,162,071	7,649	54,430	2,534,548
Williston Basin	50,297	101,324	9,542	715,495
San Juan Basin	426,263	21,778	6,647	596,812
Appalachian Basin(a)	297,801	—	—	297,801
Powder River Basin(a)	200,089	—	—	200,089
Other	13,070	78	221	14,856
Total Proved-Domestic	3,149,591	130,829	70,840	4,359,601

__________

(a) Includes assets held for sale as of December 31, 2014 (see Note 2 and Note 4 of Notes to Consolidated Financial Statements).

We prepare our own reserves estimates and approximately 88 percent of our reserves are audited by Netherland, Sewell & Associates, Inc. (“NSAI”).

We have not filed on a recurring basis estimates of our total proved net oil, NGL, and gas reserves with any U.S. regulatory authority or agency other than with the U.S. Department of Energy and the SEC. The estimates furnished to the Department of Energy have been consistent with those furnished to the SEC.

Our 2014 year-end estimated proved reserves reflect an average natural gas price of $4.01 per Mcf, an average oil price of $83.62 per barrel and average NGL price of $40.40 per barrel. These prices were calculated from the 12-month average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. During 2014, we added 691 Bcfe of extensions and discoveries to our proved reserves. During 2014, we participated in the drilling of 479 gross wells at a net capital cost of approximately $1,454 million, which includes costs associated with exploratory wells.

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Proved reserves reconciliation

The 691 Bcfe of extensions and discoveries reflects 189 Bcfe added for drilled locations and 502 Bcfe added for new proved undeveloped locations. The extensions and discoveries were primarily in the Piceance, Williston and San Juan Basins. The acquisitions of 37 Bcfe were primarily in the San Juan Basin. The divestitures of 377 Bcfe were primarily in the Piceance Basin. The overall net negative revisions of 325 Bcfe reflects 97 Bcfe of net positive revisions made to developed reserves and 422 Bcfe of net negative revisions made to undeveloped reserves.

Reserves estimation process

Our reserves are estimated by deterministic methods using an appropriate combination of production performance analysis and volumetric techniques. The proved reserves for economic undrilled locations are estimated by analogy or volumetrically from offset developed locations. Reservoir continuity and lateral pervasiveness of our tight-sands, shale and coal bed methane reservoirs is established by combinations of subsurface analysis and analysis of 2D and 3D seismic data and pressure data. Understanding reservoir quality may be augmented by core samples analysis.

The engineering staff of each basin asset team provides the reserves modeling and forecasts for their respective areas. Various departments also participate in the preparation of the year-end reserves estimate by providing supporting information such as pricing, capital costs, expenses, ownership, gas gathering and gas quality. The departments and their roles in the year-end reserves process are coordinated by our reserves analysis department. The reserves analysis department’s responsibilities also include performing an internal review of reserves data for reasonableness and accuracy, working with NSAI and the asset teams to successfully complete the reserves audit, finalizing the year-end reserves report and reporting reserves data to accounting.

The preparation of our year-end reserves report is a formal process. Early in the year, we begin with a review of the existing internal processes and controls to identify where improvements can be made from the prior year’s reporting cycle. Later in the year, the reserves staffs from the asset teams submit their preliminary reserves data to the reserves analysis department. After review by the reserves analysis department, the data is submitted to NSAI to begin their audits. Reserves data analysis and further review are then conducted and iterated between the asset teams, reserves analysis department and NSAI. In

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early December, reserves are reviewed with senior management. The process concludes upon receipt of the audit letter from NSAI.

The reserves estimates resulting from our process are subjected to both internal and external controls to promote transparency and accuracy of the year-end reserves estimates. Our internal reserves analysis team is independent and does not work within an asset team or report directly to anyone on an asset team. The reserves analysis department provides detailed independent review and extensive documentation of the year-end process. Our internal processes and controls, as they relate to the year-end reserves, are reviewed and updated as appropriate. The compensation of our reserves analysis team is not directly linked to reserves additions or revisions except to the extent that reserves additions are a component of our all-employee incentive plan.

Approximately 88 percent of our total year-end 2014 domestic proved reserves estimates were audited by NSAI. When compared on a well-by-well basis, some of our estimates are greater and some are less than the NSAI estimates. NSAI is satisfied with our methods and procedures used to prepare the December 31, 2014 reserves estimates and future revenue, and noted nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, prepared by us. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserves audit is our Director of Reserves and Production Services. The Director’s qualifications include 32 years of reserves evaluation experience, a B.S. in geology from the University of Texas at Austin, an M.S. in Physical Sciences from the University of Houston and membership in the American Association of Petroleum Geologists and The Society of Petroleum Engineers.

Proved undeveloped reserves

The majority of our reserves is concentrated in unconventional tight-sands, shale and coal bed gas reservoirs. We use available geoscience and engineering data to establish drainage areas and reservoir continuity beyond one direct offset from a producing well, which provides additional proved undeveloped reserves. Inherent in the methodology is a requirement for significant well density of economically producing wells to establish reasonable certainty. In fields where producing wells are less concentrated, generally only direct offsets from proved producing wells were assigned the proved undeveloped reserves classification. No new technologies were used to assign proved undeveloped reserves.

At December 31, 2014, our proved undeveloped reserves were 1,646 Bcfe, a decrease of 338 Bcfe from our December 31, 2013 proved undeveloped reserves estimate of 1,984 Bcfe and represents 38 percent of our total proved reserves. During 2014, 394 Bcfe of our December 31, 2013 proved undeveloped reserves were converted to proved developed reserves at a cost of $592 million. This represents a proved undeveloped conversion rate of 19.9 percent. Of the converted reserves, 69 percent were in the Piceance Basin primarily in the Williams Fork formations, 25 percent were in the Bakken and Three Forks formations in the Williston Basin, and the other 6 percent were in all other production areas combined.

In 2014, net revisions for our proved undeveloped reserves were 422 Bcfe. Net negative revisions of 363 Bcfe were due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules. Of the 363 Bcfe, 62 percent relates to the Piceance Basin, 17 percent relates to our San Juan Basin legacy assets, 11 percent in our Williston Basin assets and 10 percent for all other production areas. Net downward revision of 122 Bcfe is primarily due to re-spacing and field studies in the Piceance, Appalachian and Williston Basins. Revisions due to economics resulted in net upward revisions of 23 Bcfe. Revisions to proved undeveloped reserves that were on the books at December 31, 2013 and December 31, 2014 show an upward increase of 40 Bcfe.

All proved undeveloped locations are scheduled to be drilled within the next five years based on current expectations. Development drilling schedules are subject to revision and reprioritization throughout the year resulting from unknown factors such as the relative success of individual developmental drilling prospects, rig availability, title issues or delays and the effect that acquisitions or dispositions may have on prioritizing developmental drilling plans for maximizing returns of capital spent.

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Oil and Gas Production, Production Prices and Production Costs

Production Sales Data

The following table summarizes our net production sales volumes, including those in the Appalachian Basin, for the years indicated, but excludes our Powder River Basin and international operations which are classified as discontinued operations.

	Year Ended December 31,
	2014	2013	2012
Natural Gas (MMcf)
U.S.
Piceance Basin	205,853	219,317	246,179
Other	74,533	76,617	74,983
Total	280,386	295,934	321,162
Oil (Mbbls)
U.S.
Williston Basin	7,123	4,828	3,487
Other	2,121	1,091	907
Total	9,244	5,919	4,394
NGLs (Mbbls)
U.S.
Piceance Basin	5,352	6,963	10,075
Other	898	452	317
Total	6,250	7,415	10,392
Combined Equivalent Volumes (MMcfe)	373,352	375,940	409,877
Combined Equivalent Volumes (Mboe)	62,225	62,657	68,313
Average Daily Combined Equivalent Volumes (MMcfe/d)
U.S.
Piceance Basin	663	727	852
Other	360	303	268
Total	1,023	1,030	1,120

Net production sales data for our Powder River Basin and international operations are presented in the table below.

	Year Ended December 31,
	2014	2013	2012
Natural Gas (MMcf)
Powder River Basin	55,042	63,529	76,321
International	7,423	6,534	7,061
Total	62,465	70,063	83,382
Oil (Mbbls)
Powder River Basin	1	8	—
International	2,142	2,032	2,178
Total	2,143	2,040	2,178
NGLs (Mbbls)
Powder River Basin	—	6	—
International	160	167	181
Total	160	173	181
Combined Equivalent Volumes (MMcfe)	76,286	83,347	97,539
Combined Equivalent Volumes (Mboe)	12,714	13,891	16,257

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Domestic realized average price per unit

The following table summarizes our domestic sales prices, including the Appalachian Basin, for the years indicated, but excludes our Powder River Basin operations which are classified as discontinued operations.

	Year Ended December 31,
	2014			2013			2012
Natural gas(a):
Natural gas excluding all derivative settlements (per Mcf)	$	3.57		$	3.01		$	2.40
Impact of hedges (per Mcf)	—			0.02			1.32
Natural gas including hedges (per Mcf)	3.57			3.03			3.72
Impact of net cash received (paid) related to settlement of derivatives not designated as hedges (per Mcf)	(0.10		)	(0.07		)	0.04
Natural gas net price including all derivative settlements (per Mcf)	$	3.47		$	2.96		$	3.76
Oil(a):
Oil excluding all derivative settlements (per barrel)	$	78.32		$	90.21		$	83.34
Impact of hedges (per barrel)	—			—			2.23
Oil including hedges (per barrel)	78.32			90.21			85.57
Impact of net cash received (paid) related to settlement of derivatives not designated as hedges (per barrel)	2.01			1.52			0.35
Oil net price including all derivative settlements (per barrel)	$	80.33		$	91.73		$	85.92
NGL(a):
NGL excluding all derivative settlements (per barrel)	$	32.79		$	30.72		$	28.56
Impact of net cash received (paid) related to settlement of derivatives not designated as hedges (per barrel)	1.12			0.08			1.56
NGL net price including all derivative settlements (per barrel)	$	33.91		$	30.80		$	30.12
Combined commodity price per Mcfe, including all derivative settlements	$	5.17		$	4.41		$	4.55

__________

(a) Realized average prices reflect market prices, net of fuel, shrink, transportation and fractionation, and processing.

Domestic expenses per Mcfe

The following table summarizes our domestic costs, including costs in the Appalachian Basin, for the years indicated and excludes our Powder River Basin operations which are classified as discontinued operations.

	Year Ended December 31,
	2014		2013		2012
Production costs:
Lifting costs and workovers	$	0.53	$	0.47	$	0.40
Facilities operating expense	0.06		0.07		0.04
Other operating and maintenance	0.06		0.06		0.05
Total LOE	$	0.65	$	0.60	$	0.49
Gathering, processing and transportation charges	0.88		0.93		1.06
Taxes other than income	0.34		0.27		0.17
Total production cost	$	1.87	$	1.80	$	1.72
General and administrative	$	0.73	$	0.71	$	0.65
Depreciation, depletion and amortization	$	2.17	$	2.28	$	2.16

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Productive Oil and Gas Wells

The table below summarizes 2014 productive gross and net wells by area. We use the term “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest.

	Gas Wells (Gross)	Gas Wells (Net)	Oil Wells (Gross)	Oil Wells (Net)
Piceance Basin	5,060	3,502	—	—
Williston Basin	—	—	196	138
San Juan Basin	3,174	875	90	82
Appalachian Basin(a)	168	87	—	—
Powder River Basin(a)	5,124	2,189	—	—
Other (b)	1,138	22	7	—
Total	14,664	6,675	293	220

__________

(a) Includes assets held for sale as of December 31, 2014 (see Note 2 and Note 4 of Notes to Consolidated Financial Statements).

(b) Includes Green River Basin and other miscellaneous properties.

At December 31, 2014, there were 228 gross and 103 net producing wells with multiple completions.

Developed and Undeveloped Acreage

The following table summarizes our leased acreage as of December 31, 2014.

	Developed		Undeveloped		Total
	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres
Piceance Basin	157,973	121,959	103,014	74,190	260,988	196,149
Williston Basin	64,419	56,760	68,199	28,723	132,618	85,483
San Juan Basin	239,404	130,485	94,587	80,656	333,991	211,141
Appalachian Basin(a)	37,970	27,995	65,069	51,547	103,038	79,541
Powder River Basin(a)	595,822	268,567	166,216	72,431	762,038	340,998
Other (b)	31,105	6,215	377,719	275,189	408,824	281,404
Total	1,126,693	611,981	874,804	582,736	2,001,497	1,194,716

__________

(a) Includes assets held for sale as of December 31, 2014 (see Note 2 and Note 4 of Notes to Consolidated Financial Statements).

(b) Includes exploratory acreage in Montana, Wyoming, Kansas and other miscellaneous smaller properties.

Drilling and Exploratory Activities

We focus on lower-risk development drilling. Our development drilling success rate was 100 percent in 2014, 2013 and 2012. Our combined development and exploration success rate was 99 percent in 2014, and 100 percent in 2013 and 2012.

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The following table summarizes the number of domestic wells drilled for the periods indicated.

	2014		2013		2012
	Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells
Development wells:
Piceance Basin	267	250	249	236	239	208
Williston Basin	55	45	51	36	41	27
San Juan Basin	47	44	9	9	11	6
Appalachian Basin(a)	25	7	37	24	54	33
Powder River Basin(a)	61	22	37	16	150	92
Other(b)	17	—	24	—	52	—
Productive	472	368	407	321	547	366
Nonproductive	—	—	—	—	—	—
Development well total	472	368	407	321	547	366
Exploration wells:
Productive	2	2	9	9	1	1
Nonproductive(c)	5	5	—	—	—	—
Exploration well total	7	7	9	9	1	1
Total Drilled	479	375	416	330	548	367

__________

(a) Includes assets held for sale as of December 31, 2014 (see Note 2 and Note 4 of Notes to Consolidated Financial Statements).

(b) Includes Green River Basin and other miscellaneous properties.

(c) Reflects exploration wells which were drilled and not completed.

Total gross operated wells drilled were 369, 361 and 423 in 2014, 2013 and 2012, respectively.

Present Activities

At December 31, 2014, we had 12 gross (11 net) wells in the process of being drilled. As previously noted in Significant Properties, we also have a large number of wells that are awaiting completion.

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Scheduled Lease Expirations

The table below sets forth, as of December 31, 2014, the gross and net acres scheduled to expire over the next several years. The acreage will not expire if we are able to establish production by drilling wells on the lease prior to the expiration date.

	2015	2016	2017	2018+	Total
Piceance Basin	777	5,782	14	11,746	18,319
Williston Basin	146	160	280	1,587	2,173
San Juan Basin	160	1,122	5,603	35,809	42,694
Appalachian Basin(a)	23,020	16,944	4,925	9,297	54,186
Powder River Basin(a)	660	39	1,640	27	2,366
Other(b)	54,135	62,131	132,469	93,085	341,820
Total (Gross Acres)	78,898	86,178	144,931	151,551	461,558

	2015	2016	2017	2018+	Total
Piceance Basin	396	4,966	14	10,865	16,241
Williston Basin	86	160	200	1,583	2,029
San Juan Basin	144	1,122	5,603	35,359	42,228
Appalachian Basin(a)	20,153	13,984	4,209	5,086	43,432
Powder River Basin(a)	342	19	820	14	1,195
Other(b)	43,987	46,363	89,103	83,583	263,036
Total (Net Acres)	65,108	66,614	99,949	136,490	368,161

__________

(a) Includes assets held for sale as of December 31, 2014 (see Note 2 and Note 4 of Notes to Consolidated Financial Statements).

(b) Includes Green River Basin and other miscellaneous properties.

Gas Management

Our sales and marketing activities include the sale of our natural gas, oil and NGL production along with third-party purchases and sales of natural gas, which includes natural gas purchased from working interest owners in operated wells and other area third-party producers. Our sales and marketing activities also include the management of various natural gas related contracts such as transportation, storage and related price risk management activity. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in product revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses. Transportation capacity demand payments associated with contracts that are currently not utilized to support our development activities are captured as an expense item in gas management.

Purchase Commitments

In December 2010, we entered a long-term obligation to purchase 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) priced at market prices from a third party. Purchases under the 12-year contract began in January 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

Seasonality

Generally, the demand for natural gas decreases during the spring and fall months and increases during the winter months and in some areas during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Conversely, during extreme weather events such as blizzards, hurricanes, or heat waves, pipeline systems can become temporarily constrained thus amplifying localized price volatility. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer months. This can lessen seasonal demand fluctuations. World weather and resultant prices for liquefied natural gas can also affect deliveries of competing liquefied natural gas into this country from abroad, affecting the price of

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domestically produced natural gas. In addition, adverse weather conditions can also affect our production rates or otherwise disrupt our operations.

Hedging Activity

To manage the commodity price risk and volatility associated with owning producing natural gas, crude oil and NGL properties, we enter into derivative contracts for a portion of our expected future production. See further discussion in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Customers

Natural gas, oil and NGL production is sold through our sales and marketing activities to a variety of purchasers under various length contracts ranging from one day to multi-year under various pricing structures. Our third-party customers include other producers, utility companies, power generators, banks, marketing and trading companies and midstream service providers. In 2014, natural gas sales to BP Energy Company accounted for approximately 13 percent of our consolidated revenues. We believe that the loss of one or more of our current natural gas, oil or NGLs purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by other purchasers, absent a broad market disruption.

REGULATORY MATTERS

The oil and natural gas industry is extensively regulated by numerous federal, state, local and foreign authorities, including Native American tribes in the United States. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where we operate also regulate one or more of the following activities:

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities including seasonal wildlife closures;

• the employment of tribal members or use of tribal owned service businesses;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells;

• the notice to surface owners and other third parties; and

• the use, maintenance and restoration of roads and bridges used during all phases of drilling and production.

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State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, oil and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements in areas where we operate for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and site restoration. Most states have an administrative agency that requires the posting of performance bonds to fulfill financial requirements for owners and operators on state land. The Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing natural gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with them. The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting natural gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

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Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorating provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Operation on Native American Reservations

A portion of our leases are, and some of our future leases may be, regulated by Native American tribes. In addition to regulation by various federal, state, and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations in the United States. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the Office of Natural Resources Revenue and BLM, and the Environmental Protection Agency (“EPA”), together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment contractor preferences and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members or use tribal owned service businesses and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are often subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements, or delays in obtaining necessary approvals or permits pursuant to these regulations, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.

ENVIRONMENTAL MATTERS

Our operations are subject to numerous federal, state, local, Native American tribal and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, EPA’s 2011 – 2013 and 2014 – 2016 National Enforcement Initiatives include Energy Extraction and “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” The EPA has emphasized that this initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented.

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This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.

The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:

Hazardous Substances and Wastes. CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The Resource Conservation and Recovery Act (“RCRA”) generally does not regulate wastes generated by the exploration and production of natural gas and oil. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the CWA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

Waste Discharges. The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. On February 16, 2012, the EPA issued the final 2012 construction general permit (“CGP”) for stormwater discharges from construction activities involving more than one acre, which will provide coverage for a five-year period. The 2012 CGP modifies the prior CGP to implement the new Effluent Limitations Guidelines and New Source Performance Standards for the Construction and Development Industry. The new rule includes new and more stringent restrictions on erosion and sediment control, pollution prevention and stabilization, although a numeric turbidity limit for certain larger construction sites has been stayed as of January 4, 2011.

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Air Emissions. The CAA and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants and greenhouse gases (“GHGs”) have been developed by the EPA and may increase the costs of compliance for some facilities. In 2012, the EPA issued federal regulations affecting our operations under the New Source Performance Standards provisions (new Subpart OOOO) and expanded regulations under national emission standards for hazardous air pollutants, although implementation of some of the more rigorous requirements is not required until 2015.

Oil Pollution Act. The Oil Pollution Act of 1990, as amended (“OPA”), and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Endangered Species Act. The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Worker Safety. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

Hydraulic Fracturing. We ordinarily use hydraulic fracturing as a means to maximize the productivity of our oil and gas wells in all of the domestic basins in which we operate. In particular, all of our wells that we drill and complete in our core assets such as Williston, Piceance and San Juan require hydraulic fracturing for production. Although average drilling and completion costs for each basin will vary, as will the cost of each well within a given basin, on average approximately one-third of the drilling and completion costs for each of our wells for which we use hydraulic fracturing is associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget.

The protection of groundwater quality is extremely important to us. We follow applicable standard industry practices and legal requirements for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage), which conduct many inspections during operations that include hydraulic fracturing. Industry standards and legal requirements for groundwater protection focus on six principal areas:

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(i) pressure testing of well construction and integrity, (ii) lining of pits used to hold water and other fluids used in the drilling process isolated from surface water and groundwater, (iii) casing and cementing practices for wells to ensure separation of the production zone from groundwater, (iv) disclosure of the chemical content of fracturing liquids, (v) setback requirements as to the location of waste disposal areas, and (vi) pre- and post-drilling groundwater sampling. The legal requirements relating to the protection of surface water and groundwater vary from state to state and there are also federal regulations and guidance that apply to all domestic drilling. In addition, the American Petroleum Institute publishes industry standards and guidance for hydraulic fracturing and the protection of surface water and groundwater. Our policy and practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing.

In addition to the required use of and specifications for casing and cement in well construction, we observe regulatory requirements and what we consider best practices to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These include the following:

• Prior to perforating the production casing and hydraulic fracturing operations, the casing is pressure tested.

• Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all pressurized lines and connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, specialized equipment is utilized to monitor and record surface pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Should any problem be detected during the hydraulic fracturing treatment, the operation is shut down until the problem is evaluated, reported and remediated.

• As a means to protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing operation, special precautions are taken to ensure proper containment and storage of fluids. For example, any earthen pits containing non-fresh water must be lined with a synthetic impervious liner. These pits are tested regularly, and in certain sensitive areas have additional leak detection systems in place. At least two feet of freeboard, or available capacity, must be present in the pit at all times. In addition, earthen berms are constructed around any storage tanks, any fluid handling equipment, and in some cases around the perimeter of the location to contain any fluid releases. These berms are considered to be a “secondary” form of containment and serve as an added measure for the protection of groundwater.

• We conduct baseline water monitoring in many of the basins in which we use hydraulic fracturing.

• In Colorado we perform baseline water monitoring required by the Colorado Oil and Gas Conservation Commission.

• The BLM may require baseline water monitoring as a condition of approval for drilling permits.

• In Pennsylvania, we perform baseline water monitoring pursuant to Pennsylvania Department of Environmental Protection requirements.

• There are currently no regulatory requirements to conduct baseline water monitoring in the Williston Basin or the New Mexico portion of our San Juan Basin assets. We are pursuing options to begin voluntarily conducting water monitoring in the Williston Basin. The majority of our assets in the San Juan Basin are on federal lands, and there are few cases where water wells are within one to two miles of our wells, which is outside the range that we would typically sample.

Once a pipe is set in place, cement is pumped into the well where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design essentially eliminates a “pathway” for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. Furthermore, in the basins in which we conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable underground aquifers by thousands of feet of impermeable rock layers. This wide separation serves as a protective barrier, preventing any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones.

In addition, the vendors we employ to conduct hydraulic fracturing are required to monitor all pump rates and pressures during the fracturing treatments. This monitoring occurs on a real-time basis and data is recorded to ensure protection of groundwater.

The cement and steel casing used in well construction can have rare failures. Any failure in isolation is reported to the applicable oil and gas regulatory body. A remediation procedure is written and approved and then completed on the well before any further operations or production is commenced. Possible isolation failures may result from:

• Improper cementing work. This can create conditions in which hydraulic fracturing fluids and other natural occurring substances can migrate into the surrounding geological formation. Production casing cementing tops and cement bond effectiveness are evaluated using either a temperature log or an acoustical cement bond log prior to any completion operations. If the cement bond or cement top is determined to be inadequate for zone isolation, remedial cementing

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operations are performed to fill any voids and re-establish integrity. As part of this remedial operation, the casing is again pressure tested before fracturing operations are initiated.

• Initial casing integrity failure. The casing is pressure tested prior to commencing completion operations. If the test fails due to a compromise in the casing, the applicable oil and gas regulatory body will be notified and a remediation procedure will be written, approved and completed before any further operations are conducted. In addition, casing pressures are monitored throughout the fracturing treatment and any indication of failure will result in an immediate shutdown of the operation.

• Well failure or casing integrity failure during production. Loss of wellbore integrity can occur over time even if the well was correctly constructed due to downhole operating environments causing corrosion and stress. During production, the bradenhead, casing and tubing pressures are monitored and a casing failure can be identified and evaluated. Remediation could include placing additional cement behind casing, installing a casing patch, or plugging and abandoning the well, if necessary.

• “Fluid leakoff” during the fracturing process. Fluid leakoff can occur during hydraulic fracturing operations whereby some of the hydraulic fracturing fluid flows through the artificially created fractures into the micropore or pore spaces within the formation, existing natural fractures in the formation, or small fractures opened into the formation by the pressure in the induced fracture. Fluid leakoff is accounted for in the volume design of nearly every fracturing job and “pump-in” tests are often conducted prior to fracturing jobs to estimate the extent of fluid leakoff. In certain situations, a very fine grain sand is added in the initial part of the treatment to seal-off any small fractures of micropore spaces and mitigate fluid leak-off.

Approximately 99 percent of hydraulic fracturing fluids are made up of water and sand. We utilize major hydraulic fracturing service companies whose research departments conduct ongoing development of “greener” chemicals that are used in fracturing. We evaluate, test, and where appropriate adopt those products that are more environmentally friendly. We have also chosen to participate in a voluntary fracturing chemical registry that is a public website: www.fracfocus.org at which interested persons can find out information about fracturing fluids. This registry is a joint project of the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission and provides our industry with an avenue to voluntarily disclose chemicals used in the hydraulic fracturing process. The Company registered with the FracFocus Chemical Disclosure Registry in April 2011 and began uploading data when the registry went live on April 11, 2011. Through December 31, 2014, we have loaded data on more than 1,407 wells, including data relating to wells fractured since January 1, 2011, to the site. Consistent with other industry participants, we are not planning to add data on wells drilled prior to 2011. The information included on this website is not incorporated by reference in this Annual Report on Form 10-K.

In 2014, we used 99.9 percent recycled water for our hydraulic fracturing operations in our largest area of development, the Piceance Basin. This recycling process lessens the demand on local natural water resources. Any water that is recovered in our operations that is not used for our hydraulic fracturing operations is safely disposed in accordance with the state and federal rules and regulations in a manner that does not impact underground aquifers and surface waters. In the Marcellus, we use a blend of recycled water from our hydraulic fracturing operations with water from local sources.

Despite our efforts to minimize impacts on the environment from hydraulic fracturing activities, in light of the volume of our hydraulic fracturing activities, we have occasionally been engaged in litigation and received requests for information, notices of alleged violation, and citations related to the activities of our hydraulic fracturing vendors, none of which has resulted in any material costs or penalties.

Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate have considered Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

Federal agencies are also considering regulation of hydraulic fracturing. The EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program, and on May 10, 2012, the EPA published its proposed guidance on the issue. The public comment period for the proposed permitting guidance closed in 2012, and the EPA issued its final guidance in February 2014. In September 2014, the EPA published its Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans under the CWA confirming its intention to

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regulate wastewater discharges from on-shore Unconventional Oil and Gas Extraction and to discontinue establishing an effluent limitation guideline for the Coalbed Methane extraction industry. The EPA is also collecting information as part of a study into the effects of hydraulic fracturing on drinking water. The results of this study, which are expected to be published in a draft report for public and peer review in 2015, could result in additional regulations, which could lead to operational burdens similar to those described above. In connection with the EPA study, we have received and responded to a request for information from the EPA for 52 of our wells located in various basins that have been hydraulically fractured. The requested information covers well design, construction and completion practices, among other things. We understand that similar requests were sent to eight other companies that own or operate wells that utilized hydraulic fracturing.

In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a report on hydraulic fracturing in August 2011. The report concludes that the risk of fracturing fluids contaminating drinking water sources through fractures in the shale formations “is remote.” It also states that development of the nation’s shale resources has produced major economic benefits. The report includes recommendations to address concerns related to hydraulic fracturing and shale gas production, including but not limited to conducting additional field studies on possible methane leakage from shale gas wells to water reservoirs and adopting new rules and enforcement practices to protect drinking and surface waters. The Government Accountability Office is also examining the environmental impacts of produced water and the Counsel for Environmental Quality has been petitioned by environmental groups to develop a programmatic environmental impact statement under NEPA for hydraulic fracturing. The United States Department of the Interior is also considering whether to impose disclosure requirements or other mandates for hydraulic fracturing on federal land.

Several states, including Pennsylvania, Colorado, North Dakota, New Mexico and Wyoming, have adopted or are considering adopting, regulations that could restrict or impose additional requirements related to hydraulic fracturing. For example, Pennsylvania requires that detailed information be disclosed regarding the hydraulic fracturing fluids, including but not limited to, a list of chemical additives, volume of each chemical added, and list of chemicals in the material safety data sheets. Since June 2009, Colorado has required all operators to maintain a chemical inventory by well site for each chemical product used downhole or stored for use downhole during drilling, completion and workover operations, including fracture stimulation in an amount exceeding 500 pounds during any quarterly reporting period. Colorado adopted its final hydraulic fracturing chemical disclosure rules on December 13, 2011. Wyoming requires public disclosure of chemicals used in hydraulic fracturing. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. A number of states have also adopted regulations increasing the setback requirements, or are in the process of rulemaking to address the issue, including Colorado, New Mexico, Wyoming and Pennsylvania.

In addition, a number of local governments in Colorado have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities, while some state and local governments in the Appalachian Basin and San Juan Basin in New Mexico have considered or imposed temporary moratoria on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by the EPA or the relative state agencies are completed. Additionally, publicly operated treatment works facilities in Pennsylvania have ceased taking wastewater from hydraulic fracturing operations, and we are now recycling this wastewater and utilizing it in subsequent hydraulic fracturing operations. Certain organizations have promoted ballot initiatives at the local level that are aimed at imposing restrictions on hydraulic fracturing, and may attempt to do the same on a wider basis in one or more states where we operate. At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

Global Warming and Climate Change. Recent scientific studies have suggested that emissions of GHGs, including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. Both houses of Congress have previously considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The EPA has begun to regulate GHG emissions. On December 7, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public heath and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA issued a final rule that went into effect in 2011 that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions. On November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, and our reporting began in 2012 for emissions occurring in 2011. We are required to report our GHG emissions under this rule but are not subject to GHG permitting requirements. Several of the EPA’s GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

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Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. In March 2014, the White House published the President’s Climate Action Plan Strategy to Reduce Methane Emissions. Such developments may affect how these GHG initiatives will impact our operations. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources and may increase our litigation risk for such claims. New legislation or regulatory programs that restrict emissions of or require inventory of GHGs in areas where we operate have adversely affected or will adversely affect our operations by increasing costs. The cost increases so far have resulted from costs associated with inventorying our GHG emissions, and further costs may result from the potential new requirements to obtain GHG emissions permits, install additional emission control equipment and an increased monitoring and record-keeping burden.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas or otherwise cause us to incur significant costs in preparing for or responding to those effects.

COMPETITION

We compete with other oil and gas concerns, including major and independent oil and gas companies in the development, production and marketing of natural gas. We compete in areas such as acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.

In our gas management services business, we compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. We also compete with brokerage houses, energy hedge funds and other energy-based companies offering similar services.

EMPLOYEES

At December 31, 2014, we had approximately 1,100 full-time employees.

FINANCIAL INFORMATION ABOUT SEGMENTS

As of December 31, 2014, our operations included a domestic segment and an international segment. Our international segment is classified as discontinued operations for financial reporting purposes. See Item 8—Financial Statements and Supplementary Data—Consolidated Balance Sheets for the total assets of our domestic segment. See Item 8—Financial Statements and Supplementary Data—Consolidated Statements of Operations for revenues, and profits or losses of our domestic segment. See Item 8—Financial Statements and Supplementary Data— Note 2 of Notes to Consolidated Financial Statements for financial information with respect to our international segment’s revenues, profits or losses, and total assets.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Item 8—Financial Statements and Supplementary Data—Consolidated Statements of Operations for amounts of revenues during the last three fiscal years from external customers attributable to the United States. See Item 8—Financial Statements and Supplementary Data—Note 2 of Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to all foreign countries. See Note 5 of Notes to Consolidated Financial Statements for information relating to Property, Plant and Equipment for the last two fiscal years, located in the United States and Note 2 for Property, Plant and Equipment for all foreign countries.

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WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We make available free of charge through our website, www.wpxenergy.com/investors, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, other reports filed under the Securities Exchange Act of 1934 (“Exchange Act”) and all amendments to those reports simultaneously or as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Our reports are also available free of charge on the SEC’s website, www.sec.gov. You may inspect and copy our reports at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the Public Reference Room. Also available free of charge on our website are the following corporate governance documents:

• Amended and Restated Certificate of Incorporation

• Restated Bylaws

• Corporate Governance Guidelines

• Code of Business Conduct, which is applicable to all WPX Energy directors and employees, including the principal executive officer, the principal financial officer and the principal accounting officer

• Audit Committee Charter

• Compensation Committee Charter

• Nominating and Governance Committee Charter

All of our reports and corporate governance documents may also be obtained without charge by contacting Investor Relations, WPX Energy, Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172.

We maintain an Internet site at www.wpxenergy.com. We do not incorporate our Internet site, or the information contained on that site or connected to that site, into this Annual Report on Form 10-K.

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Certain matters contained in this Annual Report on Form 10-K 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;

• expansion and growth of our business and operations;

• financial condition and liquidity;

• business strategy;

• estimates of proved natural gas and oil reserves;

• reserve potential;

• development drilling potential;

• cash flow from operations or results of operations;

• acquisitions or divestitures

• seasonality of our business; and

• natural gas, NGLs and crude oil prices and demand.

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 natural gas and oil 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; and

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

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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. These factors are described in “Risk Factors.”

RISK FACTORS

You should carefully consider each of the following risks, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this report. Some of the risks described below relate to our business, while others relate principally to the securities markets and ownership of our common stock. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could suffer materially and adversely. In that case, the trading price of our common stock could decline, and you might lose all or part of your investment.

Risks Related to Our Business

Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, development and acquisition activities require substantial capital expenditures. We expect to fund our capital expenditures through a combination of cash flows from operations and, when appropriate, borrowings under our credit facility. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of natural gas and oil and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our natural gas and oil production or reserves, and in some areas a loss of properties.

Failure to replace reserves may negatively affect our business.

The growth of our business depends upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not always be able to find, develop or acquire additional reserves at acceptable costs. If natural gas or oil prices increase, our costs for additional reserves would also increase; conversely if natural gas or oil prices decrease, it could make it more difficult to fund the replacement of our reserves.

Exploration and development drilling may not result in commercially productive reserves.

Our past success rate for drilling projects should not be considered a predictor of future commercial success. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The new wells we drill or participate in may not be commercially productive, and we may not recover all or any portion of our investment in wells we drill or participate in. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed, canceled or rendered unprofitable or less profitable than anticipated as a result of a variety of other factors, including:

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

• equipment failures or accidents;

• adverse weather conditions, such as floods or blizzards;

• title and lease related problems;

• limitations in the market for natural gas and oil;

• unexpected drilling conditions or problems;

• pressure or irregularities in geological formations;

• regulations and regulatory approvals;

• changes or anticipated changes in energy prices; or

• compliance with environmental and other governmental requirements.

If natural gas and oil prices decrease, we may be required to take write-downs of the carrying values of our natural gas and oil properties.

Accounting rules require that we review periodically the carrying value of our natural gas and oil properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our natural gas and oil properties. A writedown constitutes a non-cash charge to earnings. For example, due to the drop in forward oil and natural gas prices in the fourth quarter of 2014, we performed assessments of our proved and unproved properties. As a result, we recorded impairments of capitalized costs of certain proved producing properties and costs of acquired unproved reserves of $20 million in 2014. In addition to those long-lived assets for which impairment charges were recorded, certain others were reviewed for which no impairment was required. These reviews included $3.8 billion of net book value associated with our predominantly natural gas proved properties and $2.7 billion of net book value associated with our predominantly oil proved properties and utilized inputs generally consistent with those described above. Many judgments and assumptions are inherent and to some extent interdependent of one another in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. We may incur impairment charges for these or other properties in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Estimating reserves and future net revenues involves uncertainties. Decreases in natural gas and oil prices, or negative revisions to reserve estimates or assumptions as to future natural gas and oil prices may lead to decreased earnings, losses or impairment of natural gas and oil assets.

Reserve estimation is a subjective process of evaluating underground accumulations of oil and gas that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and relate to projects for which the extraction of hydrocarbons must have commenced or for which the operator is reasonably certain will commence within a reasonable time.

The process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this report represents estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also be sufficient to trigger impairment losses on certain properties which would result in a noncash charge to earnings.

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The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 38 percent of our total estimated proved reserves at December 31, 2014 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserves data included in the reserves engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

The present value of future net revenues from our proved reserves will not necessarily be the same as the value we ultimately realize of our estimated natural gas and oil reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net revenues from our natural gas and oil properties will be affected by factors such as:

• actual prices we receive for natural gas and oil;

• actual cost of development and production expenditures;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A portion of our acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, the leases will expire. If we do not extend our leases and our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory and lease issues.

Prices for natural gas, oil and NGLs are volatile, and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing business.

Our revenues, operating results, future rate of growth and the value of our business depend primarily upon the prices of natural gas, oil and NGLs. Price volatility can impact both the amount we receive for our products and the volume of products we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money under our credit facility or raise additional capital.

The markets for natural gas, oil and NGLs are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:

• weather conditions;

• the level of consumer demand;

• the overall economic environment;

• worldwide and domestic supplies of and demand for natural gas, oil and NGLs;

• turmoil in the Middle East and other producing regions;

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• the activities of the Organization of Petroleum Exporting Countries;

• terrorist attacks on production or transportation assets;

• variations in local market conditions (basis differential);

• the price and availability of other types of fuels;

• the availability of pipeline capacity;

• supply disruptions, including plant outages and transportation disruptions;

• the price and quantity of foreign imports of natural gas and oil;

• domestic and foreign governmental regulations and taxes;

• volatility in the natural gas and oil markets;

• the credit of participants in the markets where products are bought and sold; and

• the adoption of regulations or legislation relating to climate change.

Our business depends on access to natural gas, oil and NGL transportation systems and facilities.

The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability, proximity, capacity and expansion of transportation systems and facilities owned by third parties. For example, we can provide no assurance that sufficient transportation capacity will exist for expected production from the Williston Basin and San Juan Basin or that we will be able to obtain sufficient transportation capacity on economic terms.

A lack of available capacity on transportation systems and facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these systems and facilities for an extended period of time could negatively affect our revenues. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.

We may have excess capacity under our firm transportation contracts, or the terms of certain of those contracts may be less favorable than those we could obtain currently.

We have entered into contracts for firm transportation that may exceed our transportation needs. Any excess transportation commitments will result in excess transportation costs that could negatively affect our results of operations. In addition, certain of the contracts we have entered into may be on terms less favorable to us than we could obtain if we were negotiating them at current rates, which also could negatively affect our results of operations.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues or increase our costs. As of December 31, 2014 , we were not the operator of approximately 12 percent of our total net production. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.

Our portfolio of derivative and other energy contracts includes wholesale contracts to buy and sell natural gas, oil and NGLs that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our business, we often extend credit to our counterparties. We are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral that secures our counterparty’s obligation is inadequate, we will suffer a loss. Downturns in the economy or disruptions in the global credit markets could cause more of our counterparties to fail to perform than we expect.

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Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results.

The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all commodity price risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.

Our use of derivatives through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.

The impact of changes in market prices for natural gas, oil and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for natural gas, oil or NGLs were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities and reduce our liquidity.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Title VII of the Dodd-Frank Act (“Title VII”) provides for new statutory and regulatory requirements for derivative transactions in the major energy markets, including swaps, hedging and other transactions.

Among other things, Title VII requires that certain classes of swaps be cleared on a derivatives clearing organization unless an exemption to clearing is available to the parties to the swap. As of February 25, 2015, the Commodity Futures Trading Commission (the “CFTC”) has designated only certain classes of interest rate swaps and index credit default swaps for mandatory clearing. While the swaps we currently use do not require clearing, it is unclear when the CFTC will designate other classes of swaps that we use, such as physical commodity swaps, for mandatory clearing. The clearing of such transactions would require us to post cash or other liquid collateral in connection with those transactions, and may cause increased costs to dealers that may be reflected in the pricing they make available to us. Moreover, certain of the transactions required to be cleared will have to be executed on boards of trade which may also adversely affect the pricing we are able to obtain.

The CFTC, the SEC and other regulators that oversee swap dealers have proposed regulations that may require us to post variation and/or initial margin. Posting of collateral could affect our liquidity, financial flexibility, and available cash. These regulations have not yet been finalized, however, and so it is difficult to predict the impact they will have on us.

Title VII also provides for the creation of position limits for certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas and light sweet crude oil. The CFTC’s original regulation setting position limits was vacated in September 2012 by the United States District Court for the District of Columbia. However, the CFTC recently proposed new position limits rules that would set limits on the positions in such contracts that market participants could hold, subject to exceptions for certain bona fide hedging transactions intended to hedge certain price risks. The new position limit rules are not yet final and their impact on us is uncertain at this time.

Section 716 of the Dodd-Frank Act, commonly referred to as the “Swaps Pushout Rule,” may also require certain of the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities. In December 2014, the President signed into law an amendment to Section 716 that reduced the impact of the pushout rule. Under the amended pushout rule, certain depository institutions will not be required to spin off their derivatives activities unless they are trading in a narrow class of swaps known as structured finance swaps. In the event that any of our counterparties are required to spin off their derivatives activities, the separate entities would be our counterparties in future swaps and may not be as creditworthy as our current counterparties.

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The complete impact of the Dodd-Frank Act on our hedging activities is unknown at this time due to the fact that the SEC, the CFTC and other federal regulatory bodies that have involvement in this area have yet to complete the adoption and implementation of all of the rules and regulations required to implement the swap provisions of the Dodd-Frank Act. Although we believe the derivative contracts that we enter into should not be impacted by position limits and that we should generally be eligible to elect the exception from any requirement to clear our hedging transactions through a clearing organization and execute those transactions on an exchange, there is a risk that we might not satisfy the conditions to reliance on the end-user exception. Additionally, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. The impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC and other federal regulators, among other factors.

Compliance with the regulations adopted and to be adopted by the CFTC and other federal regulatory bodies may significantly increase the cost of entering into and maintaining derivative contracts. The increased costs may include costs associated with swap recordkeeping and reporting requirements as well as any required posting of cash or other liquid collateral for our commodities hedging transactions under circumstances in which we do not currently do so. Posting of additional cash or liquid collateral could also impact our liquidity, reduce cash available for capital expenditures and reduce our ability to execute hedges against commodity price uncertainty to protect cash flows. The Dodd-Frank Act and related swaps regulations may lead to material alterations of the terms of derivative contracts we enter, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and the related regulations, our results of operations may become more volatile or be otherwise adversely affected and our cash flows may be less predictable. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act is to lower commodity prices.

Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, liquidity and cash flows.

We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ and counterparties’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write-down or write-off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.

We face competition in acquiring new properties, marketing natural gas and oil and securing equipment and trained personnel in the natural gas and oil industry.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and oil and securing equipment and trained personnel. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.

There are operational risks associated with drilling for, production, gathering, transporting, storage, processing and treating of natural gas and oil and the fractionation and storage of NGLs, including:

• hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters;

• aging infrastructure and mechanical problems;

• damages to pipelines, pipeline blockages or other pipeline interruptions;

• uncontrolled releases of natural gas (including sour gas), oil, NGLs, brine or industrial chemicals;

• operator error;

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• pollution and environmental risks;

• fires, explosions and blowouts;

• risks related to truck and rail loading and unloading; and

• terrorist attacks or threatened attacks on our facilities or those of other energy companies.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.

We currently maintain excess liability insurance that covers us, our subsidiaries and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability.

Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. All of our insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.

In addition, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.

Regulators and legislators continue to take a renewed look at accounting practices, financial and reserves disclosures and companies’ relationships with their independent public accounting firms and reserves consultants. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations and financial condition.

Our operating results might fluctuate on a seasonal and quarterly basis.

Our revenues can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

Our debt agreements impose restrictions on us that may limit our access to credit and adversely affect our ability to operate our business.

Our credit facility contains various covenants that restrict or limit, among other things, our ability to grant liens, merge or sell substantially all of our assets, make investments, guarantees, loans or advances in non-subsidiaries, enter into certain hedging agreements, incur additional debt and enter into certain affiliate transactions. In addition, our credit facility contains financial covenants, including an additional financial covenant if our credit ratings drop below a specified level, and other limitations with which we will need to comply and which may limit our ability to borrow under the facility. Similarly, the

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indentures governing our senior notes restrict our ability to grant liens to secure certain types of indebtedness and merge or sell substantially all of our assets. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.

Our failure to comply with the covenants in our debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

Our ability to repay, extend or refinance our debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance our debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.

Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, increased difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.

We are subject to risks associated with climate change.

There is a growing belief that emissions of GHGs may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.

In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. Numerous states have announced or adopted programs to stabilize and reduce GHGs, as well as their own reporting requirements. On September 22, 2009, the EPA finalized a GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. On November 8, 2010, the EPA also issued GHG monitoring and reporting regulations specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year-the Greenhouse Gas Reporting Program. The rule requires annual reporting of GHG emissions by regulated facilities to the EPA. We are required to report our GHG emissions to the EPA each year in March under this rule, and the EPA publishes the data on its website. The EPA has also enacted permitting requirements for GHG emissions under the CAA for certain stationary sources and newer modification projects. In March 2014, the White House published the President’s Climate Action Plan Strategy to Reduce Methane Emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.

The actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to

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complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.

Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations affecting drilling and well completion, gathering, transportation, and storage, and we may incur substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

• Clean Air Act (“CAA”) and analogous state laws, which impose obligations related to air emissions;

• Clean Water Act (“CWA”), and analogous state laws, which regulate discharge of wastewaters and storm water from some our facilities into state and federal waters, including wetlands;

• Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

• Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities;

• National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environment impacts of a proposed federal action before it is approved, such as drilling on federal lands;

• Safe Drinking Water Act (“SDWA”), which restricts the disposal, treatment or release of water produced or used during oil and gas development;

• Endangered Species Act (“ESA”), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and

• Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulation of above ground storage tanks and sets forth liability for spills by responsible parties.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which were extended by the EPA for fiscal years 2014 to 2016, and which include Energy Extraction and “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the

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environment.” This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions. For instance, the Obama administration announced on January 14, 2015, its interagency strategy to control methane emissions to reduce petroleum-sector methane emissions 40 to 45 percent by 2025 from 2012 levels. EPA plans to propose rules for new and modified wells in 2015 and finalize them in 2016. The Interior Department is to announce standards in the spring of 2015 aimed at reducing methane flaring at wells on federal land; the Department of Energy is to develop new ways to detect and repair methane leaks; the Department of Transportation is to develop new pipeline safety standards that also reduce leaks. In addition, federal and state agencies could impose additional safety requirements, any of which could affect our profitability.

Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations in order to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs. Recently, there has been heightened debate about the hydraulic fracturing process and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. If adopted, this legislation could establish an additional level of regulation and permitting at the federal, state or local levels, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. The EPA published its “Status Report” in December 2012 and expects to publish results for public and peer review in 2015. In September 2014, the EPA published its Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans under the CWA confirming its intention to regulate wastewater discharges from on-shore unconventional oil and gas extraction and to discontinue establishing an effluent limitation guideline for the coalbed methane extraction industry. In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a report on hydraulic fracturing in August 2011, which includes recommendations to address concerns related to hydraulic fracturing and shale gas production, including but not limited to conducting additional field studies on possible methane leakage from shale gas wells to water reservoirs and adopting new rules and enforcement practices to protect drinking and surface waters.

Several states have adopted or considered legislation requiring the disclosure of fracturing fluids and other restrictions on hydraulic fracturing, including states in which we operate (e.g., Wyoming, Pennsylvania, Colorado, North Dakota and New Mexico). Certain organizations have prompted ballot initiatives at the local level that are directed at imposing restrictions on hydraulic fracturing, and such ballot initiatives may be attempted on a wider basis in one or more states where we operate. The U.S. Department of the Interior is also considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business as well as delay or prevent the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.

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Our ability to produce gas could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.

Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations, particularly with respect to our Appalachian Basin, San Juan Basin, Williston Basin and Piceance Basin operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. In September 2014, the EPA published its Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans under the CWA confirming its intention to regulate wastewater discharges from on-shore unconventional oil and gas extraction and to discontinue establishing an effluent limitation guideline for the coalbed methane extraction industry. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

Legal and regulatory proceedings and investigations relating to the energy industry, and the complex government regulations to which our businesses are subject, have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in regulations or in their interpretation or implementation, or the introduction of new laws, regulations or permitting requirements applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Current legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our facilities, our customers, our vendors or our service providers, and future changes in laws and regulations could have a material adverse effect on our financial condition, results of operations and cash flows. For example, several ruptures on third-party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed, including new regulations covering gathering pipelines that have not previously been subject to regulation. Such reforms, if adopted, could significantly increase our costs.

Certain of our properties, including our operations in the Williston Basin, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, BLM and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native

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American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.

Tax laws and regulations may change over time, including changes to certain federal income tax deductions currently available with respect to oil and gas exploration and production.

Tax laws and regulations are highly complex and subject to interpretation, and the tax laws and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various jurisdictions for the periods for which the filings are made. If these laws or regulations change, or if the taxing authorities do not agree with our interpretation, it could have a material adverse effect on us.

President Obama has annually proposed changes to certain federal income tax provisions currently available to oil and gas exploration and production companies. The new chairmen of the House Ways & Means Committee and the Senate Finance Committee have also expressed their desire for business tax reform. Energy-related changes being discussed include, but are not limited to, (i) repeal of the percentage depletion allowance for oil and gas properties; (ii) elimination of the ability to fully deduct intangible drilling and development costs in the year incurred; (iii) repeal of the manufacturing deduction for certain U.S. production activities; and (iv) extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. Changes to federal tax deductions, as well as any changes to or the imposition of new state or local taxes (including production, severance, or similar taxes) could negatively affect our financial condition and results of operations.

Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.

We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:

• some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;

• we may assume liabilities that were not disclosed to us or that exceed our estimates;

• properties we acquire may be subject to burdens on title that we were not aware of at the time of acquisition or that interfere with our ability to hold the property for production;

• we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

• acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

• we may issue additional equity or debt securities related to future acquisitions.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

In order to finance acquisitions of additional producing or undeveloped properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us.

Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

Some studies indicate a high failure rate of outsourcing relationships. A deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.

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Certain of our accounting services are currently provided by our outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which our outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

Our assets and operations can be adversely affected by weather and other natural phenomena.

Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. Insurance may be inadequate, and in some instances, it may not be available on commercially reasonable terms. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.

Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.

Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to the ability to produce, process, transport or distribute natural gas, oil, or NGLs. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs.

We entered into a number of agreements with Williams prior to our separation or "spin-off" from that company on December 31, 2011. Our agreements with Williams require us to assume the past, present, and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.

We negotiated all of our agreements with Williams as a wholly-owned subsidiary of Williams. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the separation and distribution agreement, we have assumed all past, present and future liabilities (other than tax liabilities which will be governed by the tax sharing agreement as described herein) related to our business, and we will agree to indemnify Williams for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant. The allocation of assets and liabilities between Williams and us may not reflect the allocation that would have been reached between two unaffiliated parties.

We may increase our debt or raise additional capital in the future, which could affect our financial health, and may decrease our profitability.

We may increase our debt or raise additional capital in the future, subject to restrictions in our debt agreements. If our cash flow from operations is less than we anticipate, or if our cash requirements are more than we expect, we may require more financing. More financing may also be necessary if we are unable to execute dispositions of assets that are underperforming or which are no longer a part of our strategic focus. However, debt or equity financing may not be available to us on terms acceptable to us, if at all. If we incur additional debt or raise equity through the issuance of our preferred stock, the terms of the debt or our preferred stock issued may give the holders rights, preferences and privileges senior to those of holders of our common stock, particularly in the event of liquidation. The terms of the debt may also impose additional and more stringent restrictions on our operations than we currently have. If we raise funds through the issuance of additional equity, your ownership in us would be diluted. If we are unable to raise additional capital when needed, it could affect our financial health, which could negatively affect your investment in us.

If there is a determination that the spin-off from Williams is taxable for U.S. federal income tax purposes, then Williams and its stockholders could incur significant income tax liabilities, and we could incur significant liabilities.

Prior to our spin-off from Williams on December 31, 2011, Williams received an opinion of its outside tax advisor to the effect that the spin-off would not result in the recognition, for federal income tax purposes, of income, gain or loss to Williams, and Williams’ stockholders. In addition, Williams received a private letter ruling in which the IRS made various rulings, including that the spin-off will not result in the recognition, for federal income tax purposes, of income, gain or loss to Williams and Williams’ stockholders. Under the tax sharing agreement, we are required to indemnify Williams against tax-related liabilities that may be incurred by Williams relating to the spin-off, to the extent caused by a breach of any representations or

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covenants we made with respect to the spin-off and relied upon in the tax opinion or private letter ruling. The IRS is currently auditing Williams’ 2011 consolidated federal income tax return that includes the spin-off.

We continue to be subject to the tax sharing agreement with Williams for the 2011 tax year.

For any tax periods ending on or before the spin-off, we and our U.S. subsidiaries were included in Williams’ consolidated group for federal income tax purposes as well as any combined, consolidated or unitary tax returns of Williams for state or local income tax purposes. Under the tax sharing agreement with Williams, for each period in which we were consolidated or combined with Williams for purposes of any tax return, a pro forma tax return was prepared for us as if we filed our own consolidated, combined or unitary return. 2011 is the only open federal tax period for which we are still subject to the tax sharing agreement with Williams. For any adjustments to the pro forma tax returns following the spin-off we will reimburse Williams for any additional taxes shown on the pro forma tax returns, and Williams will reimburse us for reductions in the taxes shown on the pro forma tax returns. We also have deferred tax assets that were allocated to us by Williams that could decrease or increase due to adjustments that change those allocations, whether or not related to our business. Williams effectively controls all of our tax decisions in connection with any Williams consolidated, combined or unitary income tax returns in which we are included. Thus Williams will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Williams and detrimental to us.

Third parties may seek to hold us responsible for liabilities of Williams that we did not assume in our agreements.

Third parties may seek to hold us responsible for retained liabilities of Williams. Under our agreements with Williams, Williams agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from Williams.

Our prior and continuing relationship with Williams exposes us to risks attributable to businesses of Williams.

Williams is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of Williams that are incurred through a breach of the separation and distribution agreement or any ancillary agreement by Williams or its affiliates other than us, or losses that are attributable to Williams in connection with the spin-off or are not expressly assumed by us under our agreements with Williams. Any claims made against us that are properly attributable to Williams in accordance with these arrangements would require us to exercise our rights under our agreements with Williams to obtain payment from Williams. We are exposed to the risk that, in these circumstances, Williams cannot, or will not, make the required payment.

Risks Related to Our Common Stock

Future issuances of our common stock may depress the price of our common stock.

In the future, we may issue our securities in connection with investments or acquisitions. The amount of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding shares of our common stock.

We do not anticipate paying any dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any income or realize a return on your investment.

We do not anticipate paying any dividends on our common stock in the foreseeable future. Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law (“DGCL”). The future payment of dividends will be at the sole discretion of our Board of Directors and will depend on many factors, including our earnings, capital requirements, financial condition and other considerations that our Board of Directors deems relevant. As a result, to receive any income or realize a return on your investment, you will need to sell your shares of common stock. You may not be able to sell your shares of common stock at or above the price you paid for them.

Provisions of Delaware law and our charter documents may delay or prevent an acquisition of us that stockholders may consider favorable or may prevent efforts by our stockholders to change our directors or our management, which could decrease the value of your shares.

Section 203 of the DGCL and provisions in our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire us without the consent of our Board of Directors. These provisions include the following:

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• restrictions on business combinations for a three-year period with a stockholder who becomes the beneficial owner of more than 15 percent of our common stock;

• restrictions on the ability of our stockholders to remove directors;

• supermajority voting requirements for stockholders to amend our organizational documents; and

• a classified Board of Directors.

Although we believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics and thereby provide an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board of Directors, these provisions apply even if the offer may be considered beneficial by some stockholders. Further, these provisions may discourage potential acquisition proposals and may delay, deter or prevent a change of control of our company, including through unsolicited transactions that some or all of our stockholders might consider to be desirable. As a result, efforts by our stockholders to change our directors or our management may be unsuccessful.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information regarding our properties is included in Item 1 of this report.

Item 3. Legal Proceedings

See Item 8—Financial Statements and Supplementary Data—Note 9 of our Notes to Consolidated Financial Statements for the information that is called for by this item.

In August 2014, we acquired acreage in New Mexico that includes historically operating wells.  We are working with the New Mexico Air Quality Board to address violations of permitting requirements that occurred on this acreage prior to our acquisition, and we may be subject to fines in excess of $100,000 in connection with these violations. 

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the ticker symbol “WPX.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange.

	Years Ended December 31,
	2014				2013
	High		Low		High		Low
Common Stock:
Fourth quarter	$	24.42	$	10.01	$	23.69	$	17.54
Third quarter	$	26.79	$	20.05	$	20.36	$	18.10
Second quarter	$	24.35	$	17.97	$	21.11	$	14.87
First quarter	$	20.55	$	16.80	$	16.98	$	14.03

At February 25, 2015, there were 8,099 holders of record of our common stock.

We have not paid or declared any cash dividends on our common stock. Any decision as to future payment of dividends is subject to the discretion of our Board of Directors.

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Item 6. Selected Financial Data

The following financial data at December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records. The financial statements included in this Form 10-K may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand-alone public company during all periods presented. Accordingly, our results for periods prior to 2012 should not be relied upon as an indicator of our future performance.

	Years Ended December 31,
	2014		2013			2012			2011			2010
Statement of operations data:	(Millions, except per share amounts)
Revenues	$	3,493	$	2,431		$	2,900		$	3,531		$	3,645
Income (loss) from continuing operations(a)	$	129	$	(1,104	)	$	(174	)	$	106		$	(935	)
Income (loss) from discontinued operations(b)	42		(87		)	(37		)	(398		)	(348		)
Net income (loss)	171		(1,191		)	(211		)	(292		)	(1,283		)
Less: Net income attributable to noncontrolling interests	7		(6		)	12			10			8
Net income (loss) attributable to WPX Energy, Inc.	$	164	$	(1,185	)	$	(223	)	$	(302	)	$	(1,291	)
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	129	$	(1,092	)	$	(174	)	$	106		$	(935	)
Income (loss) from discontinued operations	$	35	$	(93	)	$	(49	)	$	(408	)	$	(356	)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.63	$	(5.45	)	$	(0.87	)	$	0.54		$	(4.75	)
Income (loss) from discontinued operations	$	0.18	$	(0.46	)	$	(0.25	)	$	(2.07	)	$	(1.80	)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.62	$	(5.45	)	$	(0.87	)	$	0.54		$	(4.75	)
Income (loss) from discontinued operations	$	0.18	$	(0.46	)	$	(0.25	)	$	(2.07	)	$	(1.80	)

	As of December 31,
	2014		2013		2012		2011		2010
Balance sheet data:	(Millions)
Notes payable to Williams—current(c)	$	—	$	—	$	—	$	—	$	2,261
Long-term debt	$	2,280	$	1,911	$	1,501	$	1,501	$	—
Total assets	$	8,798	$	8,429	$	9,456	$	10,432	$	9,846
Total stockholder's equity	$	4,319	$	4,109	$	5,268	$	5,678	$	4,412
Total equity, including noncontrolling interests(c)	$	4,428	$	4,210	$	5,371	$	5,759	$	4,484

__________

(a) Income (loss) from continuing operations for the year ended December 31, 2014 includes approximately $87 million of impairment charges related to certain exploratory well costs, producing properties and costs of acquired unproved reserves. Income (loss) from continuing operations for the year ended December 31, 2013 includes $860 million of impairment charges primarily related to producing properties in the Appalachian Basin and costs of acquired unproved reserves in the Piceance Basin. In addition, income (loss) from continuing operations for 2013 includes a $317 million impairment charge to estimated fair value of unproved leasehold costs in the Appalachian Basin and $20 million impairment on our equity method investment. Income (loss) from continuing operations for the year ended December 31, 2012 includes $123 million of impairment charges related to producing properties in the Green River Basin and costs of acquired unproved reserves in the Piceance Basin. Income (loss) from continuing operations for the year ended December 31, 2010 includes a $1 billion impairment charge related to goodwill and a $175 million impairment charge related to costs of acquired unproved reserves in the Piceance Basin. See Note 4 of Notes to Consolidated Financial Statements for further discussion of the impairments in 2014, 2013 and 2012.

(b) Income (loss) from discontinued operations includes the results of Apco Oil and Gas International Inc., holdings in the Powder River Basin and holdings in the Barnett Shale and Arkoma Basin. Activity in 2014 includes a $45 million

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impairment charge related to the net assets held for sale in the Powder River Basin. Activity in 2013 reflects a $36 million gain on the sale of Powder River Basin deep rights leasehold. Activity in 2013, 2012 and 2011 reflects pre-tax impairment charges of $192 million, $102 million and $367 million, respectively, related to the Powder River Basin producing properties and costs of acquired unproved reserves. Activity in 2012 reflects a $38 million pre-tax gain recorded upon closing the sale of the Barnett Shale and Arkoma Basin. Activity in 2011 and 2010 reflects pre-tax impairment charges of $180 million and $503 million, respectively, related to the Barnett Shale operations. See Note 2 of of Notes to Consolidated Financial Statements for further discussion of discontinued operations in 2014, 2013 and 2012.

(c) On June 30, 2011, all of our notes payable to Williams were canceled by Williams. The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in total equity that was partially offset by a $981 million cash distribution to Williams. See Part II, Item 8, Financial Statements and Supplementary Data for activity related to our equity at December 31, 2014 and 2013.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserves base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our oil positions in the Williston Basin in North Dakota and the San Juan Basin in the southwestern United States. Our other areas of domestic operations include natural gas plays in the San Juan Basin and the Appalachian Basin in Pennsylvania. In addition, we have historically had operations in the Powder River Basin in Wyoming and a 69 percent controlling ownership interest in Apco Oil and Gas International Inc. (“Apco”), which has oil and gas activities in South America and, until January 29, 2015, traded on the NASDAQ Capital Market under the symbol “APAGF”. As of December 31, 2014, Powder River Basin and Apco are reported as discontinued operations.

In conjunction with our exploration and development activities, we engage in sales and marketing activities that include the sale of our natural gas, oil and NGL production, along with third-party purchases and sales of natural gas and oil, which include natural gas and oil purchased from working interest owners in operated wells and other area third-party producers. Our sales and marketing activities also include the management of various natural gas related contracts such as transportation, storage and related price risk management activities. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in product revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses. Due to the seasonal aspects of the transportation and storage contracts utilized to manage our third-party marketing obligations, our quarter to quarter results may vary with economic gains in the winter months and losses in the summer months.

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 in Part II, Item 8 in this Form 10-K. 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-K, particularly in “Risk Factors” and “Forward-Looking Statements.”

Basis of Presentation

During January 2015, we completed the disposition of our international interests pursuant to the successful merger of Apco with a subsidiary of privately held Pluspetrol Resources Corporation (“Pluspetrol”). We received approximately $294 million for the disposition of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol. Together, these non-operated international holdings comprised our international segment.  The results of operations of our international segment are reported as discontinued operations.

During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. As a result, we have reported the results of operations of the Powder River Basin as discontinued operations.

Also included in discontinued operations through second-quarter 2012, are results from our holdings in the Barnett Shale and the Arkoma Basin, which were sold in 2012.

See Note 2 of Notes to Consolidated Financial Statements for further discussion of our discontinued operations. Unless indicated otherwise, the following discussion relates to continuing operations.

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Overview

The following table presents our production volumes and financial highlights for 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013			2012
Production Sales Volume Data(a):
Natural gas (MMcf)	280,386			295,934			321,162
Oil (MBbls)	9,244			5,919			4,394
NGLs (MBbls)	6,250			7,415			10,392
Combined equivalent volumes (MMcfe)	373,352			375,940			409,877
Combined equivalent volumes (Mboe)	62,225			62,657			68,313
Production Sales Volume Per Day(a):
Natural Gas (MMcf/d)	768			811			878
Oil (MBbls/d)	25			16			12
NGL (MBbls/d)	17			20			28
Combined equivalent volumes (MMcfe/d)	1,023			1,030			1,120
Financial Data (millions):
Total revenues	$	3,493		$	2,431		$	2,900
Operating income (loss)	$	326		$	(1,601	)	$	(157	)
Cash capital expenditures(b)	$	(1,807	)	$	(1,154	)	$	(1,521	)

__________

(a) Excludes production from our discontinued operations.

(b) Includes capital expenditures related to discontinued operations of $96 million, $54 million and $79 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Our 2014 operating results were $1.9 billion favorable compared to 2013. Favorable impacts include a $558 million favorable change in derivatives not designated as hedges, a $250 million decrease in exploration expenses (including exploratory well costs and unproved leasehold impairments), $190 million higher oil and condensate sales and $106 million higher natural gas sales. Additionally, impairments of proved producing properties were $20 million in 2014 as compared to impairments of proved producing properties and capitalized cost of acquired unproved reserves of $860 million in 2013 (see Note 4 of Notes to Consolidated Financial Statements).

Our 2013 operating results were $1.4 billion unfavorable as compared to 2012. The primary unfavorable impact includes $860 million recorded in the fourth quarter 2013 for impairments of producing properties and costs of acquired unproved reserves as compared to $123 million of impairments recorded in 2012. Also included in 2013 is a $317 million impairment of related leasehold costs (see Note 4 of Notes to Consolidated Financial Statements). Significant declines in the forward natural gas prices relative to the forward prices at December 31, 2012 and more notably in the fourth quarter 2013, especially the Appalachia index prices, were the primary factors for the impairments. Additional unfavorable impacts include the absence of $423 million of gains realized in 2012 on natural gas derivatives designated as hedges for accounting purposes, $202 million unfavorable change in derivatives not designated as hedges, $61 million related to lower domestic natural gas production volumes and $85 million related to lower domestic NGL production volumes. Operating results were favorably impacted by $181 million related to higher domestic realized natural gas prices (excluding hedges), $168 million from higher domestic oil production volumes and prices (excluding hedges), and $84 million lower gathering, processing and transportation costs.

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Outlook

In October 2014, we announced a strategy to simplify our geographic focus and expand returns, margins and cash flow over the next five years. Key to this strategy are the core resource plays in North Dakota, New Mexico and Colorado. As a result, we will look to exit or scale back activities in our other areas. We have made significant progress toward this goal as evidenced by the completion of sales of our international interests to Pluspetrol and our operations in northeast Pennsylvania, including the release of certain firm transportation capacity, to Southwestern Energy Company. An agreement signed in the third quarter of 2014 for the sale of our coalbed methane assets in Wyoming has been extended as certain items are renegotiated due to current market conditions.

While the significant declines in forward commodity prices, especially oil, is challenging to the oil and gas industry as evidenced by the reduced 2015 capital plans among our peers and reductions in workforces across the industry, we are committed to our long term strategy. However, we will remain flexible to adjust to market conditions and prudent in preserving the strength of our balance sheet. For 2015, approximately three-fourths of our expected natural gas production and two-thirds of our expected oil production were hedged at prices above the current market which provides some protection to the price downturn. Our 2015 capital program is expected to be approximately $725 million, in line with our projected cash flow. Our drilling will be greatly reduced in 2015 as we plan to primarily drill locations that preserve leases or optimize the drilling rigs already under contract in an effort to reduce the impact of rig release penalties while potentially deferring completions. Additionally, as we reduce our areas of focus, we have the opportunity to improve our cost structure and ensure that our organization is in alignment with growth objectives. We will continue to focus on lowering costs through reduced drilling times, efficient use of pad design and completion activities, and negotiating lower costs for vendor goods and services. Additionally, we continue to review our general and administrative costs and services.

In 2015, we will reduce our drilling activities in the Williston Basin in North Dakota and the Gallup Sandstone in the San Juan Basin in an effort to preserve those reserves for periods of higher oil prices. During 2014, we have added Gallup Sandstone acreage through acquisitions that brings the total we own or control to approximately 85,000 net acres. In 2015, we expect to spend $200 million to $225 million in the Williston Basin optimizing rigs already under contract ramping down to one rig by late spring for the balance of the year. We expect to spend $275 million to $300 million in the Gallup Sandstone, primarily preserving the leases and forming units. Despite the decrease in the capital expenditures in 2015, we are targeting a 15 to 20 percent growth in oil production.

We will also continue to focus our natural gas drilling effort in the Piceance Basin because of our scale and efficiency of that operation combined with significant infrastructure already in place. We expect to spend $200 million to $225 million in the Piceance Basin and plan to deploy an average of three and a half drilling rigs in the Piceance Basin for 2015, which includes drilling focused on the Niobrara Shale discussed below. Our drilling activity has primarily been focused in the Piceance Valley, however, we will start to shift more capital to opportunities in the Ryan Gulch field of the Piceance Basin where we have more than 4,000 drillable locations at 10-acre spacing.

A portion of our Piceance Basin estimated annual capital spending in 2015 will be for continued exploratory activities related to our Niobrara Shale discovery. Drilling thus far has validated the existence of a highly pressured continuous gas accumulation capable of producing pipeline-quality gas. However, as with most exploratory plays, our drilling and completion costs on initial wells have been higher relative to the reserves from these producing wells. As a result, we have recorded a $67 million impairment of the capitalized well costs. Future drilling will focus on driving down costs while optimizing completion techniques.

While market conditions are challenging for producers, opportunities may also arise that we will evaluate. Potential transactions to seize the opportunities may not serve to strengthen our balance sheet.

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 invest in and grow our production and reserves over the long-term;

• continuing to diversify our commodity portfolio through the development of our Williston Basin oil play position and Gallup Sandstone oil play and liquids-rich basins (primarily Piceance Basin) with high concentrations of NGLs;

• evaluating Niobrara Shale potential through drilling;

• continuing to pursue cost improvements and efficiency gains;

• employing new technology and operating methods;

• continuing to invest in exploration projects to add new development opportunities to our portfolio;

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

47

• 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;

• higher capital costs of developing our properties;

• lower than expected levels of cash flow from operations;

• lower than expected proceeds from asset sales;

• counterparty credit and performance risk;

• general economic, financial markets or industry downturn;

• 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;

• decreased drilling success; and

• unavailability of capital.

Changes in the forward prices will be considered as we proceed with our 2015 capital program. Additionally, if forecasted natural gas and oil prices were to decline we would need to review the producing properties net book value for possible impairment. See our discussion of impairment of long-lived assets in our critical accounting estimates discussion later in this section. 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 utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.

Commodity Price Risk Management

To manage the commodity price risk and volatility of owning producing gas and oil properties, we enter into derivative contracts for a portion of our future production (see Note 14 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. We have the following contracts as of February 25, 2015 for approximately three-fourths of our anticipated 2015 natural gas production and approximately two-thirds of our anticipated 2015 oil production, shown at weighted average volumes and basin-level weighted average prices:

Natural Gas	2015		2016
	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)
Fixed-price—Henry Hub	442	$4.10	280	$3.81
Swaptions—Henry Hub	—	$—	90	$4.23
Costless Collars—Henry Hub	50	$ 4.00 - $4.50	—	$—
Basis swaps—NGPL	17	$(0.18)	—	$—
Basis swaps—San Juan	99	$(0.11)	—	$—
Basis swaps—Rockies	214	$(0.16)	—	$—
Basis swaps—SoCal	20	$0.18	—	$—

Crude Oil	2015		2016
	Volume (Bbls/d)	Weighted Average Price ($/Bbl)	Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Fixed-price—WTI	20,236	$94.88	—	$—
Swaptions—WTI	882	$97.29	5,250	$97.55

Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. In conjunction with the closing of the Powder River sale and current terms therein, we may record certain pipeline capacity obligations associated with exiting the Powder River Basin. Our total commitments related to these pipeline agreements for 2015 and beyond total $172 million.

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Results of Operations

Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. Our development and production techniques specialize in production from tight-sands and shale formations primarily in the Piceance, Williston and San Juan Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.

2014 vs. 2013

Revenue Analysis

	Years ended December 31,					Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2014		2013
	(Millions)
Domestic revenues:
Natural gas sales	$	1,002	$	896		$	106		12	%
Oil and condensate sales	724		534			190			36	%
Natural gas liquid sales	205		228			(23		)	(10	)%
Total product revenues	1,931		1,658			273			16	%
Gas management	1,120		891			229			26	%
Net gain (loss) on derivatives not designated as hedges	434		(124		)	558			NM
Other	8		6			2			33	%
Total domestic revenues	$	3,493	$	2,431		$	1,062		44	%

__________

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

Domestic Revenues

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

• $106 million increase in natural gas sales primarily reflects $157 million related to higher natural gas prices partially offset by a $47 million decrease related to lower production sales volumes for 2014 compared to 2013. The decrease in our production sales volumes is primarily due to the impact of the sale of a portion of our working interests to Legacy during second-quarter 2014 (see Note 4 of Notes to Consolidated Financial Statements). Natural gas production from the Piceance Basin represents approximately 73 percent of our total domestic natural gas production. The following table reflects natural gas production prices and volumes for 2014 and 2013:

	Years ended December 31,
	2014			2013
Natural gas sales (per Mcf)(a)	$	3.57		$	3.03
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(b)	(0.10		)	(0.07		)
Natural gas net price including all derivative settlements (per Mcf)	$	3.47		$	2.96
Natural gas production sales volumes (MMcf)	280,386			295,934
Per day natural gas production sales volumes (MMcf/d)	768			811

__________

(a) Includes $0.02 per Mcf impact of net cash received on derivatives designated as hedges for 2013.

(b) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.

49

• $190 million increase in oil and condensate sales reflects a $300 million increase related to production sales volumes for 2014 compared to 2013 partially offset by a $110 million decrease related to lower sales prices. The increase in production sales volumes primarily relates to continued development drilling in the Williston Basin where the volumes were 19.5 MBbls per day for 2014 compared to 13.2 MBbls per day for 2013. The San Juan Basin also had production of 3.9 MBbls per day for 2014 related to the Gallup Sandstone development. The following table reflects oil and condensate production prices and volumes for 2014 and 2013:

	Years ended December 31,
	2014		2013
Oil sales (per barrel)	$	78.32	$	90.21
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	2.01		1.52
Oil net price including all derivative settlements (per barrel)	$	80.33	$	91.73
Oil and condensate production sales volumes (MBbls)	9,244		5,919
Per day oil and condensate production sales volumes (MBbls/d)	25.3		16.2

__________

(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.

• $23 million decrease in natural gas liquids sales reflects decreased production sales volumes despite a higher price per barrel for 2014 compared to 2013. The increased average barrel price for natural gas liquids partially reflects a change in the composition of the barrel, as noted in the table below, due to lower ethane recovery rates. The following table reflects natural gas liquid production prices and volumes for 2014 and 2013:

	Years ended December 31,
	2014		2013
NGL sales (per barrel)	$	32.79	$	30.72
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	1.12		0.08
NGL net price including all derivative settlements (per barrel)	$	33.91	$	30.80
NGL production sales volumes (MBbls)	6,250		7,415
Per day NGL production sales volumes (MBbls/d)	17.1		20.3

__________

(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.

The following table summarizes the composition of the Piceance NGL barrel for 2014 and 2013:

	Years ended December 31,
	2014				2013
	% of barrel		$/gallon		% of barrel		$/gallon
Ethane	29	%	$	0.28	39	%	$	0.25
Propane	33	%	$	1.05	29	%	$	0.98
Iso-Butane	10	%	$	1.25	8	%	$	1.41
Normal Butane	8	%	$	1.22	7	%	$	1.38
Natural Gasoline	20	%	$	1.99	17	%	$	2.11

• $229 million increase in gas management revenues primarily due to higher average prices on physical natural gas sales. The higher natural gas prices reflect the benefit of an increase in natural gas prices at sales points utilizing contracted pipeline capacity in the Northeast primarily during the first quarter of 2014. The increase in the sales

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price was greater than the increase in the purchase price as reflected in the $56 million increase in related gas management costs and expenses, discussed below.

• $558 million favorable change in net gain (loss) on derivatives not designated as hedges primarily reflects a $565 million favorable change in unrealized gains (losses) on derivatives related to production, primarily natural gas and crude, and $100 million favorable change in the unrealized portion of gas management derivatives. Our net derivative assets as of December 31, 2014 were $494 million, of which 93 percent is expected to be recognized in the next 12 months. The favorable changes are partially offset by a $120 million of realized losses in 2014 on gas management derivatives.

Cost and operating expense and operating income (loss) analysis:

	Years ended December 31,					Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2014		2013
	(Millions)
Domestic costs and expenses:
Lease and facility operating	$	244	$	227		$	(17	)	(7	)%
Gathering, processing and transportation	328		350			22			6	%
Taxes other than income	126		102			(24		)	(24	)%
Gas management, including charges for unutilized pipeline capacity	987		931			(56		)	(6	)%
Exploration	173		423			250			59	%
Depreciation, depletion and amortization	810		858			48			6	%
Impairment of producing properties and costs of acquired unproved reserves	20		860			840			98	%
Loss on sale of working interests in the Piceance Basin	196		—			(196		)	NM
General and administrative	271		269			(2		)	(1	)%
Other—net	12		12			—			—	%
Total domestic costs and expenses	$	3,167	$	4,032		$	865		21	%
Domestic operating income (loss)	$	326	$	(1,601	)	$	1,927		NM

__________

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

Domestic Costs

Significant components on our domestic costs and expenses are comprised of the following:

• $17 million increase in lease and facility operating expenses primarily relates to the impact of increased oil production in the Williston and San Juan Basins in relation to our overall portfolio. Lease and facility operating expense in 2014 averaged $0.65 per Mcfe compared to $0.60 per Mcfe during 2013.

• $22 million decrease in gathering, processing and transportation expenses primarily related to lower volumes and approximately $5 million recognized during 2014 related to a tariff rate refund received in prior years which is no longer under appeal by the pipeline company. Also included in gathering, processing and transportation expenses are $13 million and $12 million in 2014 and 2013, respectively, of excess gathering capacity expense. Gathering, processing and transportation charges averaged $0.88 per Mcfe for 2014 and $0.93 per Mcfe for 2013. Excluding the impact of the refund, the gathering, processing and transportation expenses would have averaged $0.89 per Mcfe for 2014.

• $24 million increase in taxes other than income primarily relates to increased oil production volumes and higher natural gas prices. Our taxes other than income averaged $0.34 per Mcfe for 2014 compared to an average of $0.27 per Mcfe for 2013.

• $56 million increase in gas management expenses, primarily due to higher average prices on physical natural gas cost of sales. Additionally, in 2014 we recognized a loss of approximately $14 million on the release of future storage capacity commitments and approximately $4 million loss on the sale of related natural gas in storage partially offset by $11 million related to a tariff rate refund received in prior years which is no longer under appeal by the pipeline company. Also included in gas management expenses are $57 million and $61 million in 2014 and

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2013, respectively, for unutilized pipeline capacity. Gas management expenses in 2013 also included $9 million related to the buyout of a transportation contract.

• $250 million decrease in exploration expenses primarily reflects lower unproved leasehold impairment, amortization and expiration expenses in 2014 compared to 2013. The unproved leasehold impairment in 2014 includes $41 million of impairments for unproved leasehold costs in exploratory areas where the company no longer intends to continue exploration activities, while 2013 includes a $317 million impairment to fair value of leasehold in the Appalachian Basin. The decrease in unproved leasehold impairment, amortization and expiration expenses was partially offset by a $67 million impairment related to our Niobrara Shale in the Piceance Basin and $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities (see Note 4 of Notes to Consolidated Financial Statements).

• $48 million decrease in depreciation, depletion and amortization expenses primarily due to the previously discussed lower natural gas production volumes and the impact of impairments taken in 2013 in the Appalachian Basin partially offset by the increase in oil production. During 2014, our depreciation, depletion and amortization averaged $2.17 per Mcfe compared to an average $2.28 per Mcfe in 2013.

• $20 million of property impairments in 2014 compared to $860 million in 2013 (see Note 4 of Notes to Consolidated Financial Statements).

• $196 million loss on the sale of a portion of our working interests in certain Piceance Basin wells (see Note 4 of Notes to Consolidated Financial Statements).

• General and administrative expenses were relatively flat in 2014 compared to 2013. Included in 2014 is $10 million related to a voluntary early exit program.

• Other expenses include rig release and standby fees of $16 million and $12 million for 2014 and 2013, respectively.

Consolidated results below operating income (loss)

	Years ended December 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2014			2013
	(Millions)
Consolidated operating income (loss)	$	326		$	(1,601	)	$	1,927		NM
Interest expense	(123		)	(108		)	(15		)	(14	)%
Investment income, impairment of equity method investment and other	1			(19		)	20			NM
Income (loss) from continuing operations before income taxes	204			(1,728		)	1,932			NM
Provision (benefit) for income taxes	75			(624		)	(699		)	NM
Income (loss) from continuing operations	129			(1,104		)	1,233			NM
Income (loss) from discontinued operations	42			(87		)	129			NM
Net income (loss)	171			(1,191		)	1,362			NM
Less: Net income (loss) attributable to noncontrolling interests	7			(6		)	13			NM
Net income (loss) attributable to WPX Energy, Inc.	$	164		$	(1,185	)	$	1,349		NM

__________

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 a higher amount outstanding on our revolver during 2014 compared to 2013 and the $500 million of notes issued in the third quarter of 2014.

Our investment income, impairment of equity method investment and other in 2013 includes a $20 million impairment related to an equity method investment in the Appalachian Basin.

The provision (benefit) for income taxes changed unfavorably due to income from continuing operations before income taxes in 2014 compared to a loss from continuing operations before income taxes in 2013. 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 includes the results of operations from Powder River Basin and our international segment (see Note 2 of Notes to Consolidated Financial Statements).

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2013 vs. 2012

Revenue Analysis

	Years ended December 31,					Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2013			2012
	(Millions)
Domestic revenues:
Natural gas sales	$	896		$	1,193	$	(297	)	(25	)%
Oil and condensate sales	534			376		158			42	%
Natural gas liquid sales	228			297		(69		)	(23	)%
Total product revenues	1,658			1,866		(208		)	(11	)%
Gas management	891			949		(58		)	(6	)%
Net gain (loss) on derivatives not designated as hedges	(124		)	78		(202		)	NM
Other	6			7		(1		)	(14	)%
Total domestic revenues	$	2,431		$	2,900	$	(469	)	(16	)%

_ ________

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

Domestic Revenues

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

• $297 million decrease in natural gas sales primarily due to the absence of $423 million of realized gains in 2012 from derivatives designated as hedges and $61 million related to lower production sales volumes partially offset by $181 million related to higher sales prices (excluding hedges). The Company no longer designated derivatives entered into after December 31, 2011 as hedges for accounting purposes. The decrease in our production sales volumes is due in part to our disciplined development of natural gas reserves in a low natural gas price environment. However, natural gas production in the Appalachian Basin increased over prior year. Natural gas production from the Piceance Basin represented approximately 74 percent of our total domestic natural gas production in 2013. The following table reflects natural gas production prices and volumes for 2013 and 2012:

	Years ended December 31,
	2013			2012
Natural gas sales excluding all derivative settlements (per Mcf)	$	3.01		$	2.40
Impact of hedges (per Mcf)	0.02			1.32
Natural gas sales including hedges (per Mcf)	$	3.03		$	3.72
Impact of net cash received (paid) related to settlement of derivatives not designated as hedges (per Mcf)(a)	(0.07		)	0.04
Natural gas net price including all derivative settlements (per Mcf)	$	2.96		$	3.76
Natural gas production sales volumes (MMcf)	295,934			321,162
Per day natural gas production sales volumes (MMcf/d)	811			878

__________

(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.

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• $158 million increase in oil and condensate sales reflects increased production sales volumes as well as a higher price per barrel (including the impact of hedges in 2012) for2013 compared to 2012. The increase in production sales volumes primarily relates to increased production in the Williston Basin where the per day volumes were 13.2 MBbls per day for 2013 compared to 9.5 MBbls per day for 2012. The San Juan Basin also had production of 0.8 MBbls per day for 2013. The following table reflects oil and condensate production prices and volumes for 2013 and 2012:

	Years ended December 31,
	2013		2012
Oil sales excluding all derivative settlements (per barrel)	$	90.21	$	83.34
Impact of hedges (per barrel)	—		2.23
Oil sales including hedges (per barrel)	$	90.21	$	85.57
Impact of net cash received (paid) related to settlement of derivatives not designated as hedges (per barrel)(a)	1.52		0.35
Oil net price including all derivative settlements (per barrel)	$	91.73	$	85.92
Oil and condensate production sales volumes (MBbls)	5,919		4,394
Per day oil and condensate production sales volumes (MBbls/d)	16.2		12.0

__________

(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.

• $69 million decrease in natural gas liquids sales reflects decreased production sales volumes for 2013 compared to 2012, a portion of which relates to lower ethane recovery rates as a result of ethane prices in the Piceance Basin during 2013. The increased average per barrel price for natural gas liquids reflects a change in the composition of the barrel, as noted in the table below, due to lower ethane recovery rates. The following table reflects NGL production prices and volumes for 2013 and 2012:

	Years ended December 31,
	2013		2012
NGL sales excluding all derivative settlements (per barrel)	$	30.72	$	28.56
Impact of net cash received (paid) related to settlement of derivatives not designated as hedges (per barrel)(a)	0.08		1.56
NGL net price including all derivative settlements (per barrel)	$	30.80	$	30.12
NGL production sales volumes (MBbls)	7,415		10,392
Per day NGL production sales volumes (MBbls/d)	20.3		28.4

__________

(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.

The following table summarizes the composition of the Piceance NGL barrel for 2013 and 2012:

	Years ended December 31,
	2013				2012
	% of barrel		$/gallon		% of barrel		$/gallon
Ethane	39	%	$	0.25	56	%	$	0.41
Propane	29	%	$	0.98	21	%	$	1.00
Iso-Butane	8	%	$	1.41	6	%	$	1.80
Normal Butane	7	%	$	1.38	5	%	$	1.65
Natural Gasoline	17	%	$	2.11	12	%	$	2.14

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• $58 million decrease in gas management revenues is primarily due to lower commodity sales volumes partially offset by an increase in average prices on physical natural gas sales. We experienced a similar decrease of $65 million in related gas management costs and expenses.

• $202 million change in net gain (loss) on derivatives not designated as hedges reflects both unrealized and realized losses on derivatives for 2013. The change in the unrealized loss for 2013 primarily relates to crude and natural gas derivatives as well as natural gas transportation hedges. The net change in the realized loss in 2013 primarily related to natural gas and NGL derivatives.

Cost and operating expense and operating income (loss) analysis:

	Years ended December 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2013			2012
	(Millions)
Domestic costs and expenses:
Lease and facility operating	$	227		$	202		$	(25	)	(12	)%
Gathering, processing and transportation	350			434			84			19	%
Taxes other than income	102			68			(34		)	(50	)%
Gas management, including charges for unutilized pipeline capacity	931			996			65			7	%
Exploration	423			71			(352		)	NM
Depreciation, depletion and amortization	858			884			26			3	%
Impairment of producing properties and costs of acquired unproved reserves	860			123			(737		)	NM
General and administrative	269			265			(4		)	(2	)%
Other—net	12			14			2			14	%
Total domestic costs and expenses	$	4,032		$	3,057		$	(975	)	(32	)%
Domestic operating income (loss)	$	(1,601	)	$	(157	)	$	(1,444	)	NM

__________

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

Domestic Costs

Significant components on our domestic costs and expenses are comprised of the following:

• $25 million increase in lease and facility operating expense primarily relates to increased water disposal costs due in part to decreased drilling in the Appalachian Basin and the corresponding utilization of produced water in the well hydraulic fracturing process. Additionally, increased Williston Basin production in relation to our overall portfolio impacted the increase in lease and facility operating expense. Lease and facility operating expense averaged $0.60 per Mcfe for2013 compared to $0.49 per Mcfe in 2012.

• $84 million decrease in gathering, processing and transportation charges primarily related to new favorable contract terms for gathering and processing services in the Piceance Basin as well as lower volumes. Gathering, processing and transportation expenses averaged $0.93 per Mcfe compared to $1.06 per Mcfe for 2013 and 2012, respectively. Gathering, processing and transportation for 2012 includes a $9 million adjustment related to royalty calculations for prior periods. Excluding this adjustment, gathering, processing and transportation expenses would have averaged $1.04 per Mcfe for 2012.

• $34 million increase in taxes other than income from 2013 compared to 2012 relates to the increase in natural gas prices (excluding derivatives), increased crude oil production volumes and higher crude oil prices. Taxes other than income averaged $0.27 per Mcfe for 2013 compared to $0.17 per Mcfe for 2012.

• $65 million decrease in gas management expenses reflect the lower commodity purchase volumes partially offset by an increase in average prices on physical natural gas cost of sales. Also included in gas management expenses are $61 million and $46 million for2013 and 2012, respectively, for unutilized pipeline capacity. Gas management expenses for the periods ended December 31, 2013 and 2012 included $1 million and $11 million, respectively, related to lower of cost or market charges to the carrying value of natural gas inventories in storage and 2013 includes $9 million related to the buyout of a transportation agreement.

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• $352 million higher exploration expense primarily relates to a $317 million impairment to fair value of leasehold in the Appalachian Basin in 2013 as well as higher leasehold amortization expense.

• $26 million decrease in depreciation, depletion and amortization primarily due to lower production volumes in 2013 compared to 2012. Also during 2013, we adjusted our proved reserves used for the calculation of depletion and amortization which resulted in a net $11 million reduction of depreciation, depletion and amortization expense for 2013. These adjustments primarily reflect the impact of an increase in the 12-month average price partially offset by reduced NGL reserves due to continued lower ethane recovery. During 2013, our depreciation, depletion and amortization averaged $2.28 per Mcfe compared to an average $2.16 per Mcfe in 2012. This increase partially reflects the growth of the Williston Basin as part of our portfolio.

• $860 million in 2013 of impairments of producing properties and cost of acquired unproved reserves compared to $123 million for 2012, as previously discussed (see Note 4 of Notes to Consolidated Financial Statements).

• $4 million higher general and administrative expense is primarily due to $4 million of costs associated with the separation of our chief executive officer in 2013. General and administrative expense averaged $0.71 per Mcfe compared to $0.65 per Mcfe for 2013 and 2012, respectively.

• Other expenses include rig release and standby fees of $12 million and $9 million for 2013 and 2012, respectively.

Consolidated results below operating income (loss)

	Years ended December 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2013			2012
	(Millions)
Consolidated operating income (loss)	$	(1,601	)	$	(157	)	$	(1,444	)	NM
Interest expense	(108		)	(102		)	(6		)	(6	)%
Investment income, impairment of equity method investment and other	(19		)	1			(20		)	NM
Income (loss) from continuing operations before income taxes	(1,728		)	(258		)	(1,470		)	NM
Provision (benefit) for income taxes	(624		)	(84		)	540			NM
Income (loss) from continuing operations	(1,104		)	(174		)	(930		)	NM
Income (loss) from discontinued operations	(87		)	(37		)	(50		)	(135	)%
Net income (loss)	(1,191		)	(211		)	(980		)	NM
Less: Net income (loss) attributable to noncontrolling interests	(6		)	12			(18		)	NM
Net income (loss) attributable to WPX Energy, Inc.	$	(1,185	)	$	(223	)	$	(962	)	NM

__________

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 a higher amount outstanding on our revolver in 2013.

Our investment income, impairment of equity method investment and other primarily reflects equity earnings associated with our equity method investments. In addition, 2013 includes a $20 million impairment related to an equity method investment in the Appalachian Basin. This impairment was a result of the 2013 impairment of the producing properties in the Appalachian Basin (see Note 4 of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed favorably primarily due to a greater loss from continuing operations before income taxes for 2013 compared to 2012. 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 includes the results of operations from Powder River Basin and our international segment (see Note 2 of Notes to Consolidated Financial Statements).

The change in net income (loss) attributable to noncontrolling interests is primarily due to $11 million associated with the impairment of a certain Appalachian Basin facility asset.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview and Liquidity

In 2014, we continued to focus upon growth through continued disciplined investments in expanding our natural gas, oil and NGL portfolio.

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 bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. In consideration of our liquidity, we note the following:

• As of December 31, 2014, we maintained liquidity through cash, cash equivalents and available credit capacity under our credit facility.

• 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 2015 are expected cash flows from operations, proceeds from monetization of assets, and, if necessary, additional borrowings on our $1.5 billion credit facility. We anticipate that the combination of these sources will be sufficient to allow us to pursue our business strategy and goals for 2015.

We note the following assumptions for 2015:

• our cash capital expenditures are estimated to be approximately $875 million in 2015 and exceeds the previously mentioned $725 million of capital expenditures due to costs incurred in 2014 that will be paid in 2015. The new spending is generally considered to be largely discretionary; and

• We have hedged approximately three-fourths of our anticipated 2015 natural gas production at a weighted average price of $4.10 per MMbtu, and approximately two-thirds of anticipated 2015 oil production at a weighted average price of $94.88 per barrel.

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

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

• lower than expected proceeds from asset sales;

• higher than expected collateral obligations that may be required, including those required under new commercial agreements;

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

• reduced access to our credit facility.

In October 2014, we amended and restated our $1.5 billion five-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lender party thereto (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility Agreement matures on October 28, 2019. As of December 31, 2014, the weighted average variable interest rate was 3.01 percent on the $280 million outstanding under the Credit Facility Agreement. As of February 25, 2015, we did not have any outstanding borrowings under the Credit Facility Agreement as proceeds from asset sales were used to repay all outstanding amounts. See Note 7 of Notes to Consolidated Financial Statements for discussion of significant terms related to the Credit Facility Agreement. The financial covenants in the Credit Facility Agreement that are described below may limit our ability to borrow money, depending on the applicable financial metrics at any given time.

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Under the Credit Facility Agreement when our long-term unsercured debt rating is not BBB- or better by S&P or Baa3 or better by Moody’s and not less than BB+ by S&P or Ba1 by Moody's, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the Credit Facility Agreement) to Consolidated EBITDAX (as defined in the Credit Facility Agreement) of not greater than 3.75 to 1.00. Consolidated Net Indebtedness includes a reduction attributable to unrestricted cash and cash equivalents not to exceed $50 million. Consolidated EBITDAX will be calculated for the four fiscal quarters ending on the last day of any fiscal quarter for which financial statements have been or were required to be delivered. Additionally, the ratio of Consolidated Indebtedness (defined as Indebtedness of us and our consolidated subsidiaries determined on a consolidated basis) to Consolidated Total Capitalization (defined as Consolidated Indebtedness plus Consolidated Net Worth) will not be permitted to be greater than 60 percent and will be applicable for the life of the agreement.

When our long-term unsecured debt rating is BB or worse by S&P and Ba2 or worse by Moody’s or BB- or worse by S&P or Ba3 or worse by Moody’s, we will also be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the Credit Facility Agreement, to Consolidated Indebtedness ratio of at least 1.25 to 1.00 for fiscal periods ending on or prior to December 31, 2015, and 1.50 to 1.00 for fiscal periods ending after December 31, 2015. Based on our current long-term unsecured debt ratings, as of the date of this filing, we are not required to comply with this covenant. In addition, this covenant will not apply at any time after the occurrence of the Investment Grade Date, which is the first date after closing on which our long-term unsecured debt is rated BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or watch by either agency), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.

We have executed three bilateral, uncommitted letter of credit agreements which we anticipate will be renewed annually. These agreements allow us to preserve our liquidity under our revolving credit agreement 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 Agreement. At December 31, 2014, a total of $320 million in letters of credit have been issued.

Credit Ratings

Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analysis when assigning credit ratings. A downgrade of our current rating could increase our future cost of borrowing and result in a requirement that we post additional collateral with third parties, thereby negatively affecting our available liquidity. The current ratings are as follows:

Standard and Poor’s(a)
Corporate Credit Rating	BB
Senior Unsecured Debt Rating	BB
Outlook	Stable
Moody’s Investors Service(b)
Senior Unsecured Debt Rating	Ba1
LT Corporate Family Rating	Ba1
Outlook	Stable

__________

(a) A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

(b) A rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1,” “2,” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates the lower end of the category.

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Sources (Uses) of Cash

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Net cash provided (used) by:
Operating activities	$	1,070		$	636		$	796
Investing activities	(1,437		)	(1,111		)	(1,204		)
Financing activities	344			426			37
Increase (decrease) in cash and cash equivalents	$	(23	)	$	(49	)	$	(371	)

Operating activities

Our net cash provided by operating activities in 2014 increased from 2013 primarily due to higher operating results driven by higher average natural gas prices and increased oil production volumes. In addition, 2014 increased due to higher net gas management revenues and expenses as previously discussed.

Our net cash provided by operating activities in 2013 decreased from 2012 primarily due to the decrease in our operating results driven by lower natural gas (including the impact of hedges) and NGL sales revenues.

Total cash provided by operating activities related to discontinued operations was approximately $130 million, $92 million and $68 million for 2014, 2013 and 2012, respectively.

Investing activities

Significant items include expenditures for drilling and completion of approximately $1.4 billion, $1.0 billion and $1.2 billion in 2014, 2013 and 2012, respectively. Domestic land acquisitions were $297 million, $61 million and $107 million during 2014, 2013 and 2012, respectively. Included in land acquisitions for 2014 was approximately $150 million related to the purchase of oil and natural gas properties in the San Juan Basin (see Note 5 of Notes to Consolidated Financial Statements). In addition, capital expenditures for international operations were $85 million, $51 million and $59 million during 2014, 2013 and 2012, respectively.

During 2014, we received proceeds of $337 million for the sale of a portion of our working interests in certain Piceance Basin wells to Legacy (see Note 4 of Notes to Consolidated Financial Statements). In addition, we also received proceeds of approximately $50 million related to the sale of a portion of our working interests in the Piceance Basin as part of an agreement to farmout a portion of our Trail Ridge properties with TRDC, LLC, a subsidiary of G2X Energy (see Note 5 of Notes to Consolidated Financial Statements).

During 2013, we received proceeds of $36 million from the sale of deep rights leasehold in the Powder River Basin and in 2012 we received proceeds of $306 million from the sale of our holdings in the Barnett Shale and Arkoma Basin.

Financing activities

During 2014, we issued $500 million of senior unsecured notes at an interest rate of 5.25 percent. We used the proceeds from this offering to repay borrowings under our revolving credit facility and for related transaction fees and expenses (see Note 7 of Notes to Consolidated Financial Statements). Net cash provided by financing activities in 2014 includes $130 million of net payments on our credit facility.

Net cash provided by financing activities in 2013 includes $410 million net borrowings on our credit facility.

Net cash provided by financing activities in 2012 includes $10 million of a contribution from a third party related to the formation of a consolidated limited liability company. This company was formed to hold gathering facilities.

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 December 31, 2014 and December 31, 2013.

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Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2014.

	2015		2016 – 2017		2018 – 2019		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal	$	1	$	400	$	280	$	1,600	$	2,281
Interest	122		233		200		296		851
Operating leases and associated service commitments:
Drilling rig commitments(a)	79		34		—		—		113
Other	10		17		13		16		56
Transportation and storage commitments(b)	177		311		264		389		1,141
Oil and gas activities(c)	106		128		66		60		360
Other	11		10		7		—		28
Other long-term liabilities, including current portion:
Physical and financial derivatives(d)	227		501		483		1,068		2,279
Total continuing operations	733		1,634		1,313		3,429		7,109
Obligations related to discontinued operations (e)	27		43		22		22		114
Obligations related to assets held for sale (f)	30		48		13		—		91
Total obligations	$	790	$	1,725	$	1,348	$	3,451	$	7,314

__________

(a) Includes materials and services obligations associated with our drilling rig contracts.

(b) Excludes additional commitments totaling $39 million associated with projects for which the counterparty has not yet begun construction.

(c) Includes gathering, processing and other oil and gas related services commitments. Excluded are liabilities associated with asset retirement obligations, which total $201 million as of December 31, 2014. The ultimate settlement and timing cannot be precisely determined in advance; however, we estimate that approximately 6 percent of this liability will be settled in the next five years.

(d) Includes $2.3 billion of physical natural gas derivatives related to purchases at market prices. The natural gas expected to be purchased under these contracts can be sold at market prices, largely offsetting this obligation. The obligations for physical and financial derivatives are based on market information as of December 31, 2014, and assume contracts remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur.

(e) Represents obligation assumed by or anticipated to be assumed by the purchaser. Excluded are liabilities associated with asset retirement obligations totaling $55 million as of December 31, 2014.

(f) Represents obligation assumed by or anticipated to be assumed by the purchaser. Excluded are liabilities associated with asset retirement obligations totaling $2 million as of December 31, 2014.

Effects of Inflation

Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Operating costs are influenced by both competition for specialized services and specific price changes in natural gas, oil, NGLs and other commodities. We tend to experience inflationary pressure on the cost of services and equipment when higher oil and gas prices cause an increase in drilling activity in our areas of operation. Likewise, lower prices and reduced drilling activity may lower the costs of services and equipment.

Environmental

Our operations are subject to governmental laws and regulations relating to the protection of the environment, and increasingly strict laws, regulations and enforcement policies, as well as future additional environmental requirements, could materially increase our costs of operation, compliance and any remediation that may become necessary.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and

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the disclosure of contingent assets and liabilities. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are as follows:

Impairments of Long-Lived Assets

We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that include estimates of the undiscounted future cash flows, discounted future cash flows, estimated fair value of the asset, and the current and future economic environment in which the asset is operated.

Due to the drop in oil, natural gas and natural gas liquids forward prices during 2014 and most significantly in the fourth quarter, we assessed our proved properties for impairment using estimates of future cash flows. Significant judgments and assumptions are inherent in these assessments and include estimates of reserves quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), drilling plans, expected capital and lease operating costs and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates. The assessment performed identified certain properties with a carrying value in excess of those undiscounted cash flows and their calculated fair values. As a result, we recognized approximately $20 million of impairment charges in 2014. See Notes 4 and 13 of Notes to Consolidated Financial Statements for additional discussion and significant inputs into the fair value determination.

In addition to those long-lived assets described above for which impairment charges were recorded, certain others were reviewed for which no impairment was required at the time. These reviews included $3.8 billion of net book value associated with our predominantly natural gas proved properties and $2.7 billion of net book value associated with our predominantly oil proved properties, and utilized inputs generally consistent with those described above. Many judgments and assumptions are inherent and to some extent interdependent of one another in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. If the estimated revenues (only one of the many estimates involved) of the proved oil and gas properties reviewed but for which impairment charges were not recorded were lower by 8 to 10 percent, these properties could be at risk for impairment. Over 65 percent of our future production is in years 2020 and beyond.

Accounting for Derivative Instruments and Hedging Activities

Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges for accounting purposes. Most of our commodity derivative contracts entered into after 2011 continue to serve as economic hedges but are not designated as hedges for accounting purposes as we have elected not to utilize hedge accounting on new derivative instruments. Changes in the fair value of non-hedge derivative instruments, hereafter referred to as economic hedges, are recognized as gains or losses in the earnings of the periods in which they occur, accordingly we believe this will result in future earnings that are more volatile. The unrealized changes in fair value of cash flow hedge derivatives recorded in accumulated other comprehensive income at December 31, 2012 were realized at the end of the first-quarter 2013.

We review our energy contracts to determine whether they are, or contain, derivatives. Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short-term, with more than 93 percent of the value of our derivatives portfolio expiring in the next 12 months. We further assess the appropriate accounting method for any derivatives identified, which could include:

• applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings;

• qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or

• qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings for derivatives entered into prior to 2012.

If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the accounting method involves significant judgments and assumptions, which are further described below.

The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assessed whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal

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and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur and the quantity of the forecasted transaction. In addition, we compared actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.

For derivatives designated as cash flow hedges, we must periodically assess whether they continue to qualify for hedge accounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we reclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.

Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.

Since our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivatives, as generally depicted below:

	Consolidated Statements of Operations		Consolidated Balance Sheets
Accounting Method	Drivers	Impact	Drivers	Impact
Accrual Accounting	Realizations	Less Volatility	None	No Impact
Cash Flow Hedge Accounting	Realizations & Ineffectiveness	Less Volatility	Fair Value Changes	More Volatility
Mark-to-Market Accounting	Fair Value Changes	More Volatility	Fair Value Changes	More Volatility

Our determination of the accounting method does not impact our cash flows related to derivatives.

Additional discussion of the accounting for energy contracts at fair value is included in Notes 1 and 14 of Notes to Consolidated Financial Statements.

Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities

We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:

• an increase (decrease) in estimated proved natural gas, oil and NGL reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and

• changes in natural gas, oil and NGL reserves and forward market prices both impact projected future cash flows from our properties. This, in turn, can impact our periodic impairment analyses.

The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, over 88 percent of our domestic reserves estimates are audited by independent experts. The data may change substantially over time as a result of numerous factors, including the historical 12 month weighted average price, additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserves estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion

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and amortization expense between approximately $72 million and $87 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserves categories.

Estimates of future commodity prices, which are utilized in our impairment analyses, consider market information including published forward oil and natural gas prices. The forecasted price information used in our impairment analyses is consistent with that generally used in evaluating our drilling decisions and acquisition plans. Prices for future periods impact the production economics underlying oil and gas reserve estimates. In addition, changes in the price of natural gas and oil also impact certain costs associated with our underlying production and future capital costs. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil and gas properties.

We record the cost of leasehold acquisitions as incurred. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. Changes in our assumptions regarding the estimates of the nonproductive portion of these leasehold acquisitions could result in impairment of these costs. Upon determination that specific acreage will not be developed, the costs associated with that acreage would be impaired. Additionally, our leasehold costs are evaluated for impairment if the proved property costs in the basin are impaired. Our capitalized lease acquisition costs totaled $332 million at December 31, 2014.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including royalty litigation, environmental and other contingent matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 9 of Notes to Consolidated Financial Statements.

Valuation of Deferred Tax Assets and Liabilities

We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. Included in our deferred taxes are deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of book basis, from certain separate state losses generated in the current and prior years and from alternative minimum tax credits. We must periodically evaluate whether it is more likely than not we will realize these deferred tax assets and establish a valuation allowance for those that do not meet the more likely than not threshold. When assessing the need for a valuation allowance, we consider future reversals of existing taxable temporary differences, future taxable income exclusive of reversing temporary differences and carryforwards, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryforwards. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.

The determination of our state deferred tax requires judgment as our effective state deferred tax rate can change periodically based on changes in our operations. Our effective state deferred tax rate is based upon our current entity structure and the jurisdictions in which we operate.

See Note 8 of Notes to Consolidated Financial Statements for additional information.

Fair Value Measurements

A limited amount of our energy derivative assets and liabilities trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.

The determination of fair value for our energy derivative 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

63

arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities, we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2014, the credit reserve is less than $1 million on our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.

At December 31, 2014, 93 percent of the fair value of our derivatives portfolio expires in the next 12 months and 100 percent expires in the next 24 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.

The instruments included in Level 3 at December 31, 2014, consist of natural gas index transactions that are used to manage the physical requirements of our business. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices during the month of delivery. There are generally no active forward markets or quoted prices for natural gas index transactions.

For the years ended December 31, 2014, 2013 and 2012, we recognized impairments of certain assets that were measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. See Note 13 of Notes to Consolidated Financial Statements.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our interest rate risk exposure is related primarily to our debt portfolio. Our senior notes are fixed rate debt in order to mitigate the impact of fluctuations in interest rates. For our fixed rate debt, $400 million matures in 2017, $1,100 million matures in 2022 and $500 million matures in 2024. Interest rates for each group are 5.25 percent, 6.00 percent and 5.25 percent, respectively. The aggregate fair value of the senior notes is $1,938 million. Borrowings under our credit facility are based on a variable interest rate and could expose us to the risk of increasing interest rates. As of December 31, 2014, the weighted average variable interest rate was 3.01 percent on the $280 million outstanding under the Credit Facility Agreement. See Note 7 of Notes to Consolidated Financial Statements.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of natural gas, oil and NGLs, 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 13 and 14 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 a net asset of $1 million at December 31, 2014 and a net liability of $1 million at December 31, 2013. The value at risk for contracts held for trading purposes was less than $1 million at December 31, 2014 and December 31, 2013.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our natural gas purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $493 million at December 31, 2014 and a net liability of $64 million at December 31, 2013.

The value at risk for derivative contracts held for nontrading purposes was $16 million at December 31, 2014, and $19 million at December 31, 2013. During the year ended December 31, 2014, our value at risk for these contracts ranged from a high of $19 million to a low of $16 million. The decrease in value at risk from December 31, 2013 primarily reflects decreases in market prices on contracts entered into to hedge our equity production.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a—15(f) and 15d—15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2014, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on our assessment, we concluded that, as of December 31, 2014, our internal control over financial reporting was effective.

Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.

66

Report of Independent Registered Public Accounting Firm on

Internal Control over Financial Reporting

The Board of Directors and Shareholders of WPX Energy, Inc.,

We have audited WPX Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). WPX Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, WPX Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of WPX Energy Inc. as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2014 of WPX Energy, Inc. and our report dated February 26, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2015            

67

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of WPX Energy, Inc.,

We have audited the accompanying consolidated balance sheets of WPX Energy, Inc. as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15.(a).These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of WPX Energy, Inc. at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), WPX Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2015                

68

WPX Energy, Inc.

Consolidated Balance Sheets

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

See accompanying notes.

69

WPX Energy, Inc.

Consolidated Statements of Operations

	Years Ended December 31,
	2014			2013			2012
Revenues:	(Millions, except per share amounts)
Product revenues:
Natural gas sales	$	1,002		$	896		$	1,193
Oil and condensate sales	724			534			376
Natural gas liquid sales	205			228			297
Total product revenues	1,931			1,658			1,866
Gas management	1,120			891			949
Net gain (loss) on derivatives not designated as hedges (Note 14)	434			(124		)	78
Other	8			6			7
Total revenues	3,493			2,431			2,900
Costs and expenses:
Lease and facility operating	244			227			202
Gathering, processing and transportation	328			350			434
Taxes other than income	126			102			68
Gas management, including charges for unutilized pipeline capacity	987			931			996
Exploration (Note 4)	173			423			71
Depreciation, depletion and amortization	810			858			884
Impairment of producing properties and costs of acquired unproved reserves (Note 4)	20			860			123
Loss on sale of working interests in the Piceance Basin (Note 4)	196			—			—
General and administrative	271			269			265
Other—net	12			12			14
Total costs and expenses	3,167			4,032			3,057
Operating income (loss)	326			(1,601		)	(157		)
Interest expense	(123		)	(108		)	(102		)
Investment income, impairment of equity method investment and other	1			(19		)	1
Income (loss) from continuing operations before income taxes	204			(1,728		)	(258		)
Provision (benefit) for income taxes	75			(624		)	(84		)
Income (loss) from continuing operations	129			(1,104		)	(174		)
Income (loss) from discontinued operations	42			(87		)	(37		)
Net income (loss)	171			(1,191		)	(211		)
Less: Net income (loss) attributable to noncontrolling interests	7			(6		)	12
Net income (loss) attributable to WPX Energy, Inc.	$	164		$	(1,185	)	$	(223	)
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	129		$	(1,092	)	$	(174	)
Income (loss) from discontinued operations	35			(93		)	(49		)
Net income (loss)	$	164		$	(1,185	)	$	(223	)
Basic earnings (loss) per common share (Note 3):
Income (loss) from continuing operations	$	0.63		$	(5.45	)	$	(0.87	)
Income (loss) from discontinued operations	0.18			(0.46		)	(0.25		)
Net income (loss)	$	0.81		$	(5.91	)	$	(1.12	)
Weighted-average shares (millions)	202.7			200.5			198.8
Diluted earnings (loss) per common share (Note 3):
Income (loss) from continuing operations	$	0.62		$	(5.45	)	$	(0.87	)
Income (loss) from discontinued operations	0.18			(0.46		)	(0.25		)
Net income (loss)	$	0.80		$	(5.91	)	$	(1.12	)
Weighted-average shares (millions)	206.3			200.5			198.8

See accompanying notes.

70

WPX Energy, Inc.

Consolidated Statements of Comprehensive Income (Loss)

	Years Ended December 31,
	2014		2013			2012
	(Millions)
Net income (loss) attributable to WPX Energy, Inc.	$	164	$	(1,185	)	$	(223	)
Other comprehensive income (loss):
Change in fair value of cash flow hedges, net of tax(a)	$	—	$	—		$	57
Net reclassifications into earnings of net cash flow hedge gains, net of tax(b)	—		(3		)	(274		)
Other comprehensive income (loss), net of tax	—		(3		)	(217		)
Comprehensive income (loss) attributable to WPX Energy, Inc.	$	164	$	(1,188	)	$	(440	)

__________

(a) Change in fair value of cash flow hedges is net of income tax of $33 million for 2012. 2012 includes a $15 million before tax unrealized gain that was recognized in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations, as the underlying transaction was no longer probable of occurring (see Note 14).

(b) Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million and $159 million of income tax for 2013 and 2012, respectively. Before tax amounts realized and reclassified to product revenues, primarily natural gas sales revenues, on the Consolidated Statements of Operations were $5 million and $434 million for 2013 and 2012, respectively.

See accompanying notes.

71

WPX Energy, Inc.

Consolidated Statements of Changes in Equity

	WPX Energy, Inc., Stockholders
	Common Stock		Capital in Excess of Par Value		Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Noncontrolling Interests(a)			Total
	(Millions)
Balance at December 31, 2011	$	2	$	5,457	$	—		$	219		$	5,678		$	81		$	5,759
Comprehensive income:
Net income (loss)	—		—		(223		)	—			(223		)	12			(211		)
Other comprehensive income (loss)	—		—					(217		)	(217		)	—			(217		)
Comprehensive income (loss)																	(428		)
Contribution from noncontrolling interest														10			10
Stock based compensation, net of tax benefit			30								30						30
Balance at December 31, 2012	2		5,487		(223		)	2			5,268			103			5,371
Comprehensive income:
Net income (loss)	—		—		(1,185		)	—			(1,185		)	(6		)	(1,191		)
Other comprehensive income (loss)	—		—					(3		)	(3		)	—			(3		)
Comprehensive income (loss)																	(1,194		)
Contribution from noncontrolling interest														4			4
Stock based compensation, net of tax benefit	—		29					—			29			—			29
Balance at December 31, 2013	2		5,516		(1,408		)	(1		)	4,109			101			4,210
Comprehensive income:
Net income (loss)	—		—		164						164			7			171
Other comprehensive income (loss)	—		—					—			—						—
Comprehensive income (loss)																	171
Contribution from noncontrolling interest	—		—					—			—			1			1
Stock based compensation, net of tax benefit	—		46					—			46			—			46
Balance at December 31, 2014	$	2	$	5,562	$	(1,244	)	$	(1	)	$	4,319		$	109		$	4,428

__________

(a) Primarily represents the 31 percent of Apco Oil and Gas International Inc. owned by others.

See accompanying notes.

72

WPX Energy, Inc.

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2014			2013			2012
Operating Activities	(Millions)
Net income (loss)	$	171		$	(1,191	)	$	(211	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	863			940			973
Deferred income tax provision (benefit)	46			(645		)	(160		)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments	236			1,483			288
Amortization of stock-based awards	36			32			28
(Gain) loss on sales of assets(a)	196			(41		)	(42		)
Cash provided (used) by operating assets and liabilities:
Accounts receivable	51			(43		)	68
Inventories	19			(5		)	7
Margin deposits and customer margin deposits payable	(10		)	(18		)	(5		)
Other current assets	8			(7		)	7
Accounts payable	4			41			(128		)
Accrued and other current liabilities	(1		)	(21		)	12
Changes in current and noncurrent derivative assets and liabilities	(559		)	106			(32		)
Other, including changes in other noncurrent assets and liabilities	10			5			(9		)
Net cash provided by operating activities	1,070			636			796
Investing Activities
Capital expenditures(b)	(1,807		)	(1,154		)	(1,521		)
Proceeds from sales of assets	374			49			310
Other	(4		)	(6		)	7
Net cash used in investing activities	(1,437		)	(1,111		)	(1,204		)
Financing Activities
Proceeds from common stock	16			6			3
Proceeds from long-term debt	500			—			6
Borrowings on credit facility	1,947			970			50
Payments on credit facility	(2,077		)	(560		)	(50		)
Excess tax benefit of stock based awards	—			—			13
Payments for long-term debt issuance costs	(13		)	—			—
Other	(29		)	10			15
Net cash provided by financing activities	344			426			37
Net increase (decrease) in cash and cash equivalents	(23		)	(49		)	(371		)
Effect of exchange rate changes on international cash and cash equivalents	(6		)	(5		)	(2		)
Cash and cash equivalents at beginning of period(c)	99			153			526
Cash and cash equivalents at end of period(c)	$	70		$	99		$	153
__________
(a) 2014 includes $196 million loss on the sale of working interests in the Piceance Basin (Note 4), 2013 includes a $36 million gain on sale of Powder River Basin deep rights leasehold (Note 2) and 2012 includes a $38 million gain on the sale of our holdings in Barnett Shale and Arkoma Basin (Note 2).
(b)   Increase to properties and equipment	$	(1,934	)	$	(1,207	)	$	(1,449	)
Changes in related accounts payable and accounts receivable	127			53			(72		)
Capital expenditures	$	(1,807	)	$	(1,154	)	$	(1,521	)
(c) Amounts include cash associated with our international operations which represent the difference between amounts reported as cash on the Consolidated Balance Sheets.

See accompanying notes.

73

WPX Energy, Inc.

Notes to Consolidated Financial Statements

Note 1. Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Description of Business

Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.

In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of Powder River Basin and Apco are reported as discontinued operations.

The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we,” “us” or “our.”

Basis of Presentation

These financial statements are prepared on a consolidated basis.

Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.

Discontinued operations

On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.

Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).

See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions which impact these financials include:

• impairment assessments of long-lived assets;

• valuations of derivatives;

• estimation of natural gas and oil reserves;

• assessments of litigation-related contingencies; and

• asset retirement obligations.

These estimates are discussed further throughout these notes.

Cash and cash equivalents

Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Restricted cash

Restricted cash consists of approximately $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

Inventories

All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. The following table presents a summary of inventories.

	Years ended December 31,
	2014		2013
	(Millions)
Material, supplies and other	$	43	$	43
Crude oil production in transit	2		10
Natural gas in underground storage	—		13
	$	45	$	66

During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.

Properties and equipment

Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.

Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.

Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.

Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.

Depreciation, depletion and amortization

Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.

Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

Impairment of long-lived assets

We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.

Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

Contingent liabilities

Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.

Asset retirement obligations

We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.

Cash flows from revolving credit facilities

Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.

Derivative instruments and hedging activities

We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.

We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.

Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

• unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;

• unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;

• the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;

• realized gains and losses on all derivatives that settle financially;

• realized gains and losses on derivatives held for trading purposes; and

• realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Product revenues

Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

million in 2013 and 2012, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.

Gas management revenues and expenses

Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.

Charges for unutilized transportation capacity included in gas management expenses were $57 million, $61 million and $46 million in 2014, 2013 and 2012, respectively.

Capitalization of interest

We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million. We use the weighted average rate of our outstanding debt (see Note 7).

Income taxes

We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.

Employee stock-based compensation

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

Foreign exchange

Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.

Earnings (loss) per common share

Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 3).

Note 2. Discontinued Operations

On October 3, 2014, we announced an agreement to sell our international interests for approximately $294 million subject to the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco. During January 2015 we completed the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol. Together, these non-operated international holding comprised our international segment. We expect to book a gain of approximately $40 million related to this transaction during first quarter 2015.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

During the third quarter of 2014, our management signed an agreement to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million, subject to closing adjustments such as net revenues from effective date to closing date. We continue to negotiate the divestiture. The original sales agreement was scheduled to terminate February 13, 2015, but both parties agreed to extend the timetable. If the agreement does not successfully close in March, WPX has the option to terminate the transaction. Additionally, we have recorded a $45 million impairment of the net assets to a probability weighted-average of expected sales prices. The Company has not actively drilled in the basin since 2011. The Powder River operations have firm gathering and treating agreements with total commitments of $128 million through 2020. These commitments have been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2015 and beyond totaling $172 million. Depending on the final terms upon closing of the Powder River sale, we may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Powder River Basin.

During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.

Summarized Results of Discontinued Operations

For the year ended December 31, 2014	Domestic		International		Total
			(Millions)
Total revenues	$	189	$	163	$	352
Costs and expenses:
Lease and facility operating	$	41	$	37	$	78
Gathering, processing and transportation	70		1		71
Taxes other than income	16		28		44
Exploration	—		4		4
Depreciation, depletion and amortization	11		42		53
Impairment of assets held for sale	45		—		45
General and administrative	4		16		20
Other—net	—		12		12
Total costs and expenses	187		140		327
Operating income (loss)	2		23		25
Interest capitalized	1		—		1
Investment income and other	6		19		25
Income (loss) from discontinued operations before income taxes	9		42		51
Provision (benefit) for income taxes(a)	2		7		9
Income (loss) from discontinued operations	$	7	$	35	$	42

__________

(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

For the year ended December 31, 2013	Domestic			International		Total
				(Millions)
Total revenues	$	178		$	152	$	330
Costs and expenses:
Lease and facility operating	$	44		$	37	$	81
Gathering, processing and transportation	80			3		83
Taxes other than income	15			24		39
Exploration	1			7		8
Depreciation, depletion and amortization	48			34		82
Impairment of producing properties and costs of acquired unproved reserves	192			3		195
Gain on sale of Powder River Basin deep rights leasehold	(36		)	—		(36		)
General and administrative	6			14		20
Other—net	5			—		5
Total costs and expenses	355			122		477
Operating income (loss)	(177		)	30		(147		)
Interest capitalized	4			—		4
Investment income and other	4			21		25
Income (loss) from discontinued operations before income taxes	(169		)	51		(118		)
Provision (benefit) for income taxes(a)	(62		)	31		(31		)
Income (loss) from discontinued operations	$	(107	)	$	20	$	(87	)

__________

(a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

For the year ended December 31, 2012	Domestic			International		Total
				(Millions)
Total revenues	$	180		$	137	$	317
Costs and expenses:
Lease and facility operating	$	65		$	32	$	97
Gathering, processing and transportation	74			2		76
Taxes other than income	19			24		43
Gas management, including charges for unutilized pipeline capacity	1			—		1
Exploration	1			11		12
Depreciation, depletion and amortization	62			27		89
Impairment of producing properties and costs of acquired unproved reserves	102			—		102
Gain on sale of Barnett Shale and Arkoma Basin holdings	(38		)	—		(38		)
General and administrative	10			14		24
Other—net	(1		)	—		(1		)
Total costs and expenses	295			110		405
Operating income (loss)	(115		)	27		(88		)
Interest capitalized	6			—		6
Investment income and other	4			27		31
Income (loss) from discontinued operations before income taxes	(105		)	54		(51		)
Provision (benefit) for income taxes	(38		)	24		(14		)
Income (loss) from discontinued operations	$	(67	)	$	30	$	(37	)

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations

December 31, 2014	Domestic			International			Total
				(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—		$	29		$	29
Accounts receivable	—			25			25
Inventories	1			7			8
Other	—			14			14
Total current assets	1			75			76
Investments	18			134			152
Properties and equipment (successful efforts method of accounting)(a)	132			445			577
Less—accumulated depreciation, depletion and amortization	(10		)	(228		)	(238		)
Properties and equipment, net	122			217			339
Other noncurrent assets	—			6			6
Total assets classified as held for sale—discontinued operations	$	141		$	432		$	573
Total assets classified as held for sale—continuing operations (Note 4)	200			—			200
Total assets classified as held for sale on the Consolidated Balance Sheets	$	341		$	432		$	773
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—		$	34		$	34
Accrued and other current liabilities	3			23			26
Total current liabilities	3			57			60
Deferred income taxes	—			13			13
Long-term debt	—			2			2
Asset retirement obligations	45			7			52
Other noncurrent liabilities	—			3			3
Total liabilities associated with assets held for sale—discontinued operations	$	48		$	82		$	130
Total liabilities associated with assets held for sale—continuing operations (Note 4)	$	2		$	—		$	2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	50		$	82		$	132

__________

(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

December 31, 2013	Domestic		International			Total
			(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—	$	51		$	51
Accounts receivable	—		18			18
Inventories	1		5			6
Other	—		17			17
Total current assets	1		91			92
Investments	17		125			142
Properties and equipment (successful efforts method of accounting)	166		360			526
Less—accumulated depreciation, depletion and amortization	—		(194		)	(194		)
Properties and equipment, net	166		166			332
Total assets classified as held for sale—discontinued operations(a)	$	184	$	382		$	566
Total assets classified as held for sale—continuing operations (Note 4)(a)	148		—			148
Total assets classified as held for sale on the Consolidated Balance Sheets(a)	$	332	$	382		$	714
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	18		$	18
Accrued and other current liabilities	3		20			23
Total current liabilities	3		38			41
Deferred income taxes	—		12			12
Long-term debt	—		5			5
Asset retirement obligations	47		4			51
Total liabilities associated with assets held for sale—discontinued operations(a)	$	50	$	59		$	109
Total liabilities associated with assets held for sale—continuing operations (Note 4)	2		—			2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(a)	$	52	$	59		$	111

__________

(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.

Noncontrolling interests in consolidated subsidiaries of $109 million and $101 million as of December 31, 2014 and 2013, respectively, related to assets classified as held for sale.

Cash Flows Attributable to Discontinued Operations

Excluding taxes and changes to working capital related to Powder River Basin, total cash provided by operating activities related to discontinued operations was $65 million, $36 million and $18 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related to Powder River Basin discontinued operations was $11 million, $3 million and $20 million for 2014, 2013 and 2012, respectively. Cash provided by operating activities related to our international operations was $65 million, $56 million and $50 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related our international operations was $85 million, $43 million and $56 million for 2014, 2013 and 2012, respectively.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

Note 3. Earnings (Loss) Per Common Share from Continuing Operations

 Thefollowing table summarizes the calculation of earnings per share.

	Years Ended December 31,
	2014		2013			2012
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	129	$	(1,092	)	$	(174	)
Basic weighted-average shares	202.7		200.5			198.8
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	2.7
Stock options	0.9
Diluted weighted-average shares	206.3		200.5			198.8
Earnings (loss) per common share from continuing operations:
Basic	$	0.63	$	(5.45	)	$	(0.87	)
Diluted	$	0.62	$	(5.45	)	$	(0.87	)

__________

(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

The table below includes information related to stock options that were outstanding at December 31, 2014, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.

	2014		2013		2012
Options excluded (millions)	1.4		0.4		1.3
Weighted-average exercise price of options excluded	$	18.42	$	20.24	$	18.17
Exercise price range of options excluded	$16.46 - $21.81		$20.21  - $20.97		$16.46  - $20.97
Fourth quarter weighted-average market price	$	15.96	$	19.97	$	16.15

Note 4. Asset Sales, Impairments and Exploration Expenses

In 2014, we recorded a total of $87 million in impairment charges associated with exploratory well costs and producing properties of which approximately $20 million is recorded as a separate line on the Consolidated Statements of Operations and $67 million is included in exploration expenses. In 2013, we recorded a total of $1.2 billion in impairment charges of which $860 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expenses and $20 million is included in investment income, impairment of equity method investment and other. These impairments are discussed further in the sections below.

Asset Sales

In June 2014, we sold portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP (“Legacy”) for $325 million cash with an effective date of January 1, 2014. The terms of the sale also provided us with a 10 percent ownership in a newly created class of incentive distribution rights (“IDR”) of Legacy. The working interests represented approximately 300 Bcfe of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. Production related to these working interests for January 2014 through May 2014 approximated 70 MMcfe per day of our production. Based on an estimated total value received of $329 million, which represents estimated final cash proceeds and an estimated fair value of the IDRs, we recorded a $195 million loss on the sale in second quarter 2014. In the third quarter of 2014, we recorded an additional loss on sale of $1 million related to this transaction.

On December 3, 2014, we announced that we have agreed to sell our operations in northeast Pennsylvania and release certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $300 million in cash. Net property, plant and equipment related to this transaction, as of December 31,2014, was $200 million and asset retirement

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obligation liability was $2 million. The transaction includes physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 operated horizontal wells. The assets are primarily located in Susquehanna County, Pennsylvania. The transaction also includes the release of firm transportation capacity that we have under contract in the northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we will be released from approximately $24 million per year in annual demand obligations associated with the transport. The transaction subsequently closed on January 30, 2015 and we estimate a net gain of at least $75 million will be recorded in first quarter 2015.

Impairments

The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments.

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)	$	20	$	860	$	123
Impairment of equity method investment in Appalachian Basin	$	—	$	20	$	—

__________

(a) Excludes related impairments of unproved leasehold included in exploration expenses.

As a result of declines in forward crude oil and natural gas prices primarily during the fourth-quarter 2014 as compared to forward prices as of December 31, 2013, we performed impairment assessments of our proved producing properties and costs of acquired unproved reserves. Accordingly, we recorded the following impairments during 2014:

• $11 million impairment in the fourth quarter in the Green River Basin; and

• $9 million of impairments in the fourth quarter of other properties.

As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded the following impairments during 2013:

• $772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin; and

• $88 million impairment in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area.

The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.

As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded the following impairments during 2012:

• $75 million impairment of capitalized costs of acquired unproved reserves in the Piceance Basin; and

• $48 million impairment of proved producing oil and gas properties in the Green River Basin.

Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 13).

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Exploration Expenses

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Geologic and geophysical costs	$	11	$	18	$	12
Impairments of exploratory area well costs and dry hole costs	88		3		1
Unproved leasehold property impairments, amortization and expiration	74		402		58
Total exploration expenses	$	173	$	423	$	71

Impairments of exploratory well and dry hole costs for 2014 include $67 million of impairment related to our Niobrara Shale well costs in the Piceance Basin and $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities. The remaining amount represents dry hole costs associated with exploratory wells where hydrocarbons were not detected. The $67 million Niobrara Shale impairment relates to carrying costs on producing and science wells in excess of estimated discounted cash flows of the exploratory play. We continue to evaluate the potential of our Niobrara Shale exploratory play and plan to drill additional wells in 2015. As of December 31, 2014, our total domestic capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $37 million.

Unproved leasehold impairment, amortization and expiration in 2014 includes impairments of $41 million for unproved leasehold costs in exploratory areas where the company no longer intends to continue exploration activities.

Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold associated with our impairment of the producing properties in the Appalachian Basin.

Note 5. Properties and Equipment

Properties and equipment is carried at cost and consists of the following:

	Estimated Useful Life(a) (Years)	December 31,
		2014			2013
		(Millions)
Proved properties	(b)	$	10,386		$	10,955
Unproved properties	(c)	394			316
Gathering, processing and other facilities	15-25	251			209
Construction in progress	(c)	541			353
Other	3-40	181			178
Total properties and equipment, at cost		11,753			12,011
Accumulated depreciation, depletion and amortization		(4,911		)	(5,251		)
Properties and equipment—net		$	6,842		$	6,760

__________

(a) Estimated useful lives are presented as of December 31, 2014.

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

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

During 2014, we purchased oil and natural gas properties in the San Juan Basin for $150 million. The properties purchased included both producing wells and undeveloped locations. Approximately $50 million of the purchase price was allocated to proved producing properties and the remainder to proved undeveloped or unproved leasehold within properties and equipment. The purchase is included within our capital expenditures on the Consolidated Statements of Cash Flows. 

Also during 2014, we closed an agreement to farmout a portion of our Trail Ridge properties in the Piceance Basin with TRDC LLC, a subsidiary of G2X Energy. We received $50 million in cash for 49 percent of our working interests in

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approximately 100 proved developed wells and certain incurred drilling costs. TRDC LLC has committed to a $170 million drilling carry on nearly 400 future wells and will make additional investments for its 49 percent working interest.

Unproved properties consist primarily of non-producing leasehold in the San Juan, Williston and Piceance Basins.

Asset Retirement Obligations

Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.

A rollforward of our asset retirement obligations for the years ended 2014 and 2013 is presented below.

	2014			2013
	(Millions)
Balance, January 1	$	308		$	261
Liabilities incurred	19			11
Liabilities settled	(2		)	(1		)
Liabilities associated with assets sold	(65		)	—
Estimate revisions	(78		)	17
Accretion expense(a)	19			20
Balance, December 31	$	201		$	308
Amount reflected as current	$	3		$	3

__________

(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Estimate revisions in 2014 are primarily associated with decreases in anticipated plug and abandonment costs.

Note 6. Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable

	December 31,
	2014		2013
	(Millions)
Trade	$	215	$	208
Accrual for capital expenditures	313		225
Royalties	125		130
Cash overdrafts	—		35
Other	59		36
	$	712	$	634

Accrued and other current liabilities

	December 31,
	2014		2013
	(Millions)
Taxes other than income taxes	$	41	$	41
Accrued interest	53		43
Compensation and benefit related accruals	55		52
Other, including other loss contingencies	28		31
	$	177	$	167

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Note 7. Debt and Banking Arrangements

As of the indicated dates, our debt consisted of the following:

	December 31,
	2014 (a)		2013 (a)
	(Millions)
5.250% Senior Notes due 2017	$	400	$	400
6.000% Senior Notes due 2022	1,100		1,100
5.250% Senior Notes due 2024	500		—
Credit facility agreement	280		410
Other	1		2
Total debt	$	2,281	$	1,912
Less: Current portion of long-term debt	1		1
Total long-term debt	$	2,280	$	1,911

__________

(a) Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

Senior Notes

In November 2011, we issued $400 million aggregate principal amount of 5.25% Senior Notes due 2017 (the “2017 Notes”) and $1.1 billion aggregate principal amount of 6.00% Senior Notes due 2022 (the “2022 Notes”) pursuant to a private offering, and in June 2012 we exchanged these notes for registered 2017 Notes and 2022 Notes. The 2017 Notes and 2022 Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee.

In September 2014, we issued $500 million aggregate principal amount of 5.25% Senior Notes due 2024 (“the 2024 Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 2024 Notes were issued under an indenture, as supplemented by a supplemental indenture, each between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the 2024 Notes were approximately $494 million after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility.

The terms of the indentures governing our 2017 Notes, 2022 Notes and 2024 Notes are substantially identical.

Optional Redemption. We have the option prior to maturity for the 2017 Notes, prior to October 15, 2021 for the 2022 Notes, and prior to June 15, 2024 for the 2024 Notes to redeem some or all of such notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. We also have the option at any time or from time to time on or after October 15, 2021 to redeem the 2022 Notes, or on or after June 15, 2024, to redeem the 2024 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date.

Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.

Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.

Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:

(1) a default in the payment of interest on the notes when due that continues for 30 days;

(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity, upon redemption, or otherwise;

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(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and

(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.

Credit Facility Agreement

In October 2014, we amended and restated our $1.5 billionfive-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility Agreement matures on October 28, 2019. As of December 31, 2014, the weighted average variable interest rate was 3.01% on the $280 million outstanding under the Credit Facility Agreement. As of February 25, 2015, we did not have any outstanding borrowings under the Credit Facility Agreement as proceeds from asset sales were used to repay all outstanding amounts.

Interest on borrowings under the Credit Facility Agreement are payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5%, (ii) Citibank, N.A.'s publicly announced prime rate, and (iii) one-month LIBOR plus 1.0%. The Applicable Rate is defined in the Credit Facility Agreement and is determined by which interest rate we select and the ratings of our long-term unsecured debt. At December 31, 2014, the Applicable Rate was 1.875% on our LIBOR loans and 0.875% on our alternate base rate loans. Additionally, we will be required to pay a commitment fee, based on the ratings of our long-term unsecured debt, on the unused portion of the commitments under the Credit Facility Agreement. At December 31, 2014, the commitment fee rate was 0.30%.

Under the Credit Facility Agreement, when our long-term unsecured debt rating is not BBB- or better by S&P or Baa3 or better by Moody’s and the other of the two ratings is not less than BB+ by S&P or Ba1 by Moody's, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the Credit Facility Agreement) to Consolidated EBITDAX (as defined in the Credit Facility Agreement) of not greater than 3.75 to 1.00. Consolidated Net Indebtedness includes a reduction attributable to unrestricted cash and cash equivalents not to exceed $50 million. Consolidated EBITDAX will be calculated for the four fiscal quarters ending on the last day of any fiscal quarter for which financial statements have been or were required to be delivered. Additionally, the ratio of Consolidated Indebtedness (defined as Indebtedness of us and our consolidated subsidiaries determined on a consolidated basis) to Consolidated Total Capitalization (defined as Consolidated Indebtedness plus Consolidated Net Worth) will not be permitted to be greater than 60 percent and will be applicable for the life of the agreement.

When our long-term unsecured debt rating is BB or worse by S&P and Ba2 or worse by Moody's or BB- or worse by S&P or Ba3 or worse by Moody's, we will also be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the Credit Facility Agreement, to Consolidated Indebtedness ratio of at least 1.25 to 1.00 for fiscal periods ending on or prior to December 31, 2015, and 1.50 to 1.00 for fiscal periods ending after December 31, 2015. Based on our current long-term unsecured debt ratings, as of the date of this filing, we are not required to comply with this covenant. In addition, this covenant will not apply at any time after the occurrence of the Investment Grade Date, which is the first date after closing on which our long-term unsecured debt is rated BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or watch by either agency), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.

The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness; our and our subsidiaries' ability to grant certain liens, materially change the nature of our or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of our material subsidiaries to enter into certain restrictive agreements; our and our material subsidiaries' ability to enter into certain affiliate transactions; and our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person. We and our subsidiaries are also prohibited from using the

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proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to certain exceptions and/or standards of materiality applicable to the contracting parties that differ from those applicable to investors.

The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.

Letters of Credit

WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2014 a total of $320 million in letters of credit have been issued.

Note 8. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes from continuing operations includes:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision (benefit):
Current:
Federal	$	(3	)	$	(29	)	$	49
State	1			1			4
	(2		)	(28		)	53
Deferred:
Federal	76			(549		)	(125		)
State	1			(47		)	(12		)
	77			(596		)	(137		)
Total provision (benefit)	$	75		$	(624	)	$	(84	)

Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision (benefit) at statutory rate	$	71		$	(604	)	$	(90	)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	3			(111		)	(6		)
State income tax change in valuation allowance (net of federal benefit)	(1		)	80			—
State income tax legislation change (net of federal benefit)	9			—			—
Effective state income tax rate change (net of federal benefit)	(9		)	(3		)	—
Alternative minimum tax credits	—			—			11
Other	2			14			1
Provision (benefit) for income taxes	$	75		$	(624	)	$	(84	)

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Significant components of deferred tax liabilities and deferred tax assets are as follows:

	December 31,
	2014		2013
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	738	$	961
Derivatives, net	170		—
Other, net	17		23
Total deferred tax liabilities	925		984
Deferred tax assets:
Accrued liabilities and other	124		176
Alternative minimum tax credits	60		76
Loss carryovers	51		83
Derivatives, net	—		21
Other, net	32		—
Total deferred tax assets	267		356
Less: valuation allowance	114		99
Total net deferred tax assets	153		257
Net deferred tax liabilities	$	772	$	727

Net cash payments for domestic income taxes were $9 million and $40 million in 2014 and 2012, respectively, while net cash refunds were $26 million in 2013.

We had federal net operating loss (“NOL”) carryovers of approximately $114 million at December 31, 2013, which were fully utilized in 2014. The Company has state NOL carryovers, primarily in Pennsylvania, of approximately $875 million and $825 million at 2014 and 2013, respectively, of which more than 90 percent expire after 2029.

Tax reform legislation was enacted by the state of New York on March, 31, 2014, and had an impact on us as a result of our marketing activities in the state. As a result, we recorded an additional $9 million of deferred tax expense in the first quarter of 2014 to accrue for the impact of this new legislation. However, due to announced asset sales in fourth-quarter 2014, our state effective tax rate decreased resulting in a $9 million deferred tax benefit.

We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania. In addition, we have recorded a valuation allowance against a portion of the excess tax basis in our investment in Apco, which have been included in discontinued operations (see Note 2). In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. As a result of our assessment of available evidence, a valuation allowance was recorded to reduce recognized tax assets, net of federal tax, to an amount that will more likely than not be realized by the Company.

Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the excess tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. At December 31, 2013, $7 million of excess tax benefit was not included in the Company’s loss carryovers deferred tax asset. The $7 million excess tax benefit was recognized in 2014 due to the utilization of loss carryovers.

Through the effective date of our spin-off from The Williams Companies, Inc. (“Williams”), December 31, 2011, our domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. Effective with the spin-off, we entered into a tax sharing agreement with Williams which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off. Pursuant to the tax sharing agreement, we remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. We are not aware of any significant

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adjustments related to our business, but the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments to 2011 unrelated to our business. Williams previously notified us of certain corrections that resulted in reductions in the alternative minimum tax credit allocated to us, of which $11 million was a reduction of a benefit for income taxes in 2012.

The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.

As of December 31, 2014, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.

Note 9. Contingent Liabilities and Commitments

Royalty litigation

In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We have completed the accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to seek a stay of this new lawsuit pending resolution of the first lawsuit in the Colorado Court of Appeals.

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.

Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues

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in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2008 through December 2014, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $113 million.

Environmental matters

The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Matters related to Williams’ former power business

In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion on the Western States Antitrust Litigation. The panel held that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims, reversing the summary judgment entered in favor of the defendants. The panel further held that the district court did not abuse its discretion in denying the plaintiffs’ motions for leave to amend complaints. The U.S. Supreme Court granted Defendants' writ of certiorari. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.

Other Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that

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are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.

At December 31, 2014, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

In connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.

Summary

As of December 31, 2014 and December 31, 2013, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

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

Commitments

As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2014 are as follows:

	(Millions)
2015	$	177
2016	162
2017	149
2018	138
2019	126
Thereafter	389
Total	$	1,141

Also, in conjunction with the closing of the Powder River sale and current terms therein, we may record certain pipeline capacity obligations held by our marketing company associated with our exiting the Powder River Basin. Our total commitments related to these pipeline agreements for 2015 and beyond total $172 million.

We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services, which total $305 million over approximately six years.

Excluded from the pipeline capacity and natural gas gathering and treating services commitments discussed above are commitments totaling $88 million and $43 million, respectively, which have been or are assumed to be assigned to the buyers of assets held for sale.

In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

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Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:

	(Millions)
2015	$	37
2016	32
2017	11
2018	7
2019	7
Thereafter	15
Total	$	109

Leases totaling $0.5 million associated with assets held for sale are excluded from the operating lease commitments discussed above.

Total rent expense, excluding amounts capitalized, was $27 million, $27 million and $19 million in 2014, 2013 and 2012, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.

Note 10. Employee Benefit Plans

WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $17 million, $16 million and $6 million for 2014, 2013 and 2012, respectively. Approximately $10 million and $11 million were included in accrued and other current liabilities at December 31, 2014 and December 31, 2013 respectively, related to the non-matching annual employer contribution.

Note 11. Stock-Based Compensation

WPX Energy, Inc. 2013 Incentive Plan

We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2013 Incentive Plan is 19.8 million shares. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.

The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 124 thousand shares at an average price of $12.56 per share during 2014.

Employee stock-based awards

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.

Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

Restricted stock units are generally valued at fair value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

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Notes to Consolidated Financial Statements—(Continued)

Total stock-based compensation expense reflected in general and administrative expense for the years ended December 31, 2014, 2013 and 2012 was $35 million, $31 million and $28 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2014 was $41 million. This amount is comprised of $1 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2014.

	WPX Plan
Stock Options	Options		Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)				(Millions)
Outstanding at December 31, 2013(a)	4.1		$	13.27	$	29
Granted	0.4		$	19.03
Exercised	(1.3	)	$	11.11
Forfeited	(0.1	)	$	15.39
Outstanding at December 31, 2014(a)	3.1		$	14.80	$	2
Exercisable at December 31, 2014	2.7		$	14.26	$	2

__________

(a) Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.

The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $13 million, $5 million and $5 million, respectively.

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2014.

	WPX Plan
	Stock Options Outstanding				Stock Options Exercisable
Range of Exercise Prices	Options	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life	Options	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life
	(Millions)			(Years)	(Millions)			(Years)
$ 6.02 to $10.68	0.5	$	7.59	2.8	0.5	$	7.59	2.8
$ 11.32 to $13.46	0.6	$	11.82	4.0	0.6	$	11.82	4.0
$14.41 to $18.23	1.5	$	16.39	6.1	1.2	$	16.36	5.6
$19.95 to $21.81	0.5	$	20.61	5.0	0.4	$	20.24	3.2
Total	3.1	$	14.80	5.0	2.7	$	14.26	4.4

The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows:

	WPX Plan
	2014			2013			2012
Weighted-average grant date fair value of options granted	$	18.94		$	6.04		$	7.79
Weighted-average assumptions:
Dividend yield	—			—			—
Volatility	43.0		%	42.8		%	43.8		%
Risk-free interest rate	1.85		%	1.06		%	1.17		%
Expected life (years)	5.9			6.0			6.0

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Notes to Consolidated Financial Statements—(Continued)

For 2014, 2013 and 2012, we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method.

Cash received from stock option exercises was $14 million, $4 million and $2 million during 2014, 2013 and 2012, respectively.

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.

	WPX Plan
Restricted Stock Units	Shares		Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2013	5.2		$	16.97
Granted	2.5		$	18.37
Forfeited	(0.7	)	$	16.92
Vested	(1.9	)	$	16.92
Nonvested at December 31, 2014	5.1		$	17.58

__________

(a) Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Other restricted stock unit information

	WPX Plan
	2014		2013		2012
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.37	$	14.97	$	17.35
Total fair value of restricted stock units vested during the year (millions)	$	33	$	18	$	14

Performance-based shares granted represent 15 percent of nonvested restricted stock units outstanding at December 31, 2014. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Note 12. Stockholders’ Equity

Common Stock

Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends were declared or paid for 2014, 2013 or 2012. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.

Preferred Stock

Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred

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stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.

Note 13. Fair Value Measurements

Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

• Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.

• Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.

• Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

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

	December 31, 2014								December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(Millions)								(Millions)
Energy derivative assets	$	14	$	517	$	5	$	536	$	30	$	26	$	1	$	57
Energy derivative liabilities	$	32	$	10	$	—	$	42	$	83	$	38	$	1	$	122
Total debt(a)	$	—	$	2,218	$	—	$	2,218	$	—	$	1,938	$	—	$	1,938

__________

(a) The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.

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Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.

Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

Forward, swap and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with 100 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2014, consist primarily of natural gas index transactions that are used to manage our physical requirements.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2014 or 2013.

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Notes to Consolidated Financial Statements—(Continued)

The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

	Years ended December 31,
	2014		2013			2012
	(Millions)
Beginning balance	$	—	$	(1	)	$	1
Realized and unrealized gains (losses):
Included in income (loss) from continuing operations	5		(2		)	3
Included in other comprehensive income (loss)	—		—			—
Purchases, issuances, and settlements	—		3			(5		)
Transfers out of Level 3	—		—			—
Ending balance	$	5	$	—		$	(1	)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	5	$	(1	)	$	(1	)

Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations.

As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas, oil and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In each of the three years ended December 31, 2014, our assessments identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

	Total losses for the years ended December 31,
	2014 (a)		2013 (b)		2012 (c)
	(Millions)
Impairments:
Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)	$	20	$	1,055	$	225
Unproved leasehold	—		317		—
Equity method investment (Note 4)	—		20		—
	$	20	$	1,392	$	225

__________

(a) As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:

• $11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.

• $9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

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(b) As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:

• $792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.

• $317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.

• $107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.

• $88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

• $85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

(c) As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:

• $102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

• $48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

Note 14. Derivatives and Concentration of Credit Risk

Energy Commodity Derivatives

Risk Management Activities

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.

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Notes to Consolidated Financial Statements—(Continued)

We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.

We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.

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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 December 31, 2014.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Natural Gas
Natural Gas	2015	Fixed Price Swaps	Henry Hub	(442	)	$	4.10
Natural Gas	2015	Costless Collars	Henry Hub	(50	)	$ 4.00 - 4.50
Natural Gas	2015	Basis Swaps	NGPL	(13	)	$	(0.16	)
Natural Gas	2015	Basis Swaps	Rockies	(150	)	$	(0.11	)
Natural Gas	2015	Basis Swaps	San Juan	(85	)	$	(0.10	)
Natural Gas	2015	Basis Swaps	SoCal	(20	)	$	0.18
Natural Gas	2016	Fixed Price Swaps	Henry Hub	(200	)	$	3.98
Natural Gas	2016	Swaptions	Henry Hub	(90	)	$	4.23
Natural Gas	2017	Swaptions	Henry Hub	(65	)	$	4.19
Crude Oil
Crude Oil	2015	Fixed Price Swaps	WTI	(20,236	)	$	94.88
Crude Oil	2015	Swaptions	WTI	(882	)	$	97.29
Crude Oil	2016	Swaptions	WTI	(5,250	)	$	97.55

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.

(b) Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.

(c) The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

Derivatives primarily related to transportation

The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.

Commodity	Period	Contract Type (a)	Location (b)	Notional Volume (c)
Natural Gas	2015	Basis Swaps	Multiple	(3	)
Natural Gas	2015	Index	Multiple	(118	)
Natural Gas	2016	Index	Multiple	(70	)
Natural Gas	2017	Index	Multiple	(70	)
Natural Gas	2018+	Index	Multiple	(379	)

__________

(a) We enter into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.

(b) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.

(c) Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.

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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.

	December 31,
	2014				2013
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Derivatives related to production not designated as hedging instruments	$	517	$	10	$	26	$	39
Derivatives related to physical marketing agreements not designated as hedging instruments	19		32		31		83
Total derivatives not designated as hedging instruments	$	536	$	42	$	57	$	122

The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.

	Years Ended December 31,						Classification
	2014		2013		2012
			(Millions)
Net gain recognized in other comprehensive income (loss) (effective portion)	$	—	$	—	$	90	AOCI
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	—	$	5	$	434	Revenues

__________

(a) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.

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

	Years Ended December 31,
	2014			2013			2012
Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515		$	(57	)	$	66
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)	(67		)	12
Net gain (loss) on derivatives not designated as hedges	$	434		$	(124	)	$	78

__________

(a) Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.

(b) Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.

The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

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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)			Cash Collateral Posted(Received)		Net Amount
December 31, 2014	(Millions)
Derivative assets with right of offset or master netting agreements	$	536		$	(25	)	$	—	$	511
Derivative liabilities with right of offset or master netting agreements	$	(42	)	$	25		$	17	$	—
December 31, 2013
Derivative assets with right of offset or master netting agreements	$	57		$	(50	)	$	—	$	7
Derivative liabilities with right of offset or master netting agreements	$	(122	)	$	50		$	52	$	(20	)

__________

(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from S&P’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

As of December 31, 2014, we had collateral totaling $26 million posted to derivative counterparties, which includes $9 million of initial margin to clearinghouses or exchanges to enter into positions and $17 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $17 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2013, we had collateral totaling $71 million posted to derivative counterparties, which includes $19 million of initial margin to clearinghouses or exchanges to enter into positions and $52 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $72 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was less than $1 million at December 31, 2014 and $20 million at December 31, 2013.

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark-to-market value. As of December 31, 2012, we had hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at

105

WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) were expected to be reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Actual gains or losses realized in the first quarter of 2013 matched these values. These gains substantially offset net losses that were realized in earnings from previous unfavorable market movements associated with underlying hedged transactions.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:

	2014		2013
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	340	$	339
Joint interest owners	106		168
Other	13		11
Total	$	459	$	518

Natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2014, 2013 and 2012, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

106

WPX Energy, Inc.

Notes to Consolidated Financial Statements—(Continued)

The gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:

Counterparty Type	Gross Total			Net Total
	(Millions)
Gas and electric utilities, integrated oil and gas companies, and other	$	4		$	4
Financial institutions (Investment Grade) (a)	533			508
	537			512
Credit reserves	(1		)	(1		)
Credit exposure from derivatives	$	536		$	511

__________

(a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Our nine largest net counterparty positions represent approximately 96 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

Other

At December 31, 2014, we held collateral support of approximately $32 million, either in the form of cash or letters of credit, related to our gas management sale agreements.

The customer margin deposits payable as of December 31, 2014 related to our commodity agreements. Collateral support for our commodity agreements could also include letters of credit and guarantees of payment by credit worthy parties.

Revenues

During 2014, 2013 and 2012, BP Energy Company, a domestic segment customer, accounted for 13 percent, 16 percent and 11 percent of our consolidated revenues, respectively. During 2014 and 2013, Southern California Gas Company accounted for 8 percent and 11 percent of our consolidated revenues, respectively. Williams accounted for 14 percent of our consolidated revenue for 2012. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

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WPX Energy, Inc.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Millions, except per-share amounts)
2014
Revenues	$	894		$	727		$	747		$	1,125
Operating costs and expenses	$	783		$	659		$	570		$	656
Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
Income (loss) from discontinued operations	19			11			20			(8		)
Net income (loss)	$	19		$	(133	)	$	66		$	219
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
Income (loss) from discontinued operations	18			9			16			(8		)
Net income (loss)	$	18		$	(135	)	$	62		$	219
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.11
Income (loss) from discontinued operations	0.09			0.05			0.07			(0.03		)
Net income (loss)	$	0.09		$	(0.66	)	$	0.30		$	1.08
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.10
Income (loss) from discontinued operations	0.09			0.05			0.07			(0.04		)
Net income (loss)	$	0.09		$	(0.66	)	$	0.30		$	1.06
2013
Revenues	$	552		$	722		$	581		$	576
Operating costs and expenses	$	634		$	612		$	621		$	1,024
Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(890	)
Income (loss) from discontinued operations	2			16			(11		)	(94		)
Net income (loss)	$	(113	)	$	22		$	(116	)	$	(984	)
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(878	)
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	(116	)	$	18		$	(114	)	$	(973	)
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.57	)	$	0.03		$	(0.52	)	$	(4.37	)
Income (loss) from discontinued operations	(0.01		)	0.06			(0.05		)	(0.48		)
Net income (loss)	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

Net loss for fourth-quarter 2014 includes the following pre-tax items:

• $87 million of impairments of costs of producing properties, acquired unproved reserves and leasehold (see Note 4).

• During 2014, we assigned our remaining natural gas storage capacity agreement to a third party and sold the remaining natural gas stored under this agreement for a total loss of approximately $18 million reflected in gas management expenses in the Consolidated Statements of Operations.

108

Net income for third-quarter 2014 includes the following pre-tax items:

• $22 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.

Net loss for second-quarter 2014 includes the following pre-tax items:

• $195 million loss on the sale of a portion of our working interests in certain Piceance Basin wells.

• $40 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.

• $11 million increase in gas management expense related to a tariff rate refund received in prior years which is no longer under appeal by the pipeline company.

Net income for first-quarter 2014 includes the following pre-tax items:

• $9 million deferred tax expense to accrue for the impact of new legislation (see Note 8.)

Net loss for fourth-quarter 2013 includes the following pre-tax items:

• $1,178 million of impairments of costs of producing properties, acquired unproved reserves, leasehold and equity method investment (see Note 4).

• $9 million buyout of a transportation agreement.

Net loss for third-quarter 2013 includes the following pre-tax items:

• $19 million of impairments of costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin (see Note 4).

109

Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:

	First Quarter			Second Quarter			Third Quarter (a)			Fourth Quarter
	(Millions, except per-share amounts)
	(Increase, (Decrease))
2014
Revenues	$	(93	)	$	(87	)	$	47		N/A
Operating costs and expenses	$	(62	)	$	62		$	31		N/A
Income (loss) from continuing operations	$	(19	)	$	(11	)	$	(15	)	N/A
Income (loss) from discontinued operations	19			11			15			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(18	)	$	(9	)	$	(16	)	N/A
Income (loss) from discontinued operations	18			9			16			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
2013
Revenues	$	(79	)	$	(93	)	$	35		$	(81	)
Operating costs and expenses	$	(76	)	$	(77	)	$	22		$	(74	)
Income (loss) from continuing operations	$	(2	)	$	(16	)	$	3		$	94
Income (loss) from discontinued operations	2			16			(3		)	(94		)
Net income (loss)	$	—		$	—		$	—		$	—
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	1		$	(12	)	$	9		$	95
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	—		$	—		$	—		$	—
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.01		$	(0.06	)	$	0.01		$	0.48
Income (loss) from discontinued operations	(0.01		)	0.06			(0.01		)	(0.48		)
Net income (loss)	$	—		$	—		$	—		$	—

__________

(a) Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

110

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(Unaudited)

We have significant continuing oil and gas producing activities primarily in the Piceance and San Juan Basins in the Rocky Mountain region and the Williston Basin in North Dakota, all of which are located in the United States. Until January 2015, we had international oil and gas producing activities, primarily in Argentina which were previously reported as a segment. The international activities were held for sale as of December 31, 2014 and as such, our international results of operations were reported as discontinued operations (see Note 2 of Notes to Consolidated Financial Statements). International net proved reserves, including amounts related to an equity method investment, were approximately 213 Bcfe or less than 5 percent of our total domestic and international reserves at December 31, 2014. Other than noted below, the following information relates to our domestic oil and gas activities and excludes our gas management activities.

With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information for the Powder River Basin and, through the date of sale in 2012, the holdings in the Barnett Shale and Arkoma Basin both of which have been reported as discontinued operations in our consolidated financial statements. The Powder River Basin operations represent less than 5 percent of our total domestic proved reserves at December 31, 2014. Additionally, capitalized costs exclude amounts related to assets in our Appalachian Basin which were held for sale as of December 31, 2014. Our Appalachian Basin assets held for sale represented less than 5 percent of our total domestic proved reserves.

Capitalized Costs

	As of December 31,
	2014			2013
	(Millions)
Proved Properties	$	10,717		$	11,132
Unproved properties	394			324
	11,111			11,456
Accumulated depreciation, depletion and amortization and valuation provisions	(4,698		)	(5,070		)
Net capitalized costs	$	6,413		$	6,386

• Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $385 million and $328 million, net, for 2014 and 2013, respectively.

• Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.

• Unproved properties consist primarily of unproved leasehold costs.

Cost Incurred

	For the years ended December 31,
	2014		2013		2012
	(Millions)
Acquisition	$	294	$	57	$	111
Exploration	92		104		23
Development	1,376		939		1,130
	$	1,762	$	1,100	$	1,264

• Costs incurred include capitalized and expensed items.

• Acquisition costs are as follows: Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include 28 Bcfe of proved reserves. The 2013 and 2012 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves.

• Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.

• Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.

111

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures—(Continued)

(Unaudited)

Results of Operations

	For the years ended December 31,
	2014		2013			2012
	(Millions)
Revenues:
Natural gas sales	$	1,002	$	896		$	1,193
Oil and condensate sales	724		534			376
Natural gas liquid sales	205		228			297
Net gain (loss) on derivatives not designated as hedges	515		(57		)	66
Other revenues	8		6			7
Total revenues	2,454		1,607			1,939
Costs:
Lease and facility operating	244		227			202
Gathering, processing and transportation	328		350			434
Taxes other than income	126		102			68
Exploration	173		423			71
Depreciation, depletion and amortization	810		858			884
Impairment of certain proved properties	15		772			48
Impairment of costs of acquired unproved reserves	5		88			75
Loss on sale of working interests in the Piceance Basin	196		—			—
General and administrative	264		262			259
Other (income) expense	12		12			16
Total costs	2,173		3,094			2,057
Results of operations	281		(1,487		)	(118		)
Provision (benefit) for income taxes	103		(543		)	(43		)
Exploration and production net income (loss)	$	178	$	(944	)	$	(75	)

• Amounts for all years exclude the equity losses from our equity method investees. Net equity losses from these investees were $1 million, $21 million and $1 million in 2014, 2013 and 2012, respectively.

• Natural gas revenues consist of natural gas production sold and 2012 includes realized gains (losses) of derivatives that were designated as cash flow hedges.

• For derivative instruments that were entered into after January 1, 2012, we did not designate those as cash flow hedges. Any gain (loss) related to these derivatives is included in net gain on derivatives not designated as hedges.

• Other revenues consist of activities that are an indirect part of the producing activities.

• Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2014 include impairments of certain exploratory well costs (see Note 4 of Notes to Consolidated Financial Statements). Exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachian Basin.

• Depreciation, depletion and amortization includes depreciation of support equipment.

112

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures—(Continued)

(Unaudited)

Proved Reserves

The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.

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WPX Energy, Inc.

Supplemental Oil and Gas Disclosures—(Continued)

(Unaudited)

The following is a summary of changes in our domestic proved reserves including proved reserves in the Powder River Basin which is reported as discontinued operations. Proved reserves related to Powder River were approximately 200 Bcfe, 244.6 Bcfe and 235.9 Bcfe at December 31, 2014, 2013 and 2012, respectively. Excluded from the table are our international reserves that are primarily attributable to a consolidated subsidiary (Apco) which represented less than five percent of our total reserves. The international interests were sold in January 2015.

	Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		All Products (Bcfe)
Proved reserves at December 31, 2011	3,982.9		47.1		134.0		5,070.1
Revisions	(404.8	)	5.6		(21.1	)	(498.6	)
Purchases	5.8		—		—		5.8
Divestitures	(217.0	)	(0.3	)	(1.0	)	(224.8	)
Extensions and discoveries	409.2		28.5		8.9		633.8
Production	(407.0	)	(4.4	)	(10.4	)	(495.8	)
Proved reserves at December 31, 2012	3,369.1		76.5		110.4		4,490.5
Revisions	308.3		3.5		(25.4	)	177.2
Divestitures	(0.2	)	—		—		(0.5	)
Extensions and discoveries	312.0		28.8		8.1		533.8
Production	(359.4	)	(5.9	)	(7.4	)	(439.4	)
Proved reserves at December 31, 2013	3,629.8		102.9		85.7		4,761.6
Revisions	(198.3	)	(7.7	)	(13.4	)	(324.8	)
Purchases	6.0		4.2		0.8		36.5
Divestitures	(314.6	)	(1.8	)	(8.5	)	(376.6	)
Extensions and discoveries	362.1		42.4		12.5		691.3
Production	(335.4	)	(9.2	)	(6.3	)	(428.4	)
Proved reserves at December 31, 2014	3,149.6		130.8		70.8		4,359.6
Proved developed reserves:
December 31, 2012	2,170.7		23.7		64.9		2,702.6
December 31, 2013	2,265.2		36.8		48.6		2,777.7
December 31, 2014	2,090.0		60.0		43.9		2,713.8
Proved undeveloped reserves:
December 31, 2012	1,198.4		52.8		45.5		1,787.9
December 31, 2013	1,364.6		66.1		37.1		1,983.9
December 31, 2014	1,059.6		70.8		26.9		1,645.8

__________

(a) Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

• Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.

• Revisions in 2014 primarily reflect 97 Bcfe of net positive revisions to developed reserves and 422 Bcfe of net negative revisions to undeveloped reserves. The 422 Bcfe of net negative revisions were primarily due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules. Revisions in 2013 reflects 133 Bcfe related to developed reserves and 44 Bcfe related to undeveloped reserves. Revisions in 2012 primarily resulted from the lower 12-month average price as compared to the 12-month average price used in 2011.

• Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (See Note 4 of Notes to Consolidated Financial Statements). Divestitures in 2012 primarily relate to the sale of our holdings in the Barnett Shale and the Arkoma Basin (see Note 2 of Notes to Consolidated Financial Statements).

• Extensions and discoveries in 2014 reflect 189 Bcfe added for drilled locations and 502 Bcfe added for new proved undeveloped locations. Extensions and discoveries in 2013 reflects 127 Bcfe added for drilled locations and 407 Bcfe added for new undeveloped locations. The 2014 and 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin. Extensions and discoveries in 2012 reflect 225 Bcfe added for drilled locations and 405 Bcfe added for new undeveloped locations. The 2012 extensions and discoveries were primarily in the Williston Basin, Appalachian Basin and Piceance Basin.

114

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures—(Continued)

(Unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is based on the estimated quantities of proved reserves. Prices are based on the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years ended December 31, 2014, 2013 and 2012, the average domestic combined natural gas and NGL equivalent price was $4.34, $3.63 and $3.01 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2014, 2013 and 2012 was $83.62, $92.16 and $82.32 per barrel, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2014		2013
	(Millions)
Future cash inflows	$	26,444	$	24,547
Less:
Future production costs	12,641		12,148
Future development costs	3,426		3,789
Future income tax provisions	2,519		2,147
Future net cash flows	7,858		6,463
Less 10 percent annual discount for estimated timing of cash flows	3,975		3,499
Standardized measure of discounted future net cash inflows	$	3,883	$	2,964

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

	For the years ended December 31,
	2014			2013			2012
	(Millions)
Beginning of year	$	2,964		$	1,949		$	3,591
Sales of oil and gas produced, net of operating costs	(1,324		)	(1,040		)	(778		)
Net change in prices and production costs	303			1,198			(3,601		)
Extensions, discoveries and improved recovery, less estimated future costs	1,761			1,282			1,154
Development costs incurred during year	592			414			333
Changes in estimated future development costs	143			(736		)	50
Purchase of reserves in place, less estimated future costs	147			—			4
Sale of reserves in place, less estimated future costs	(391		)	(3		)	(272		)
Revisions of previous quantity estimates	(536		)	239			(232		)
Accretion of discount	383			225			481
Net change in income taxes	(142		)	(540		)	1,194
Other	(17		)	(24		)	25
Net changes	919			1,015			(1,642		)
End of year	$	3,883		$	2,964		$	1,949

115

WPX Energy, Inc.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

	Beginning Balance		Charged (Credited) to Costs and Expenses			Other		Deductions			Ending Balance
2014:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	7	$	—		$	—	$	(1	)	$	6
Deferred tax asset valuation allowance(b)	102		(1		)	17		—			118
Price-risk management credit reserves—assets(a)(c)	—		—			1		—			1
2013:
Allowance for doubtful accounts—accounts and notes receivable(a)	11		(3		)	—		(1		)	7
Deferred tax asset valuation allowance(b)	19		80			3		—			102
2012:
Allowance for doubtful accounts—accounts and notes receivable(a)	13		(2		)	—		—			11
Deferred tax asset valuation allowance(b)	16		3			—		—			19

__________

(a) Deducted from related assets.

(b) Deducted from related assets, with a portion included in assets held for sale.

(c) Included in revenues.

116

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure 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”) 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 also is 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 make modifications as necessary; our intent in this regard is that the Disclosure 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.

Management’s Annual Report on Internal Control over Financial Reporting

See report set forth in Item 8, “Financial Statements and Supplementary Data.”

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

See report set forth in Item 8, “Financial Statements and Supplementary Data.”

Fourth Quarter 2014 Changes in Internal Controls

There have been no changes during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

Item 9B. Other Information

None.

117

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information called for by this Item 10 is incorporated by reference to our definitive proxy statement for our 2015 Annual meeting of Stockholders, or our 2015 Proxy Statement, anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, under the headings “Proposal 1— Election of Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership and Reporting Compliance.”

Item 11. Executive Compensation

The information called for by this Item 11 is incorporated by reference to our 2015 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, under the headings “Executive Compensation” and “Compensation Interlocks and Insider Participation.”

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by this Item 12 is incorporated by reference to our 2015 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, under the headings “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.”

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information called for by this Item 13 is incorporated by reference to our 2015 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, under the headings “Corporate Governance” and “Certain Relationships and Transactions.”

Item 14. Principal Accountant Fees and Services

The information called for by this Item 14 is incorporated by reference to our 2015 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, under the heading “Independent Registered Public Accounting Firm.”

118

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1 and 2.

	Page
Covered by report of Independent Registered Public Accounting Firm:
Consolidated balance sheets at December 31, 2014 and 2013	69
Consolidated statements of operations for each year in the three-year period ended December 31, 2014	70
Consolidated statements of comprehensive income (loss) for each year in the three-year period ended December 31, 2014	71
Consolidated statements of changes in equity for each year in the three-year period ended December 31, 2014	72
Consolidated statements of cash flows for each year in the three-year period ended December 31, 2014	73
Notes to consolidated financial statements	74
Schedule for each year in the three-year period ended December 31, 2014:
II — Valuation and qualifying accounts	116
All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.
Not covered by report of independent auditors:
Quarterly financial data (unaudited)	108
Supplemental oil and gas disclosures (unaudited)	111

(a) 3 and (b). The exhibits listed below are filed as part of this annual report.

119

INDEX TO EXHIBITS

Exhibit No.	Description
2.1	Contribution Agreement, dated as of October 26, 2010, by and among Williams Production RMT Company, LLC, Williams Energy Services, LLC, Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and Williams Field Services Group, LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s registration statement on Form S-1/A (File No. 333-173808) filed with the SEC on July 19, 2011)
2.2**	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)
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 (File No. 001-35322) filed with the SEC on January 6, 2012)
3.2	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 (File No. 001-35322) filed with the SEC on November 15, 2013)
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)
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 (File No. 001-35322) 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 (File No. 001-35322) filed with the SEC on January 6, 2012)
10.4	Transition Services Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
10.5	Credit Agreement, dated as of June 3, 2011, by and among WPX Energy, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.3 to The Williams Companies, Inc.’s Current report on Form 8-K (File No. 001-04174) filed with the SEC on June 9, 2011)
10.6 #	Amended and Restated Gas Gathering, Processing, Dehydrating and Treating Agreement by and among Williams Field Services Company, LLC, Williams Production RMT Company, LLC, Williams Production Ryan Gulch LLC and WPX Energy Marketing, LLC, effective as of August 1, 2011 (incorporated herein by reference to Exhibit 10.7 to WPX Energy, Inc.’s registration statement on Form S-1/A (File No. 333-173808) filed with the SEC on July 19, 2011)
10.7	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 (File No. 001-35322) filed with the SEC on July 23, 2012)(1)
10.8	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 (File No. 001-35322) filed with the SEC on July 23, 2012)(1)

120

Exhibit No.	Description
10.9	First Amendment to the Credit Agreement, dated as of November 1, 2011, by and among WPX Energy, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.2 to The Williams Companies, Inc.’s Current report on Form 8-K (File No. 001-04174) filed with the SEC on November 1, 2011)
10.10	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 (File No. 001-35322) filed with the SEC on May 29, 2013)(1)
10.11	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)
10.12	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)
10.13*	Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers(1)
10.14*	Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers(1)
10.15	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.14 to WPX Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)(1)
10.16	Form of Stock Option Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2012)(1)
10.17	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)
10.18	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)
10.19	Agreement, dated December 17, 2013, between WPX Energy, Inc. and Taconic Capital Advisors LP (incorporated herein by reference to Exhibit 99.1 to WPX Energy, Inc.'s Current report on Form 8-K filed with the SEC on December 18, 2013).
10.20	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).
10.21	Severance Agreement, dated February 18, 2014, between WPX Energy, Inc. and Neal A. Buck (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.'s current report on Form 8-K filed with the SEC on February 19, 2014) (1)
10.22	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)
10.23	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)
10.24	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)
10.25	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)
10.26	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)

121

Exhibit No.	Description
10.27	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)
10.28	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)
10.29	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)
10.30	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)
10.31	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)
12*	Statement of Computation of Ratio of Earnings to Fixed Charges
21.1*	List of Subsidiaries
23.1*	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP
23.2*	Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
24.1*	Powers of Attorney
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
99.1*	Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
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

# Certain portions have been omitted pursuant to an Order Granting Confidential Treatment issued by the SEC on December 5, 2011. Omitted information has been filed separately with the SEC.

* 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

122

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: February 26, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Richard E. Muncrief	President, Chief Executive Officer and Director (Principal Executive Officer)	February 26, 2015
/s/ J. Kevin Vann	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 26, 2015
/s/ Stephen L. Faulkner	Controller (Principal Accounting Officer)	February 26, 2015
/s/ John A. Carrig*	Director	February 26, 2015
/s/ William R. Granberry*	Director	February 26, 2015
/s/ Robert K. Herdman*	Director	February 26, 2015
/s/ Kelt Kindick*	Director	February 26, 2015
/s/ Karl F. Kurz*	Director	February 26, 2015
/s/ Henry E. Lentz*	Director	February 26, 2015
/s/ George A. Lorch*	Director	February 26, 2015
/s/ William G. Lowrie*	Chairman of the Board	February 26, 2015
/s/ Kimberly S. Lubel*	Director	February 26, 2015
/s/ David F. Work*	Director	February 26, 2015

	/s/ Stephen E. Brilz
*By:	Attorney-in-Fact	February 26, 2015

123

EX-10.13

Exhibit 10.13

[Grant Date]

TO:[Participant Name]

FROM:Richard E. Muncrief

SUBJECT:2015 Restricted Stock Award

You have been selected to receive a restricted stock award. This award, which is subject to adjustment under the 2015 Restricted Stock Agreement (the “Agreement”) and the WPX Energy, Inc. 2013 Incentive Plan, is granted to you in recognition of your role as a key employee whose responsibilities and performance are critical to the attainment of long-term goals. It is granted and subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan, as amended and restated from time to time, and the Agreement.

Subject to all of the terms of the Agreement, you will become vested in one-third of this award if you are an active employee of the Company on each anniversary of the date on which this award is made until the award has been paid in full.

If you have any questions about this award, you may contact a dedicated Fidelity Stock Plan Representative at 1-800-544-9354.

1

WPX ENERGY, INC.

2015 TIME-BASED RESTRICTED STOCK AGREEMENT

THIS RESTRICTED STOCK AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Award referred to in the 2015 Restricted Stock Award Letter delivered in hard copy or electronically to Participant, is by and between WPX ENERGY, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1.Grant of Restricted Stock. Subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan or any successor plan, as amended and restated from time to time (the “Plan”), this Agreement, the Company hereby grants an award (the “Award”) to the Participant of [Number of Shares Granted] Shares of Restricted Stock, effective [Grant Date] (the “Effective Date”). The number ofShares of Restricted Stock is subject to adjustment under the terms of this Agreement and the Plan. The Shares of Restricted Stock shall be issued in the form of book entry shares in the name of the Participant as soon as reasonably practicable after the Effective Date, subject to the restrictions described in this Agreement and the Plan.

2.Incorporation of Plan and Acceptance of Documents. The Plan is incorporated by reference and all capitalized terms used herein which are not defined in this Agreement or in the attached Appendix shall have the respective meanings set forth in the Plan. The Participant acknowledges that he or she has received a copy of, or has online access to, the Plan and hereby automatically accepts the Shares of Restricted Stock subject to all the terms and provisions of the Plan and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the prospectus for the Plan and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3.Committee Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Committee, its delegates, or agents, upon any questions or other matters arising under the Plan or this Agreement.

4. Voting Rights; Dividends. Unless otherwise determined by the Committee in accordance with applicable law, from and after the Effective Date and prior to any forfeiture of the Shares of Restricted Stock, the Participant may: (i) exercise full voting rights with respect to the Shares of Restricted Stock; and (ii) receive, free of all restrictions, all cash dividends declared with respect to the Shares of Restricted Stock. Any shares of Common Stock of the Company issued with respect to the Shares of Restricted Stock in a stock dividend, stock split or similar event, shall only become vested and nonforfeitable in the same manner as the Shares of Restricted Stock in accordance with Paragraph 5, and shall be subject to all terms, restrictions and conditions described in this Agreement and the Plan that are applicable to the Shares of Restricted Stock.

5.Vesting; Legally Binding Rights.

(a)The Award shall not be vested as of the Effective Date and shall be forfeitable unless and until otherwise vested pursuant to the terms of this Agreement.

(b)Except as otherwise provided in Subparagraphs 5(c) - 5(g) below, the Participant shall vest in one-third of the Shares of Restricted Stock on the first anniversary of the Effective Date, in one-third of the Shares of Restricted Stock on the second anniversary of the Effective Date, and in the final one-third of the Shares of Restricted Stock on the third anniversary of the Effective Date (each such anniversary of the Effective Date, a “Maturity Date”), but only if the Participant remains an active employee of the Company or any of its Affiliates from the Effective Date through such Maturity Date. Because the Effective Date of the Participant’s award under this Agreement is [Grant Date], the Maturity Dates will be March 2, 2016,March 2, 2017, and March 2, 2018.

2

(c)If the Participant dies prior to the final Maturity Date while an active employee of the Company or any of its Affiliates, the Participant shall vest in all unvested Shares of Restricted Stock at the time of such death.

(d)If the Participant becomes Disabled prior to the final Maturity Date while an active employee of the Company or any of its Affiliates, the Participant shall vest in all unvested Shares of Restricted Stock at the time the Participant becomes Disabled.

(e)If the Participant experiences a Separation from Service prior to the final Maturity Date and within two years following a Change in Control, either voluntarily for Good Reason or involuntarily (other than due to Cause), the Participant shall vest in all unvested Shares of Restricted Stock upon such Separation from Service.

(f)If the Participant experiences an involuntary Separation from Service prior to the final Maturity Date and the Participant either receives benefits under a severance pay plan or program maintained by the Company or any of its Affiliates or receives benefits under a separation agreement with the Company or any of its Affiliates, the Participant shall vest in all unvested Shares of Restricted Stock upon such Separation from Service.

(g)If the Participant experiences an involuntary Separation from Service prior to the final Maturity Date due to a sale of a business or the outsourcing of any portion of a business, the Participant shall vest in all unvested Shares of Restricted Stock upon such Separation from Service, but only if the Company or any of its Affiliates failed to make an offer of comparable employment, as defined by a severance pay plan or program maintained by the Company or any of its Affiliates, to the Participant. For purposes of this Subparagraph 5(g), a Termination of Affiliation shall constitute an involuntary Separation from Service, excluding any Termination of Affiliation that results from a voluntary Separation from Service.

6. Delivery of Restricted Stock.

(a)Except as otherwise provided in Subparagraph 6(b), evidence of book entry shares with respect to Shares of Restricted Stock that have become vested under Paragraph 5 (other than Subparagraph 5(c)) or, if requested by the Participant prior to such vesting, a stock certificate with respect to such Shares of Restricted Stock, shall be delivered to the Participant as soon as practicable following the date on which the Participant becomes vested in such Shares of Restricted Stock and satisfies all other applicable conditions, including but not limited to the withholding obligations described in Paragraph 7.

(b) Evidence of book entry shares with respect to Shares of Restricted Stock that have become vested upon the Participant’s death pursuant to Subparagraph 5(c) or, if requested by the executors or administrators of the Participant’s estate upon vesting, a stock certificate with respect to such Shares of Restricted Stock, shall be delivered to the executors or administrators of the Participant’s estate as soon as practicable following the Company’s receipt of notification of the Participant’s death and the Participant’s estate’s satisfaction of all other applicable conditions, including but not limited to the withholding obligations described in Paragraph 7.

7. Withholding.

(a) Prior to the delivery to the Participant (or the Participant’s estate, if applicable) of evidence

3

of book entry shares or a stock certificate with respect to Shares of Restricted Stock that have become vested, the Company shall withhold a number of Shares of Restricted Stock, valued at their Fair Market Value on the date the withholding obligation arises, sufficient to satisfy all of the Company’s or any Affiliate’s federal, state and local tax withholding requirements related thereto but no more than the minimum amount necessary to satisfy such amounts (“Required Withholding”). The Company may instead require (i) the withholding of such Required Withholding from compensation otherwise due to the Participant or from any Shares, valued at their Fair Market Value on the date the withholding obligation arises, or from any other payment due to the Participant under the Plan or otherwise; (ii) payment of the Required Withholding by the Participant in cash; or (iii) that the Required Withholding be satisfied through any combination of the alternatives described in this Subparagraph 7(a).

(b) If the Participant makes an election under Section 83(b) of the Code (as described in Paragraph 10), the Company or any Affiliate shall be entitled to require (i) that the Grantee remit an amount in cash, or in the Company’s discretion, in Shares of Restricted Stock, valued at their Fair Market Value on the date the withholding obligation arises, sufficient to satisfy the resulting Required Withholding, (ii) the withholding of such Required Withholding from compensation otherwise due to the Participant or from any Shares or other payment due to the Participant under the Plan or otherwise or (iii) any combination of the foregoing.

8. Other Provisions.

(a)The Participant understands and agrees that Shares of Restricted Stock and any other payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice, or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan, or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

(b) The Participant agrees and understands that, upon receipt of Shares of Restricted Stock under this Agreement, stock certificates (or other indicia of ownership) issued may be held as collateral for monies he/she owes to Company or any of its Affiliates.

(c)Except as provided in Subparagraphs 5(c) - 5(g), in the event that the Participant experiences a Separation from Service prior to the Participant’s becoming vested in the Shares of Restricted Stock under this Agreement, the Shares of Restricted Stock subject to this Agreement shall be immediately forfeited and returned to the Company without payment of additional consideration.

(d) The Shares of Restricted Stock and the Participant’s interest in the Shares of Restricted Stock may not be sold, assigned, transferred, pledged or otherwise disposed of or encumbered at any time prior to the Shares of Restricted Stock becoming vested under this Agreement.

(e)The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Committee, its delegates or agents.

(f)The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Committee to allow or comply with a domestic relations order with respect to this Award.

(g)The Participant acknowledges that this Award and similar awards are made on a selective

4

basis and are, therefore, to be kept confidential.

(h)If the Participant at any time forfeits any or all of the Shares of Restricted Stock pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in such Shares of Restricted Stock hereunder shall terminate upon forfeiture without payment of consideration.

(i)The Committee shall determine whether an event has occurred resulting in the forfeiture of the Shares of Restricted Stock, in accordance with this Agreement, and all determinations of the Committee shall be final and conclusive.

(j)Nothing in this Agreement or the Plan shall interfere with or limit in any way the right of the Company or an Affiliate to terminate the Participant’s employment or service at any time, nor confer upon the Participant the right to continue in the employ of the Company and/or an Affiliate.

9.Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to WPX Energy, Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner. To direct the sale of any Shares issued under this Agreement, the Participant shall contact the Company’s stock plan administrator, which, as of the Grant Date, is Fidelity Stock Plan Services.

10.Section 83(b) Election for Restricted Stock Award; Tax Consultation. Under Section 83(a) of the Code, the Participant will generally be taxed on the Shares of Restricted Stock subject to this Award on the date such Shares of Restricted Stock vest and the forfeiture restrictions lapse, based on their fair market value on such date, at ordinary income rates. For this purpose, the term “forfeiture restrictions” means the right of the Company to receive back any Shares of Restricted Stock subject to this Award that have not vested upon a separation from service. Under Section 83(b) of the Code, the Participant may elect to be taxed on the Shares of Restricted Stock on the Effective Date, based upon their fair market value on such date, at ordinary income rates, rather than when and as the Shares of Restricted Stock that have not vested cease to be subject to the forfeiture restrictions. If the Participant elects to accelerate the date on which he or she is taxed on the Shares of Restricted Stock under Section 83(b), an election (an “83(b) Election”) to such effect must be filed with the Internal Revenue Service within 30 days from the Effective Date.

The Participant understands he or she will incur tax consequences as a result of acquisition or disposition of the Shares of Restricted Stock. The foregoing is only a summary of the federal income tax laws that apply to the Shares of Restricted Stock under this Agreement and does not purport to be complete. The actual tax consequences of receiving or disposing of the Shares of Restricted Stock are complicated and depend, in part, on the Participant’s specific situation and may also depend on the resolution of currently uncertain tax law and other variables not within the control of the Company. Therefore, the Participant agrees to consult with any tax consultants he or she thinks advisable in connection with the acquisition of the Shares of Restricted Stock and acknowledges that he or she is not relying, and will not rely, on the Company for any tax advice.

If the Participant decides to make an 83(b) Election, it is the Participant’s responsibility to file such an election with the Internal Revenue Service within the 30-day period after the Effective Date, to deliver to the Company a signed copy of the 83(b) Election, and to file an additional copy of such election form with his or her federal income tax return for the calendar year in which the Effective Date occurs.

5

WPX ENERGY, INC.

By:_________________________

Richard E. Muncrief

Chief Executive Officer

Participant: [Participant Name]

6

APPDENDIX

DEFINITIONS

“Affiliate” means all persons with whom the Company would be considered a single employer under Section 414(b) of the Code and all persons with whom the Company would be considered a single employer under Section 414(c) of the Code.

“Disabled” means a Participant qualifies for long-term disability benefits under the Company’s long-term disability plan, or if the Company does not sponsor such a disability plan, the Participant qualifies for Social Security Disability Insurance under Title II of the Social Security Act.

“Separation from Service” means a Participant’s termination or deemed termination from employment with the Company and its Affiliates. For purposes of determining whether a Separation from Service has occurred, the employment relationship is treated as continuing intact while the Participant is on military leave, sick leave, or other bona fide leave of absence if the period of such leave does not exceed six months, or if longer, so long as the Participant retains a right to reemployment with his or her employer under an applicable statute or by contract. For this purpose, a leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the Participant will return to perform services for his or her employer. If the period of leave exceeds six months and the Participant does not retain a right to reemployment under an applicable statute or by contract, the employment relationship will be deemed to terminate on the first date immediately following such six month period.

Notwithstanding the foregoing, if a leave of absence is due to any medically determinable physical or mental impairment that can be expected to last for a continuous period of more than six months but less than 12 months, and such impairment causes the Participant to be unable to perform the duties of the Participant’s position of employment or any substantially similar position of employment, a period equal to such Participant’s leave of absence will be substituted for such six-month period, so long as that period is less than 12 months. If such an absence exceeds 12 months, then the Participant will be considered Disabled and Subparagraph 5(d) will govern.

A Separation from Service occurs at the date as of which the facts and circumstances indicate either that, after such date: (A) the Participant and the Company reasonably anticipate the Participant will perform no further services for the Company and its Affiliates (whether as an employee or an independent contractor) or (B) that the level of bona fide services the Participant will perform for the Company and its Affiliates (whether as an employee or independent contractor) will permanently decrease to no more than 20% of the average level of bona fide services performed over the immediately preceding 36-month period or, if the Participant has been providing services to the Company and its Affiliates for less than 36 months, the full period over which the Participant has rendered services, whether as an employee or independent contractor.

7

EX-10.14

Exhibit 10.14

[Grant Date]

TO:[Participant Name]

FROM:Richard E. Muncrief

SUBJECT:2015 Restricted Stock Unit Award

You have been selected to receive a restricted stock unit award. This award, which is subject to adjustment under the 2015 Restricted Stock Unit Agreement (the “Agreement”) and the WPX Energy, Inc. 2013 Incentive Plan, is granted to you in recognition of your role as a key employee whose responsibilities and performance are critical to the attainment of long-term goals. This award and similar awards are made on a selective basis and are, therefore, to be kept confidential. It is granted and subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan, as amended and restated from time to time, and the Agreement.

Subject to all of the terms of the Agreement, you will become entitled to payment of 1/3 of this award if you are an active employee of the Company on each anniversary of the date on which this award is made until the award has been paid in full. The provisions related to your rights, if any, associated with this award upon your termination of employment are included in the Agreement.

If you have any questions about this award, you may contact a dedicated Fidelity Stock Plan Representative at 1-800-544-9354.

1

WPX ENERGY, INC.

2015 TIME-BASED RESTRICTED STOCK UNIT AGREEMENT

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Units (“Restricted Stock Units” or “RSUs”) referred to in the 2015 Restricted Stock Unit Award Letter delivered in hard copy or electronically to Participant, is by and between WPX ENERGY, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1.Grant of RSUs. Subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan or any successor plan, as amended and restated from time to time (the “Plan”), and this Agreement, the Company hereby grants an award (the “Award”) to the Participant of [Number of Shares Granted] RSUs effective [Grant Date] (the “Effective Date”). The Award gives the Participant the opportunity to earn the right to receive the number ofshares of the Common Stock of the Company equal to the number of RSUs shown in the prior sentence, subject to adjustment under the terms of this Agreement and the Plan. These shares are referred to in this Agreement as the “Shares.” Until the Participant both becomes vested in the Shares under the terms of Paragraph 4 and is paid such Shares under the terms of Paragraph 5, the Participant shall have no rights as a stockholder of the Company with respect to the Shares.

2.Incorporation of Plan and Acceptance of Documents. The Plan is incorporated by reference and all capitalized terms used herein which are not defined in this Agreement or in the attached Appendix shall have the respective meanings set forth in the Plan. The Participant acknowledges that he or she has received a copy of, or has online access to, the Plan and hereby automatically accepts the RSUs subject to all the terms and provisions of the Plan and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the prospectus for the Plan and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3.Committee Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Committee, its delegates, or agents, upon any questions or other matters arising under the Plan or this Agreement.

4.Vesting; Legally Binding Rights.

(a)Notwithstanding any other provision of this Agreement, the Participant shall not be entitled to any payment of Shares under this Agreement unless and until the Participant obtains a legally binding right to such Shares and satisfies applicable vesting conditions for such payment.

(b)Except as otherwise provided in Subparagraphs 4(c) - 4(g) below, the Participant shall vest in one-third of the Shares on the first anniversary of the Effective Date, in one-third of the Shares on the second anniversary of the Effective Date, and in the final one-third of the Shares on the third anniversary of the Effective Date (each such anniversary of the Effective Date, a “Maturity Date”), but only if the Participant remains an active employee of the Company or any of its Affiliates from the Effective Date through such Maturity Date. Because the Effective Date of the Participant’s award under this Agreement is [Grant Date], the Maturity Dates will be March 2, 2016,March 2, 2017, and March 2, 2018.

(c)If the Participant dies prior to the final Maturity Date while an active employee of the Company or any of its Affiliates, the Participant shall vest in all unvested Shares at the time of such death.

(d)If the Participant becomes Disabled prior to the final Maturity Date while an active employee of the Company or any of its Affiliates, the Participant shall vest in all unvested Shares at the time the Participant

2

becomes Disabled.

(e)If the Participant experiences a Separation from Service prior to the final Maturity Date and within two years following a Change in Control, either voluntarily for Good Reason or involuntarily (other than due to Cause), the Participant shall vest in all unvested Shares upon such Separation from Service.

(f)If the Participant experiences an involuntary Separation from Service prior to the final Maturity Date and the Participant either receives benefits under a severance pay plan or program maintained by the Company or any of its Affiliates or receives benefits under a separation agreement with the Company or any of its Affiliates, the Participant shall vest in all unvested Shares upon such Separation from Service.

(g)If the Participant experiences an involuntary Separation from Service prior to the final Maturity Date due to a sale of a business or the outsourcing of any portion of a business, the Participant shall vest in all unvested Shares upon such Separation from Service, but only if the Company or any of its Affiliates failed to make an offer of comparable employment, as defined by a severance pay plan or program maintained by the Company or any of its Affiliates, to the Participant. For purposes of this Subparagraph 4(g), a Termination of Affiliation shall constitute an involuntary Separation from Service, excluding any Termination of Affiliation that results from a voluntary Separation from Service.

5. Payment of Shares.

(a)Payment of all Shares in which the Participant becomes vested pursuant to Subparagraph 4(b) above shall occur within 30 days following a Maturity Date.

(b) Payment of all Shares in which the Participant becomes vested pursuant to Subparagraph 4(c) above shall occur within 60 days following the Participant’s death.

(c)Payment of all shares in which the Participant becomes vested pursuant to Subparagraph 4(d) above shall occur within 30 days after the Participant is determined to be Disabled.

(d)Payment of all Shares in which the Participant becomes vested pursuant to Subparagraphs 4(e), 4(f), and 4(g) above shall occur within 30 days following such Participant’s Separation from Service.

(e)Upon conversion of RSUs into Shares under this Agreement, such RSUs shall be cancelled. Shares that become payable under this Agreement will be paid by the Company by the delivery to the Participant, or the Participant’s beneficiary or legal representative, of one or more certificates (or other indicia of ownership) representing shares of Common Stock equal in number to the number of Shares otherwise payable under this Agreement less the number of Shares having a Fair Market Value, as of the date the withholding tax obligation arises, equal to the minimum statutory withholding requirements. Notwithstanding the foregoing, to the extent permitted by Section 409A of the Code and the guidance issued by the Internal Revenue Service thereunder (if and to the extent applicable), if federal employment taxes become due when the Participant becomes entitled to payment of Shares, the number of Shares necessary to cover minimum statutory withholding requirements may, in the discretion of the Company, be used to satisfy such requirements upon such entitlement.

6. Other Provisions.

(a)The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice, or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any

3

employment agreement, any change of control severance protection plan, or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

(b)The Participant agrees and understands that, subject to the limit expressed in clause (iii) of the following sentence, upon payment of Shares under this Agreement, stock certificates (or other indicia of ownership) issued may be held as collateral for monies he/she owes to the Company or any of its Affiliates. In addition, the Company may accelerate the time or schedule of a payment of vested Shares, and/or deduct from any payment of Shares to the Participant under this Agreement, or to his or her beneficiaries in the case of the Participant’s death, that number of Shares having a Fair Market Value at the date of such deduction equal to the amount of such debt as satisfaction of any such debt, provided that (i) such debt is incurred in the ordinary course of the employment relationship between the Company or any of its Affiliates and the Participant, (ii) the aggregate amount of any such debt-related collateral held or deduction made in any taxable year of the Company with respect to the Participant does not exceed $5,000, and (iii) the deduction of Shares is made at the same time and in the same amount as the debt otherwise would have been due and collected from the Participant.

(c)Except as provided in Subparagraphs 4(c) through 4(g) above, in the event that the Participant experiences a Separation from Service prior to the Participant’s becoming vested in the Shares under this Agreement, RSUs subject to this Agreement and any right to Shares issuable hereunder shall be forfeited.

(d)The Participant acknowledges that this Award and similar awards are made on a selective basis and are, therefore, to be kept confidential.

(e)RSUs, Shares, and the Participant’s interest in RSUs and Shares may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered at any time prior to both (i) the Participant’s becoming vested in such Shares and (ii) payment of such Shares under this Agreement.

(f)If the Participant at any time forfeits any or all of the RSUs pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in such RSUs and in Shares issuable hereunder shall terminate upon forfeiture without payment of consideration.

(g)The Committee shall determine whether an event has occurred resulting in the forfeiture of the Shares, in accordance with this Agreement, and all determinations of the Committee shall be final and conclusive.

(h)With respect to the right to receive payment of the Shares under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

(i)The obligations of the Company under this Agreement are unfunded and unsecured. Each Participant shall have the status of a general creditor of the Company with respect to amounts due, if any, under this Agreement.

(j)The parties to this Agreement intend that this Agreement satisfies the requirements of the short-term deferral exception from Section 409A of the Code and, if not excepted, complies with the applicable requirements of Section 409A of the Code. This Agreement reflects certain provisions of Section 409A of the Code or regulations issued thereunder for purposes of defining certain terms and requirements. Such references shall not be construed to cause the Agreement to be subject to Section 409A of the Code or to conflict with the parties’ intent that this agreement satisfies the requirements of the short-term deferral exception. The parties recognize that it may be necessary to modify this Agreement and/or the

4

Plan to maintain the Plan’s exception from Section 409A of the Code or to otherwise reflect guidance under Section 409A of the Code issued by the Internal Revenue Service. Participant agrees that the Committee shall have sole discretion in determining (i) whether any such modification is desirable or appropriate and (ii) the terms of any such modification.

(k)The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Committee, its delegates or agents.

(l)Nothing in this Agreement or the Plan shall interfere with or limit in any way the right of the Company or an Affiliate to terminate the Participant’s employment or service at any time, nor confer upon the Participant the right to continue in the employ of the Company and/or an Affiliate.

(m)The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Committee to allow or comply with a domestic relations order with respect to this Award.

7.Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to WPX Energy, Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner. To direct the sale of any Shares issued under this Agreement, the Participant shall contact the Company’s stock plan administrator, which, as of the Grant Date, is Fidelity Stock Plan Services.

8.Tax Consultation. The Participant understands he or she will incur tax consequences as a result of acquisition or disposition of the Shares. The Participant agrees to consult with any tax consultants deemed advisable in connection with the acquisition of the Shares and acknowledges that he or she is not relying, and will not rely, on the Company or any of its Affiliates for any tax advice.

WPX ENERGY, INC.

By:_________________________

Richard E. Muncrief

Chief Executive Officer

Participant: [Participant Name]

5

APPDENDIX

DEFINITIONS

“Affiliate” means all persons with whom the Company would be considered a single employer under Section 414(b) of the Code and all persons with whom the Company would be considered a single employer under Section 414(c) of the Code.

“Disabled” means a Participant qualifies for long-term disability benefits under the Company’s long-term disability plan, or if the Company does not sponsor such a disability plan, the Participant qualifies for Social Security Disability Insurance under Title II of the Social Security Act. Notwithstanding the forgoing, the definition of “Disabled” shall comply with the requirements of the definition of “disabled” described in Treasury Regulation § 1.409A-3(i)(4), as amended.

“Separation from Service” means a Participant’s termination or deemed termination from employment with the Company and its Affiliates. For purposes of determining whether a Separation from Service has occurred, the employment relationship is treated as continuing intact while the Participant is on military leave, sick leave, or other bona fide leave of absence if the period of such leave does not exceed six months, or if longer, so long as the Participant retains a right to reemployment with his or her employer under an applicable statute or by contract. For this purpose, a leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the Participant will return to perform services for his or her employer. If the period of leave exceeds six months and the Participant does not retain a right to reemployment under an applicable statute or by contract, the employment relationship will be deemed to terminate on the first date immediately following such six month period.

Notwithstanding the foregoing, if a leave of absence is due to any medically determinable physical or mental impairment that can be expected to last for a continuous period of more than six months but less than 12 months, and such impairment causes the Participant to be unable to perform the duties of the Participant’s position of employment or any substantially similar position of employment, a period equal to such Participant’s leave of absence will be substituted for such six-month period, so long as that period is less than 12 months. If such an absence exceeds 12 months, then the Participant will be considered Disabled and Subparagraph 4(d) will govern.

A Separation from Service occurs at the date as of which the facts and circumstances indicate either that, after such date: (A) the Participant and the Company reasonably anticipate the Participant will perform no further services for the Company and its Affiliates (whether as an employee or an independent contractor) or (B) that the level of bona fide services the Participant will perform for the Company and its Affiliates (whether as an employee or independent contractor) will permanently decrease to no more than 20% of the average level of bona fide services performed over the immediately preceding 36-month period or, if the Participant has been providing services to the Company and its Affiliates for less than 36 months, the full period over which the Participant has rendered services, whether as an employee or independent contractor. The determination of whether a Separation from Service has occurred shall be governed by the provisions of Treasury Regulation § 1.409A-1, as amended, taking into account the objective facts and circumstances with respect to the level of bona fide services performed by the Participant after a certain date.

6

EX-12

Exhibit 12

WPX Energy, Inc.

Computation of Ratio of Earnings to Fixed Charges

	Years Ended December 31,
	2014			2013			2012			2011			2010
	(Millions)
Earnings:
Income (loss) from continuing operations before income taxes	$	204		$	(1,728	)	$	(258	)	$	181		$	(886	)
Less: Equity earnings, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees	(5		)	(4		)	(4		)	(4		)	(4		)
Income (loss) from continuing operations before income taxes and equity earnings	199			(1,732		)	(262		)	177			(890		)
Add:
Fixed charges:
Interest accrued, including proportionate share from 50% owned investees and unconsolidated majority-owned investees (a)	123			108			102			118			124
Rental expense representative of interest factor	6			5			5			3			4
Total fixed charges	129			113			107			121			128
Distributed income of equity-method investees, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees	4			3			4			4			4
Less:
Capitalized interest	(2		)	(1		)	(2		)	(1		)	(1		)
Total earnings as adjusted	$	330		$	(1,617	)	$	(153	)	$	301		$	(759	)
Fixed charges	$	129		$	113		$	107		$	121		$	128
Ratio of earnings to fixed charges	2.56			(b)			(c)			2.49			(d)

 __________

(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 taxes in our Consolidated Statements of Operations.

(b) Earnings are inadequate to cover fixed charges by $1,730 million.

(c) Earnings are inadequate to cover fixed charges by $260 million.

(d) Earnings are inadequate to cover fixed charges by $887 million.

EX-21.1

Exhibit 21.1

List of Subsidiaries of WPX Energy, Inc.

(all Delaware entities unless otherwise indicated)

1. Barrett Resources International Corporation

2. Bison Royalty LLC

3. Diamond Elk, LLC – a Colorado limited liability company

4. Mockingbird Pipeline, L.P.

5. RW Gathering, LLC

6. SW Gathering, LLC

7. WPX Energy Appalachia, LLC

10. WPX Energy Arkoma Gathering, LLC

11. WPX Enterprises, Inc.

12. WPX Energy Gulf Coast, LP

Assumed name in Texas: Williams Prod. Gulf Coast, L.P.

13. WPX Energy Holdings, LLC

14. WPX Energy Keystone, LLC

15. WPX Energy Marcellus Gathering, LLC

16. WPX Energy Mid-Continent Company, an Oklahoma corporation

17. WPX Energy Production, LLC

Fictitious name in Oklahoma: WEG-Production Company, LLC

18. WPX Energy Rocky Mountain, LLC

19. WPX Energy RM Company

20. WPX Energy Marketing, LLC

21. WPX Energy Marketing Services Company, LLC

22. WPX Energy Services Company, LLC

23. WPX Energy Van Hook Gathering Services, LLC

24. WPX Energy Williston, LLC

Trade name in North Dakota: D3 E & P LLC

25. WPX Gas Resources Company

26. Minuteman Exploration, LLC

27. Minuteman Holding, LLC

28. Betterit Land & Title Holding Company, LLC – a New Mexico Limited Liability Company

Fictitious name in Oklahoma: WPX Energy Chaco Slope, LLC

International subsidiaries:

1. WPX Energy International Oil & Gas (Venezuela), Ltd. – a Cayman Islands corporation

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No 333-198523) and related Prospectus of WPX Energy, Inc. pertaining to the registration of debt securities

(2) Registration Statement (Form S-3 No 333-197905) and related Prospectus of WPX Energy, Inc. pertaining to the registration of 481,157 shares of its common stock

(3) Registration Statement (Form S-8 No 333-188767) pertaining to the WPX Energy, Inc. 2013 Incentive Plan

(4) Registration Statement (Form S-8 No 333-178388) and the related post-effective amendment No. 1 pertaining to the WPX Energy, Inc. 2011 Incentive Plan and the WPX Energy, Inc. 2011 Employee Stock Purchase Plan

of our report dated February 26, 2015 with respect to the consolidated financial statements and schedule of WPX Energy, Inc. and the effectiveness of internal control over financial reporting of WPX Energy, Inc., included in this Annual Report (Form 10-K) of WPX Energy, Inc. for the year ended December 31, 2014.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2015

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to the references to and the filing and incorporation by reference of our audit letter as of December 31, 2014, included in or made part of the Annual Report on Form 10-K of WPX Energy, Inc. for the year ended December 31, 2014. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, and of our audit letter as of December 31, 2014, and references thereto, into WPX Energy, Inc.'s Registration Statements on Form S-8 (No.'s 333-178388 and 333-188767 and Post-Effective Amendment No. 1 to Registration Statement No. 333-178388 on Form S-8) and Form S-3 (No.'s 333-197905 and 333-198523).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

Dallas, Texas

February 26, 2015

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-24.1

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned individuals, in his or her capacity as a director of WPX Energy, Inc., a Delaware corporation (“WPX Energy”), does hereby constitute and appoint each of Dennis C. Cameron and Stephen E. Brilz as his or her true and lawful attorney-in-fact, with full power and authority to sign WPX Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, and any and all amendments thereto or any and all instruments necessary or incidental in connection therewith. Each said attorney-in-fact shall have full power of substitution, and each said attorney-in-fact shall have full power and authority to do and perform in the name and on behalf of each of the undersigned, in any and all capacities, every act whatsoever requisite or necessary to be done in or about the premises, as fully to all intents and purposes as each of the undersigned might or could do in person, the undersigned hereby ratifying and approving the acts of said attorney-in-fact.

This power of attorney has been duly executed below by the following persons as of the 26^th day of February, 2015.

/s/ John A. Carrig	/s/ William R. Granberry
John A. Carrig	William R. Granberry
/s/ Robert K. Herdman	/s/ Karl F. Kurz
Robert K. Herdman	Karl F. Kurz
/s/ Kelt Kindick	/s/ Henry E. Lentz
Kelt Kindick	Henry E. Lentz
/s/ George A. Lorch	/s/ William G. Lowrie
George A. Lorch	William G. Lowrie
/s/ Kimberly S. Lubel	/s/ David F. Work
Kimberly S. Lubel	David F. Work

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Richard E. Muncrief, certify that:

1. I have reviewed this annual report on Form 10-K 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 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: February 26, 2015

/s/ Richard E. Muncrief

Richard E. Muncrief

Chief Executive Officer

(Principal Executive Officer)

EX-31.1

Exhibit 31.2

SECTION 302 CERTIFICATION

I, J. Kevin Vann, certify that:

1.I have reviewed this annual report on Form 10-K 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 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: February 26, 2015

/s/ J. Kevin Vann

J. Kevin Vann

Chief Financial Officer

(Principal 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 Annual Report of WPX Energy, Inc. (the “Company”) on Form 10-K for the period ending December 31, 2014, 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

Chief Executive Officer

February 26, 2015

/s/ J. Kevin Vann

J. Kevin Vann

Senior Vice President and Chief Financial Officer

February 26, 2015

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.

EX-99.1

Exhibit 99.1

February 23, 2015

Director of Reserves and Production Services

WPX Energy, Inc.

One Williams Center, Suite 3600

Tulsa, Oklahoma 74172

Dear Sir or Madam:

In accordance with your request, we have audited the estimates prepared by WPX Energy, Inc. and its subsidiaries WPX Energy Production, LLC; WPX Energy Rocky Mountain, LLC; WPX Energy RM Company; and WPX Energy Williston, LLC (collectively referred to herein as "WPX"), as of December 31, 2014, of the proved reserves and future revenue to the WPX interest in certain oil and gas properties located in the United States. It is our understanding that the proved reserves estimated herein constitute approximately 88 percent of all proved reserves owned by WPX. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for WPX's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth WPX's estimates of the net reserves and future net revenue, as of December 31, 2014, for the audited properties:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed	59,618	43,678	1,750,233	6,043,276	3,540,798
Proved Undeveloped	70,807	26,885	888,142	3,628,774	1,046,418
Total Proved	130,424	70,564	2,638,375	9,672,051	4,587,216

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a well-by-well basis, some of the estimates of WPX are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates of WPX's proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by WPX in preparing the December 31, 2014, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by WPX.

The estimates shown herein are for proved reserves. WPX's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by WPX are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by area for basis differentials and by lease for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by area for basis differentials and by lease for energy content, transportation fees, market differentials, and, as appropriate, plant shrinkage. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $83.62 per barrel of oil, $40.36 per barrel of NGL, and $4.010 per MCF of gas.

Operating costs used by WPX are based on historical operating expense records. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of WPX are included to the extent that they are covered under joint operating agreements for the operated properties. Capital costs used by WPX are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Operating costs and capital costs are not escalated for inflation. Estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of WPX and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by WPX, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by WPX with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of WPX's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the

conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by WPX, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Dan Paul Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1980 and has over 7 years of prior industry experience. John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
	/s/ Dan Paul Smith		/s/ John G. Hattner
By:		By:
	Dan Paul Smith, P.E. 49093		John G. Hattner, P.G. 559
	Senior Vice President		Senior Vice President
Date Signed: February 23, 2015		Date Signed: February 23, 2015

DPS:JSB

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

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

	December 31, 2014								December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(Millions)								(Millions)
Energy derivative assets	$	14	$	517	$	5	$	536	$	30	$	26	$	1	$	57
Energy derivative liabilities	$	32	$	10	$	—	$	42	$	83	$	38	$	1	$	122
Total debt(a)	$	—	$	2,218	$	—	$	2,218	$	—	$	1,938	$	—	$	1,938

__________

(a) The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

	Years ended December 31,
	2014		2013			2012
	(Millions)
Beginning balance	$	—	$	(1	)	$	1
Realized and unrealized gains (losses):
Included in income (loss) from continuing operations	5		(2		)	3
Included in other comprehensive income (loss)	—		—			—
Purchases, issuances, and settlements	—		3			(5		)
Transfers out of Level 3	—		—			—
Ending balance	$	5	$	—		$	(1	)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	5	$	(1	)	$	(1	)

Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy

The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

	Total losses for the years ended December 31,
	2014 (a)		2013 (b)		2012 (c)
	(Millions)
Impairments:
Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)	$	20	$	1,055	$	225
Unproved leasehold	—		317		—
Equity method investment (Note 4)	—		20		—
	$	20	$	1,392	$	225

__________

(a) As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:

• $11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.

• $9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

(b) As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:

• $792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.

• $317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.

• $107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.

• $88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

• $85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

(c) As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:

• $102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

• $48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

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

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Earnings (Loss) Per Common Share from Continuing Operations (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$ 227	$ 46	$ (144)	$ 0	$ (878)	$ (105)	$ 6	$ (115)	$ 129	$ (1,092)		$ (174)
Basic weighted-average shares									202.7	200.5		198.8
Diluted weighted-average shares									206.3	200.5	[1]	198.8	[1]
Earnings (loss) per common share from continuing operations:
Basic (in dollars per share)	$ 1.11	$ 0.23	$ (0.71)	$ 0.00					$ 0.63	$ (5.45)		$ (0.87)
Diluted (in dollars per share)	$ 1.10	$ 0.23	$ (0.71)	$ 0.00					$ 0.62	$ (5.45)		$ (0.87)
Nonvested Restricted Stock Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements									2.7	2.5		1.1
Stock Options
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements									0.9	1.9		1.0

[1] For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

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

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

[1] Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

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

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

[1] (a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.

[2] (a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

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Properties and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Properties and Equipment, at Cost

Properties and equipment is carried at cost and consists of the following:

	Estimated Useful Life(a) (Years)	December 31,
		2014			2013
		(Millions)
Proved properties	(b)	$	10,386		$	10,955
Unproved properties	(c)	394			316
Gathering, processing and other facilities	15-25	251			209
Construction in progress	(c)	541			353
Other	3-40	181			178
Total properties and equipment, at cost		11,753			12,011
Accumulated depreciation, depletion and amortization		(4,911		)	(5,251		)
Properties and equipment—net		$	6,842		$	6,760

__________

(a) Estimated useful lives are presented as of December 31, 2014.

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

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

Rollforward of Asset Retirement Obligation

A rollforward of our asset retirement obligations for the years ended 2014 and 2013 is presented below.

	2014			2013
	(Millions)
Balance, January 1	$	308		$	261
Liabilities incurred	19			11
Liabilities settled	(2		)	(1		)
Liabilities associated with assets sold	(65		)	—
Estimate revisions	(78		)	17
Accretion expense(a)	19			20
Balance, December 31	$	201		$	308
Amount reflected as current	$	3		$	3

__________

(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

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

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Stock-Based Compensation - Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted-average or grant date fair value of options granted	$ 18.94	$ 6.04	$ 7.79
Dividend yield	0.00%	0.00%	0.00%
Volatility	43.00%	42.80%	43.80%
Risk-free interest rate	1.85%	1.06%	1.17%
Expected life	5 years 10 months 24 days	6 years	6 years

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Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
Standard & Poor's
Credit Exposure From Derivatives [Line Items]
Counterparties credit rating in investment grade	BBB-
Moody's Investors Service
Credit Exposure From Derivatives [Line Items]
Counterparties credit rating in investment grade	Baa3

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

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

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

[1] With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

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Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of producing properties and costs of acquired unproved reserves	$ 11	$ 365		$ 351
Weighted average natural gas price	4.34	3.63		3.01
Unproved leasehold property impairment, amortization and expiration	74	402		58
Unproved Leasehold Property Impairment	0	317	[1]	0
Equity method investment (Note 4)	0	20	[1]	0
Asset Impairment Charges Including Discontinued Operations	20	1,392		225
Probable Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax				13.00%
Possible Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax				15.00%
Green River Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge	11
Green River Basin | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge				48
Weighted average natural gas price	4.77			5.87
Percentage of discount rate after-tax				11.00%
Green River Basin | Producing Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax	9.00%
Green River Basin | Undeveloped Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax	11.00%
Green River Basin | Minimum | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved reserve quantities of gas equivalent	23,000,000			29,000,000
Appalachian Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge Including Equity Method Investment		792
Impairment Charge		772
Unproved leasehold property impairment, amortization and expiration		317
Appalachian Basin | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Weighted average natural gas price		3.60
Percentage of discount rate after-tax		11.00%
Appalachian Basin | Minimum | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved reserve quantities of gas equivalent		299,000,000
Powder River Basin
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment Charge		107		102
Impairment of producing properties and costs of acquired unproved reserves		85
Powder River Basin | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Weighted average natural gas price		3.53
Percentage of discount rate after-tax		11.00%
Powder River Basin | Probable Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax		15.00%
Powder River Basin | Possible Reserves | Unproved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax		18.00%
Powder River Basin | Minimum | Proved Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved reserve quantities of gas equivalent		294,000,000
Piceance
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of producing properties and costs of acquired unproved reserves		88		75
Piceance | Probable Reserves
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax		13.00%
Piceance | Possible Reserves
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of discount rate after-tax		15.00%
Other Member
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of producing properties and costs of acquired unproved reserves	$ 9

[1] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

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

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

[1] The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.

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

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Supplemental Oil and Gas Disclosures

12 Months Ended

Dec. 31, 2014

Extractive Industries [Abstract]

Supplemental Oil and Gas Disclosures

We have significant continuing oil and gas producing activities primarily in the Piceance and San Juan Basins in the Rocky Mountain region and the Williston Basin in North Dakota, all of which are located in the United States. Until January 2015, we had international oil and gas producing activities, primarily in Argentina which were previously reported as a segment. The international activities were held for sale as of December 31, 2014 and as such, our international results of operations were reported as discontinued operations (see Note 2 of Notes to Consolidated Financial Statements). International net proved reserves, including amounts related to an equity method investment, were approximately 213 Bcfe or less than 5 percent of our total domestic and international reserves at December 31, 2014. Other than noted below, the following information relates to our domestic oil and gas activities and excludes our gas management activities.

With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information for the Powder River Basin and, through the date of sale in 2012, the holdings in the Barnett Shale and Arkoma Basin both of which have been reported as discontinued operations in our consolidated financial statements. The Powder River Basin operations represent less than 5 percent of our total domestic proved reserves at December 31, 2014. Additionally, capitalized costs exclude amounts related to assets in our Appalachian Basin which were held for sale as of December 31, 2014. Our Appalachian Basin assets held for sale represented less than 5 percent of our total domestic proved reserves.

Capitalized Costs

	As of December 31,
	2014			2013
	(Millions)
Proved Properties	$	10,717		$	11,132
Unproved properties	394			324
	11,111			11,456
Accumulated depreciation, depletion and amortization and valuation provisions	(4,698		)	(5,070		)
Net capitalized costs	$	6,413		$	6,386

• Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $385 million and $328 million, net, for 2014 and 2013, respectively.

• Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.

• Unproved properties consist primarily of unproved leasehold costs.

Cost Incurred

	For the years ended December 31,
	2014		2013		2012
	(Millions)
Acquisition	$	294	$	57	$	111
Exploration	92		104		23
Development	1,376		939		1,130
	$	1,762	$	1,100	$	1,264

• Costs incurred include capitalized and expensed items.

• Acquisition costs are as follows: Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include 28 Bcfe of proved reserves. The 2013 and 2012 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves.

• Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.

• Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.

Results of Operations

	For the years ended December 31,
	2014		2013			2012
	(Millions)
Revenues:
Natural gas sales	$	1,002	$	896		$	1,193
Oil and condensate sales	724		534			376
Natural gas liquid sales	205		228			297
Net gain (loss) on derivatives not designated as hedges	515		(57		)	66
Other revenues	8		6			7
Total revenues	2,454		1,607			1,939
Costs:
Lease and facility operating	244		227			202
Gathering, processing and transportation	328		350			434
Taxes other than income	126		102			68
Exploration	173		423			71
Depreciation, depletion and amortization	810		858			884
Impairment of certain proved properties	15		772			48
Impairment of costs of acquired unproved reserves	5		88			75
Loss on sale of working interests in the Piceance Basin	196		—			—
General and administrative	264		262			259
Other (income) expense	12		12			16
Total costs	2,173		3,094			2,057
Results of operations	281		(1,487		)	(118		)
Provision (benefit) for income taxes	103		(543		)	(43		)
Exploration and production net income (loss)	$	178	$	(944	)	$	(75	)

• Amounts for all years exclude the equity losses from our equity method investees. Net equity losses from these investees were $1 million, $21 million and $1 million in 2014, 2013 and 2012, respectively.

• Natural gas revenues consist of natural gas production sold and 2012 includes realized gains (losses) of derivatives that were designated as cash flow hedges.

• For derivative instruments that were entered into after January 1, 2012, we did not designate those as cash flow hedges. Any gain (loss) related to these derivatives is included in net gain on derivatives not designated as hedges.

• Other revenues consist of activities that are an indirect part of the producing activities.

• Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2014 include impairments of certain exploratory well costs (see Note 4 of Notes to Consolidated Financial Statements). Exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachian Basin.

• Depreciation, depletion and amortization includes depreciation of support equipment.

Proved Reserves

The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.

The following is a summary of changes in our domestic proved reserves including proved reserves in the Powder River Basin which is reported as discontinued operations. Proved reserves related to Powder River were approximately 200 Bcfe, 244.6 Bcfe and 235.9 Bcfe at December 31, 2014, 2013 and 2012, respectively. Excluded from the table are our international reserves that are primarily attributable to a consolidated subsidiary (Apco) which represented less than five percent of our total reserves. The international interests were sold in January 2015.

	Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		All Products (Bcfe)
Proved reserves at December 31, 2011	3,982.9		47.1		134.0		5,070.1
Revisions	(404.8	)	5.6		(21.1	)	(498.6	)
Purchases	5.8		—		—		5.8
Divestitures	(217.0	)	(0.3	)	(1.0	)	(224.8	)
Extensions and discoveries	409.2		28.5		8.9		633.8
Production	(407.0	)	(4.4	)	(10.4	)	(495.8	)
Proved reserves at December 31, 2012	3,369.1		76.5		110.4		4,490.5
Revisions	308.3		3.5		(25.4	)	177.2
Divestitures	(0.2	)	—		—		(0.5	)
Extensions and discoveries	312.0		28.8		8.1		533.8
Production	(359.4	)	(5.9	)	(7.4	)	(439.4	)
Proved reserves at December 31, 2013	3,629.8		102.9		85.7		4,761.6
Revisions	(198.3	)	(7.7	)	(13.4	)	(324.8	)
Purchases	6.0		4.2		0.8		36.5
Divestitures	(314.6	)	(1.8	)	(8.5	)	(376.6	)
Extensions and discoveries	362.1		42.4		12.5		691.3
Production	(335.4	)	(9.2	)	(6.3	)	(428.4	)
Proved reserves at December 31, 2014	3,149.6		130.8		70.8		4,359.6
Proved developed reserves:
December 31, 2012	2,170.7		23.7		64.9		2,702.6
December 31, 2013	2,265.2		36.8		48.6		2,777.7
December 31, 2014	2,090.0		60.0		43.9		2,713.8
Proved undeveloped reserves:
December 31, 2012	1,198.4		52.8		45.5		1,787.9
December 31, 2013	1,364.6		66.1		37.1		1,983.9
December 31, 2014	1,059.6		70.8		26.9		1,645.8

__________

(a) Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

• Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.

• Revisions in 2014 primarily reflect 97 Bcfe of net positive revisions to developed reserves and 422 Bcfe of net negative revisions to undeveloped reserves. The 422 Bcfe of net negative revisions were primarily due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules. Revisions in 2013 reflects 133 Bcfe related to developed reserves and 44 Bcfe related to undeveloped reserves. Revisions in 2012 primarily resulted from the lower 12-month average price as compared to the 12-month average price used in 2011.

• Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (See Note 4 of Notes to Consolidated Financial Statements). Divestitures in 2012 primarily relate to the sale of our holdings in the Barnett Shale and the Arkoma Basin (see Note 2 of Notes to Consolidated Financial Statements).

• Extensions and discoveries in 2014 reflect 189 Bcfe added for drilled locations and 502 Bcfe added for new proved undeveloped locations. Extensions and discoveries in 2013 reflects 127 Bcfe added for drilled locations and 407 Bcfe added for new undeveloped locations. The 2014 and 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin. Extensions and discoveries in 2012 reflect 225 Bcfe added for drilled locations and 405 Bcfe added for new undeveloped locations. The 2012 extensions and discoveries were primarily in the Williston Basin, Appalachian Basin and Piceance Basin.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is based on the estimated quantities of proved reserves. Prices are based on the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years ended December 31, 2014, 2013 and 2012, the average domestic combined natural gas and NGL equivalent price was $4.34, $3.63 and $3.01 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2014, 2013 and 2012 was $83.62, $92.16 and $82.32 per barrel, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2014		2013
	(Millions)
Future cash inflows	$	26,444	$	24,547
Less:
Future production costs	12,641		12,148
Future development costs	3,426		3,789
Future income tax provisions	2,519		2,147
Future net cash flows	7,858		6,463
Less 10 percent annual discount for estimated timing of cash flows	3,975		3,499
Standardized measure of discounted future net cash inflows	$	3,883	$	2,964

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

	For the years ended December 31,
	2014			2013			2012
	(Millions)
Beginning of year	$	2,964		$	1,949		$	3,591
Sales of oil and gas produced, net of operating costs	(1,324		)	(1,040		)	(778		)
Net change in prices and production costs	303			1,198			(3,601		)
Extensions, discoveries and improved recovery, less estimated future costs	1,761			1,282			1,154
Development costs incurred during year	592			414			333
Changes in estimated future development costs	143			(736		)	50
Purchase of reserves in place, less estimated future costs	147			—			4
Sale of reserves in place, less estimated future costs	(391		)	(3		)	(272		)
Revisions of previous quantity estimates	(536		)	239			(232		)
Accretion of discount	383			225			481
Net change in income taxes	(142		)	(540		)	1,194
Other	(17		)	(24		)	25
Net changes	919			1,015			(1,642		)
End of year	$	3,883		$	2,964		$	1,949

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Asset Sales, Impairments and Exploration Expenses - Significant Adjustments with Domestic Operations (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended						3 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2014 Well acre MMcf		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2014	Mar. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets			$ 374		$ 49		$ 310
Percentage Ownership Of Incentive Distribution Rights			10.00%						10.00%
Proved Developed and Undeveloped Reserves, Net			300,000.0						300,000.0
Percentage of proved reserves attributed to sale of producing assets			6.00%
Production Related To The Sale Of Working Interests			70
Impairment of producing properties and costs of acquired unproved reserves			20	[1]	860	[1]	123	[1]
Impairment Equity method investment			0		20	[2]	0
Gain on sale of Powder River Basin deep rights leasehold					36
Loss On Sale Of Working Interests	1	195	196		0		0
Property, Plant and Equipment, Net			6,842		6,760				6,842
Asset Retirement Obligation			201		308		261		201
Oil and Gas Property, Deep Rights, Acres Sold During Period			46,700
Production related to sale			50
Proved developed wells related to sale			63
Oil and Gas Delivery Commitments and Contracts, Daily Production			260
Cost Of Oil And Gas Services			24
Other Property
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Impairment Charge			9
Legacy [Member] | Piceance Basin [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets			325
Pennsylvania [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets									300
Post Closing [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from sales of assets			329
Marcellus Shale
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property, Plant and Equipment, Net			200						200
Asset Retirement Obligation			2						2
Subsequent Event
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Gain (Loss) on Disposition of Proved Property										$ 75

[1] Excludes related impairments of unproved leasehold included in exploration expenses.

[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

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Supplemental Oil and Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2014

Extractive Industries [Abstract]

Capitalized Costs

Capitalized Costs

	As of December 31,
	2014			2013
	(Millions)
Proved Properties	$	10,717		$	11,132
Unproved properties	394			324
	11,111			11,456
Accumulated depreciation, depletion and amortization and valuation provisions	(4,698		)	(5,070		)
Net capitalized costs	$	6,413		$	6,386

Cost Incurred

Cost Incurred

	For the years ended December 31,
	2014		2013		2012
	(Millions)
Acquisition	$	294	$	57	$	111
Exploration	92		104		23
Development	1,376		939		1,130
	$	1,762	$	1,100	$	1,264

Results of Operations

Results of Operations

	For the years ended December 31,
	2014		2013			2012
	(Millions)
Revenues:
Natural gas sales	$	1,002	$	896		$	1,193
Oil and condensate sales	724		534			376
Natural gas liquid sales	205		228			297
Net gain (loss) on derivatives not designated as hedges	515		(57		)	66
Other revenues	8		6			7
Total revenues	2,454		1,607			1,939
Costs:
Lease and facility operating	244		227			202
Gathering, processing and transportation	328		350			434
Taxes other than income	126		102			68
Exploration	173		423			71
Depreciation, depletion and amortization	810		858			884
Impairment of certain proved properties	15		772			48
Impairment of costs of acquired unproved reserves	5		88			75
Loss on sale of working interests in the Piceance Basin	196		—			—
General and administrative	264		262			259
Other (income) expense	12		12			16
Total costs	2,173		3,094			2,057
Results of operations	281		(1,487		)	(118		)
Provision (benefit) for income taxes	103		(543		)	(43		)
Exploration and production net income (loss)	$	178	$	(944	)	$	(75	)

Proved Reserves

	Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		All Products (Bcfe)
Proved reserves at December 31, 2011	3,982.9		47.1		134.0		5,070.1
Revisions	(404.8	)	5.6		(21.1	)	(498.6	)
Purchases	5.8		—		—		5.8
Divestitures	(217.0	)	(0.3	)	(1.0	)	(224.8	)
Extensions and discoveries	409.2		28.5		8.9		633.8
Production	(407.0	)	(4.4	)	(10.4	)	(495.8	)
Proved reserves at December 31, 2012	3,369.1		76.5		110.4		4,490.5
Revisions	308.3		3.5		(25.4	)	177.2
Divestitures	(0.2	)	—		—		(0.5	)
Extensions and discoveries	312.0		28.8		8.1		533.8
Production	(359.4	)	(5.9	)	(7.4	)	(439.4	)
Proved reserves at December 31, 2013	3,629.8		102.9		85.7		4,761.6
Revisions	(198.3	)	(7.7	)	(13.4	)	(324.8	)
Purchases	6.0		4.2		0.8		36.5
Divestitures	(314.6	)	(1.8	)	(8.5	)	(376.6	)
Extensions and discoveries	362.1		42.4		12.5		691.3
Production	(335.4	)	(9.2	)	(6.3	)	(428.4	)
Proved reserves at December 31, 2014	3,149.6		130.8		70.8		4,359.6
Proved developed reserves:
December 31, 2012	2,170.7		23.7		64.9		2,702.6
December 31, 2013	2,265.2		36.8		48.6		2,777.7
December 31, 2014	2,090.0		60.0		43.9		2,713.8
Proved undeveloped reserves:
December 31, 2012	1,198.4		52.8		45.5		1,787.9
December 31, 2013	1,364.6		66.1		37.1		1,983.9
December 31, 2014	1,059.6		70.8		26.9		1,645.8

__________

(a) Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Standardized Measure of Discounted Future Net Cash Flows

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2014		2013
	(Millions)
Future cash inflows	$	26,444	$	24,547
Less:
Future production costs	12,641		12,148
Future development costs	3,426		3,789
Future income tax provisions	2,519		2,147
Future net cash flows	7,858		6,463
Less 10 percent annual discount for estimated timing of cash flows	3,975		3,499
Standardized measure of discounted future net cash inflows	$	3,883	$	2,964

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

	For the years ended December 31,
	2014			2013			2012
	(Millions)
Beginning of year	$	2,964		$	1,949		$	3,591
Sales of oil and gas produced, net of operating costs	(1,324		)	(1,040		)	(778		)
Net change in prices and production costs	303			1,198			(3,601		)
Extensions, discoveries and improved recovery, less estimated future costs	1,761			1,282			1,154
Development costs incurred during year	592			414			333
Changes in estimated future development costs	143			(736		)	50
Purchase of reserves in place, less estimated future costs	147			—			4
Sale of reserves in place, less estimated future costs	(391		)	(3		)	(272		)
Revisions of previous quantity estimates	(536		)	239			(232		)
Accretion of discount	383			225			481
Net change in income taxes	(142		)	(540		)	1,194
Other	(17		)	(24		)	25
Net changes	919			1,015			(1,642		)
End of year	$	3,883		$	2,964		$	1,949

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Stock-Based Compensation - Other Restricted Stock Unit (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$ 18.37	[1]
Restricted Stock Units
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$ 18.37		$ 14.97	$ 17.35
Total fair value of restricted stock units vested during the year (millions)	$ 33		$ 18	$ 14

[1] Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

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

[1] Excludes related impairments of unproved leasehold included in exploration expenses.

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Contingent Liabilities and Commitments (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitment Under Contracts

Our commitments under these contracts as of December 31, 2014 are as follows:

	(Millions)
2015	$	177
2016	162
2017	149
2018	138
2019	126
Thereafter	389
Total	$	1,141

Future Minimum Annual Rentals Under Noncancelable Operating Leases

Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:

	(Millions)
2015	$	37
2016	32
2017	11
2018	7
2019	7
Thereafter	15
Total	$	109

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

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

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

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

[1] (a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.

[2] (a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating Activities
Net income (loss)	$ 171		$ (1,191)		$ (211)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	863		940		973
Deferred income tax provision (benefit)	46		(645)		(160)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments	236		1,483		288
Amortization of stock-based awards	36		32		28
Gain (loss) on sales of assets	(196)	[1]	41	[1]	42	[1]
Cash provided (used) by operating assets and liabilities:
Accounts receivable	51		(43)		68
Inventories	19		(5)		7
Margin deposits and customer margin deposits payable	(10)		(18)		(5)
Other current assets	8		(7)		7
Accounts payable	4		41		(128)
Accrued and other current liabilities	(1)		(21)		12
Changes in current and noncurrent derivative assets and liabilities	(559)		106		(32)
Other, including changes in other noncurrent assets and liabilities	10		5		(9)
Net cash provided by operating activities	1,070		636		796
Investing Activities
Capital expenditures	(1,807)	[2]	(1,154)	[2]	(1,521)	[2]
Proceeds from sales of assets	374		49		310
Other	(4)		(6)		7
Net cash used in investing activities	(1,437)		(1,111)		(1,204)
Financing Activities
Proceeds from common stock	16		6		3
Proceeds from long-term debt	500		0		6
Borrowings on credit facility	1,947		970		50
Payments on credit facility	(2,077)		(560)		(50)
Excess tax benefit of stock based awards	0		0		13
Payments for long-term debt issuance costs	(13)		0		0
Other	(29)		10		15
Net cash provided by financing activities	344		426		37
Net increase (decrease) in cash and cash equivalents	(23)		(49)		(371)
Effect of Exchange Rate on Cash and Cash Equivalents	(6)		(5)		(2)
Cash and cash equivalents at beginning of period	99	[3]	153	[3]	526	[3]
Cash and cash equivalents at end of period	$ 70	[3]	$ 99	[3]	$ 153	[3]

[1] 2014 includes $196 million loss on the sale of working interests in the Piceance Basin (Note 4), 2013 includes a $36 million gain on sale of Powder River Basin deep rights leasehold (Note 2) and 2012 includes a $38 million gain on the sale of our holdings in Barnett Shale and Arkoma Basin (Note 2).

[2] Increase to properties and equipment$(1,934) $(1,207) $(1,449)Changes in related accounts payable127 53 (72)Capital expenditures$(1,807) $(1,154) $(1,521)

[3] (c) Amounts include cash associated with our international operations which represent the difference between amounts reported as cash on the Consolidated Balance Sheets.

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

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Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Line Items]
Buyout of Transportation Agreement	$ 9	$ 14
Natural Gas Storage Revenue		4
Equity Method Investment, Ownership Percentage		69.00%
Share Based Compensation Arrangement By Share Based Payment Award Minimum Exercisable Period For Stock Options		3 years
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Minimum		20.00%
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Maximum		50.00%
Hedge gains realized from natural gas revenues			5	423
Charges for unutilized transportation capacity included in gas management expenses		57	61	46
Projects with construction periods, minimum		3 months
Total estimated project cost		1
Share Based Compensation Arrangement By Share Based Payment Award Award Term		10 years
Natural Gas
Accounting Policies [Line Items]
Inventory writedowns		1	1	11
Domestic Segment
Accounting Policies [Line Items]
Restricted cash related to escrow accounts to settle agreement	21	6	21
International
Accounting Policies [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds		$ 294

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Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Tables)

12 Months Ended

Dec. 31, 2014

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

The following table presents a summary of inventories.

	Years ended December 31,
	2014		2013
	(Millions)
Material, supplies and other	$	43	$	43
Crude oil production in transit	2		10
Natural gas in underground storage	—		13
	$	45	$	66

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Recently Issued Accounting Standards (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.

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

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

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

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]

Summarized Results of Discontinued Operations

For the year ended December 31, 2014	Domestic		International		Total
			(Millions)
Total revenues	$	189	$	163	$	352
Costs and expenses:
Lease and facility operating	$	41	$	37	$	78
Gathering, processing and transportation	70		1		71
Taxes other than income	16		28		44
Exploration	—		4		4
Depreciation, depletion and amortization	11		42		53
Impairment of assets held for sale	45		—		45
General and administrative	4		16		20
Other—net	—		12		12
Total costs and expenses	187		140		327
Operating income (loss)	2		23		25
Interest capitalized	1		—		1
Investment income and other	6		19		25
Income (loss) from discontinued operations before income taxes	9		42		51
Provision (benefit) for income taxes(a)	2		7		9
Income (loss) from discontinued operations	$	7	$	35	$	42

__________

(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.

For the year ended December 31, 2013	Domestic			International		Total
				(Millions)
Total revenues	$	178		$	152	$	330
Costs and expenses:
Lease and facility operating	$	44		$	37	$	81
Gathering, processing and transportation	80			3		83
Taxes other than income	15			24		39
Exploration	1			7		8
Depreciation, depletion and amortization	48			34		82
Impairment of producing properties and costs of acquired unproved reserves	192			3		195
Gain on sale of Powder River Basin deep rights leasehold	(36		)	—		(36		)
General and administrative	6			14		20
Other—net	5			—		5
Total costs and expenses	355			122		477
Operating income (loss)	(177		)	30		(147		)
Interest capitalized	4			—		4
Investment income and other	4			21		25
Income (loss) from discontinued operations before income taxes	(169		)	51		(118		)
Provision (benefit) for income taxes(a)	(62		)	31		(31		)
Income (loss) from discontinued operations	$	(107	)	$	20	$	(87	)

__________

(a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

For the year ended December 31, 2012	Domestic			International		Total
				(Millions)
Total revenues	$	180		$	137	$	317
Costs and expenses:
Lease and facility operating	$	65		$	32	$	97
Gathering, processing and transportation	74			2		76
Taxes other than income	19			24		43
Gas management, including charges for unutilized pipeline capacity	1			—		1
Exploration	1			11		12
Depreciation, depletion and amortization	62			27		89
Impairment of producing properties and costs of acquired unproved reserves	102			—		102
Gain on sale of Barnett Shale and Arkoma Basin holdings	(38		)	—		(38		)
General and administrative	10			14		24
Other—net	(1		)	—		(1		)
Total costs and expenses	295			110		405
Operating income (loss)	(115		)	27		(88		)
Interest capitalized	6			—		6
Investment income and other	4			27		31
Income (loss) from discontinued operations before income taxes	(105		)	54		(51		)
Provision (benefit) for income taxes	(38		)	24		(14		)
Income (loss) from discontinued operations	$	(67	)	$	30	$	(37	)

Summarized Results of Discontinued Operations

.

Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block]

Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations

December 31, 2014	Domestic			International			Total
				(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—		$	29		$	29
Accounts receivable	—			25			25
Inventories	1			7			8
Other	—			14			14
Total current assets	1			75			76
Investments	18			134			152
Properties and equipment (successful efforts method of accounting)(a)	132			445			577
Less—accumulated depreciation, depletion and amortization	(10		)	(228		)	(238		)
Properties and equipment, net	122			217			339
Other noncurrent assets	—			6			6
Total assets classified as held for sale—discontinued operations	$	141		$	432		$	573
Total assets classified as held for sale—continuing operations (Note 4)	200			—			200
Total assets classified as held for sale on the Consolidated Balance Sheets	$	341		$	432		$	773
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—		$	34		$	34
Accrued and other current liabilities	3			23			26
Total current liabilities	3			57			60
Deferred income taxes	—			13			13
Long-term debt	—			2			2
Asset retirement obligations	45			7			52
Other noncurrent liabilities	—			3			3
Total liabilities associated with assets held for sale—discontinued operations	$	48		$	82		$	130
Total liabilities associated with assets held for sale—continuing operations (Note 4)	$	2		$	—		$	2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	50		$	82		$	132

__________

(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

December 31, 2013	Domestic		International			Total
			(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—	$	51		$	51
Accounts receivable	—		18			18
Inventories	1		5			6
Other	—		17			17
Total current assets	1		91			92
Investments	17		125			142
Properties and equipment (successful efforts method of accounting)	166		360			526
Less—accumulated depreciation, depletion and amortization	—		(194		)	(194		)
Properties and equipment, net	166		166			332
Total assets classified as held for sale—discontinued operations(a)	$	184	$	382		$	566
Total assets classified as held for sale—continuing operations (Note 4)(a)	148		—			148
Total assets classified as held for sale on the Consolidated Balance Sheets(a)	$	332	$	382		$	714
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	18		$	18
Accrued and other current liabilities	3		20			23
Total current liabilities	3		38			41
Deferred income taxes	—		12			12
Long-term debt	—		5			5
Asset retirement obligations	47		4			51
Total liabilities associated with assets held for sale—discontinued operations(a)	$	50	$	59		$	109
Total liabilities associated with assets held for sale—continuing operations (Note 4)	2		—			2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(a)	$	52	$	59		$	111

__________

(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.

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

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

Thefollowing table summarizes the calculation of earnings per share.

	Years Ended December 31,
	2014		2013			2012
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	129	$	(1,092	)	$	(174	)
Basic weighted-average shares	202.7		200.5			198.8
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	2.7
Stock options	0.9
Diluted weighted-average shares	206.3		200.5			198.8
Earnings (loss) per common share from continuing operations:
Basic	$	0.63	$	(5.45	)	$	(0.87	)
Diluted	$	0.62	$	(5.45	)	$	(0.87	)

__________

(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Options

The table below includes information related to stock options that were outstanding at December 31, 2014, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.

	2014		2013		2012
Options excluded (millions)	1.4		0.4		1.3
Weighted-average exercise price of options excluded	$	18.42	$	20.24	$	18.17
Exercise price range of options excluded	$16.46 - $21.81		$20.21  - $20.97		$16.46  - $20.97
Fourth quarter weighted-average market price	$	15.96	$	19.97	$	16.15

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

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Asset Sales, Impairments and Exploration Expenses (Tables)

12 Months Ended

Dec. 31, 2014

Extractive Industries [Abstract]

Summary of Significant Gains or Losses Reflected in Impairment of Producing Properties and Costs of Acquired Unproved Reserves, Goodwill Impairment and Other-Net within Costs and Expenses

The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments.

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)	$	20	$	860	$	123
Impairment of equity method investment in Appalachian Basin	$	—	$	20	$	—

__________

(a) Excludes related impairments of unproved leasehold included in exploration expenses.

Summary of Exploration Expenses

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Geologic and geophysical costs	$	11	$	18	$	12
Impairments of exploratory area well costs and dry hole costs	88		3		1
Unproved leasehold property impairments, amortization and expiration	74		402		58
Total exploration expenses	$	173	$	423	$	71

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

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Derivatives and Concentration of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2014

DerivativeGainLoss [Line Items]

DerivativeGainLoss [Table Text Block]

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

	Years Ended December 31,
	2014			2013			2012
Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515		$	(57	)	$	66
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)	(67		)	12
Net gain (loss) on derivatives not designated as hedges	$	434		$	(124	)	$	78

__________

(a) Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.

(b) Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.

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

	Years Ended December 31,
	2014			2013			2012
Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515		$	(57	)	$	66
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)	(67		)	12
Net gain (loss) on derivatives not designated as hedges	$	434		$	(124	)	$	78

__________

(a) Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.

(b) Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.

Derivative Volumes that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production

Derivatives related to production

The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2014.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Natural Gas
Natural Gas	2015	Fixed Price Swaps	Henry Hub	(442	)	$	4.10
Natural Gas	2015	Costless Collars	Henry Hub	(50	)	$ 4.00 - 4.50
Natural Gas	2015	Basis Swaps	NGPL	(13	)	$	(0.16	)
Natural Gas	2015	Basis Swaps	Rockies	(150	)	$	(0.11	)
Natural Gas	2015	Basis Swaps	San Juan	(85	)	$	(0.10	)
Natural Gas	2015	Basis Swaps	SoCal	(20	)	$	0.18
Natural Gas	2016	Fixed Price Swaps	Henry Hub	(200	)	$	3.98
Natural Gas	2016	Swaptions	Henry Hub	(90	)	$	4.23
Natural Gas	2017	Swaptions	Henry Hub	(65	)	$	4.19
Crude Oil
Crude Oil	2015	Fixed Price Swaps	WTI	(20,236	)	$	94.88
Crude Oil	2015	Swaptions	WTI	(882	)	$	97.29
Crude Oil	2016	Swaptions	WTI	(5,250	)	$	97.55

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.

(b) Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.

(c) The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

Derivatives primarily related to transportation

The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.

Commodity	Period	Contract Type (a)	Location (b)	Notional Volume (c)
Natural Gas	2015	Basis Swaps	Multiple	(3	)
Natural Gas	2015	Index	Multiple	(118	)
Natural Gas	2016	Index	Multiple	(70	)
Natural Gas	2017	Index	Multiple	(70	)
Natural Gas	2018+	Index	Multiple	(379	)

__________

(a) We enter into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.

(b) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.

(c) Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.

Fair Value of Energy Commodity Derivatives

The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

	December 31,
	2014				2013
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Derivatives related to production not designated as hedging instruments	$	517	$	10	$	26	$	39
Derivatives related to physical marketing agreements not designated as hedging instruments	19		32		31		83
Total derivatives not designated as hedging instruments	$	536	$	42	$	57	$	122

Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues

The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.

	Years Ended December 31,						Classification
	2014		2013		2012
			(Millions)
Net gain recognized in other comprehensive income (loss) (effective portion)	$	—	$	—	$	90	AOCI
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	—	$	5	$	434	Revenues

__________

(a) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.

Gross And Net Derivative Asset and Liability

The following table presents our gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet			Netting Adjustments (a)			Cash Collateral Posted(Received)		Net Amount
December 31, 2014	(Millions)
Derivative assets with right of offset or master netting agreements	$	536		$	(25	)	$	—	$	511
Derivative liabilities with right of offset or master netting agreements	$	(42	)	$	25		$	17	$	—
December 31, 2013
Derivative assets with right of offset or master netting agreements	$	57		$	(50	)	$	—	$	7
Derivative liabilities with right of offset or master netting agreements	$	(122	)	$	50		$	52	$	(20	)

__________

(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Concentration of Receivables, Net of Allowances, by Product or Service

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:

	2014		2013
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	340	$	339
Joint interest owners	106		168
Other	13		11
Total	$	459	$	518

Gross and Net Credit Exposure from Derivative Contracts

The gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:

Counterparty Type	Gross Total			Net Total
	(Millions)
Gas and electric utilities, integrated oil and gas companies, and other	$	4		$	4
Financial institutions (Investment Grade) (a)	533			508
	537			512
Credit reserves	(1		)	(1		)
Credit exposure from derivatives	$	536		$	511

__________

(a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

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

[1] Estimated useful lives are presented as of December 31, 2014.

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

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

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

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

[1] Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

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

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

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

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Supplemental Oil and Gas Disclosures - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Mcfe		Dec. 31, 2013 Mcfe		Dec. 31, 2012 Mcfe		Dec. 31, 2011 Mcfe
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserves, Net	300,000.0
Equipment and facilities in support of oil and gas production excluded from capitalization	385		328
Equity earnings from the international equity method investee	1		21		1
Impairment of oil and gas properties	20	[1]	1,055	[2]	225	[3]
Computation of natural gas reserves	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
Weighted average natural gas price	4.34		3.63		3.01
Weighted average oil per barrel price	83.62		92.16		82.32
Discount rate	10.00%
Powder River Basin
Supplementary Information [Line Items]
Operations representing total domestic and international proved reserves	5.00%
International
Supplementary Information [Line Items]
Operations representing total domestic and international proved reserves	5.00%
Appalachian Basin
Supplementary Information [Line Items]
Operations representing total domestic and international proved reserves	5.00%
Impairment of oil and gas properties	317
Oil and Condensate Sales | Domestic
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserves, Net	130.8		102.9		76.5		47.1
Oil and Condensate Sales | San Juan [Member]
Supplementary Information [Line Items]
Proved Developed and Undeveloped Reserves, Net	28,000.0
All products | Domestic
Supplementary Information [Line Items]
Proved developed reserves, revisions	97,000		133,000
Proved undeveloped reserves, revisions	422,000		44,000
Additions due to added drill locations	189,000		127,000		225,000
Additions due to new undeveloped locations	502,000		407,000		405,000
Proved Developed And Undeveloped Reserves Net Equivalent	4,359,600	[4]	4,761,600	[4]	4,490,500	[4]	5,070,100	[4]
All products | Powder River Basin
Supplementary Information [Line Items]
Proved Developed And Undeveloped Reserves Net Equivalent	200,000	[4]	244,600	[4]	235,900	[4]

[1] As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:•$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.•$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

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

[4] Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

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

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Supplemental Oil and Gas Disclosures - Proved Reserves - Additional Information (Detail)

12 Months Ended

Dec. 31, 2014

Disclosure Proved Reserves [Abstract]

Conversion Rate Of Oil And Ngl Quantities

Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

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Debt and Banking Arrangements (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

As of the indicated dates, our debt consisted of the following:

	December 31,
	2014 (a)		2013 (a)
	(Millions)
5.250% Senior Notes due 2017	$	400	$	400
6.000% Senior Notes due 2022	1,100		1,100
5.250% Senior Notes due 2024	500		—
Credit facility agreement	280		410
Other	1		2
Total debt	$	2,281	$	1,912
Less: Current portion of long-term debt	1		1
Total long-term debt	$	2,280	$	1,911

__________

(a) Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

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

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Fair Value Measurements

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

• Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.

• Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.

• Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

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

	December 31, 2014								December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(Millions)								(Millions)
Energy derivative assets	$	14	$	517	$	5	$	536	$	30	$	26	$	1	$	57
Energy derivative liabilities	$	32	$	10	$	—	$	42	$	83	$	38	$	1	$	122
Total debt(a)	$	—	$	2,218	$	—	$	2,218	$	—	$	1,938	$	—	$	1,938

__________

(a) The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.

Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.

Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

Forward, swap and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with 100 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2014, consist primarily of natural gas index transactions that are used to manage our physical requirements.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2014 or 2013.

The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

	Years ended December 31,
	2014		2013			2012
	(Millions)
Beginning balance	$	—	$	(1	)	$	1
Realized and unrealized gains (losses):
Included in income (loss) from continuing operations	5		(2		)	3
Included in other comprehensive income (loss)	—		—			—
Purchases, issuances, and settlements	—		3			(5		)
Transfers out of Level 3	—		—			—
Ending balance	$	5	$	—		$	(1	)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31	$	5	$	(1	)	$	(1	)

Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations.

As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas, oil and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In each of the three years ended December 31, 2014, our assessments identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

	Total losses for the years ended December 31,
	2014 (a)		2013 (b)		2012 (c)
	(Millions)
Impairments:
Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)	$	20	$	1,055	$	225
Unproved leasehold	—		317		—
Equity method investment (Note 4)	—		20		—
	$	20	$	1,392	$	225

__________

(a) As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:

• $11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.

• $9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

(b) As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:

• $792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.

• $317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.

• $107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.

• $88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

• $85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

(c) As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:

• $102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

• $48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

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Provision (Benefit) for Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes from Continuing Operations

The provision (benefit) for income taxes from continuing operations includes:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision (benefit):
Current:
Federal	$	(3	)	$	(29	)	$	49
State	1			1			4
	(2		)	(28		)	53
Deferred:
Federal	76			(549		)	(125		)
State	1			(47		)	(12		)
	77			(596		)	(137		)
Total provision (benefit)	$	75		$	(624	)	$	(84	)

Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate

Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision (benefit) at statutory rate	$	71		$	(604	)	$	(90	)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	3			(111		)	(6		)
State income tax change in valuation allowance (net of federal benefit)	(1		)	80			—
State income tax legislation change (net of federal benefit)	9			—			—
Effective state income tax rate change (net of federal benefit)	(9		)	(3		)	—
Alternative minimum tax credits	—			—			11
Other	2			14			1
Provision (benefit) for income taxes	$	75		$	(624	)	$	(84	)

Significant Components of Deferred Tax Liabilities and Deferred Tax Assets

Significant components of deferred tax liabilities and deferred tax assets are as follows:

	December 31,
	2014		2013
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	738	$	961
Derivatives, net	170		—
Other, net	17		23
Total deferred tax liabilities	925		984
Deferred tax assets:
Accrued liabilities and other	124		176
Alternative minimum tax credits	60		76
Loss carryovers	51		83
Derivatives, net	—		21
Other, net	32		—
Total deferred tax assets	267		356
Less: valuation allowance	114		99
Total net deferred tax assets	153		257
Net deferred tax liabilities	$	772	$	727

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Supplemental Oil and Gas Disclosures - Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2014 MMcf		Dec. 31, 2013 MMcf		Dec. 31, 2012 MMcf
Supplementary Information [Line Items]
Proved reserves ending balance	300,000
Domestic | Natural Gas
Supplementary Information [Line Items]
Proved reserves beginning balance	3,629,800		3,369,100		3,982,900
Revisions	(198,300)		308,300		(404,800)
Purchases	(6,000)				(5,800)
Divestitures	(314,600)		(200)		(217,000)
Extensions and discoveries	362,100		312,000		409,200
Production	(335,400)		(359,400)		(407,000)
Proved reserves ending balance	3,149,600		3,629,800		3,369,100
Proved developed reserves	2,090,000		2,265,200		2,170,700
Proved undeveloped reserves	1,059,600		1,364,600		1,198,400
Domestic | Oil and Condensate Sales
Supplementary Information [Line Items]
Proved reserves beginning balance	102.9		76.5		47.1
Revisions	(7.7)		3.5		5.6
Purchases	(4.2)				0.0
Divestitures	(1.8)		0.0		(0.3)
Extensions and discoveries	42.4		28.8		28.5
Production	(9.2)		(5.9)		(4.4)
Proved reserves ending balance	130.8		102.9		76.5
Proved developed reserves	60.0		36.8		23.7
Proved undeveloped reserves	70.8		66.1		52.8
Domestic | Natural Gas Liquids
Supplementary Information [Line Items]
Proved reserves beginning balance	85.7		110.4		134.0
Revisions	(13.4)		(25.4)		(21.1)
Purchases	(0.8)		0.0		0.0
Divestitures	(8.5)				(1.0)
Extensions and discoveries	12.5		8.1		8.9
Production	(6.3)		(7.4)		(10.4)
Proved reserves ending balance	70.8		85.7		110.4
Proved developed reserves	43.9		48.6		64.9
Proved undeveloped reserves	26.9		37.1		45.5
Domestic | All products
Supplementary Information [Line Items]
Proved reserves beginning balance	4,761,600	[1]	4,490,500	[1]	5,070,100	[1]
Revisions	(324,800)	[1]	177,200	[1]	(498,600)	[1]
Purchases	36,500	[1]			5,800	[1]
Divestitures	(376,600)	[1]	(500)	[1]	(224,800)	[1]
Extensions and discoveries	691,300	[1]	533,800	[1]	633,800	[1]
Production	(428,400)	[1]	(439,400)	[1]	(495,800)	[1]
Proved reserves ending balance	4,359,600	[1]	4,761,600	[1]	4,490,500	[1]
Proved developed reserves	2,713,800	[1]	2,777,700	[1]	2,702,600	[1]
Proved undeveloped reserves	1,645,800	[1]	1,983,900	[1]	1,787,900	[1]

[1] Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL DATA

WPX Energy, Inc.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Millions, except per-share amounts)
2014
Revenues	$	894		$	727		$	747		$	1,125
Operating costs and expenses	$	783		$	659		$	570		$	656
Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
Income (loss) from discontinued operations	19			11			20			(8		)
Net income (loss)	$	19		$	(133	)	$	66		$	219
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
Income (loss) from discontinued operations	18			9			16			(8		)
Net income (loss)	$	18		$	(135	)	$	62		$	219
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.11
Income (loss) from discontinued operations	0.09			0.05			0.07			(0.03		)
Net income (loss)	$	0.09		$	(0.66	)	$	0.30		$	1.08
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.10
Income (loss) from discontinued operations	0.09			0.05			0.07			(0.04		)
Net income (loss)	$	0.09		$	(0.66	)	$	0.30		$	1.06
2013
Revenues	$	552		$	722		$	581		$	576
Operating costs and expenses	$	634		$	612		$	621		$	1,024
Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(890	)
Income (loss) from discontinued operations	2			16			(11		)	(94		)
Net income (loss)	$	(113	)	$	22		$	(116	)	$	(984	)
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(878	)
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	(116	)	$	18		$	(114	)	$	(973	)
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.57	)	$	0.03		$	(0.52	)	$	(4.37	)
Income (loss) from discontinued operations	(0.01		)	0.06			(0.05		)	(0.48		)
Net income (loss)	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

Net loss for fourth-quarter 2014 includes the following pre-tax items:

• $87 million of impairments of costs of producing properties, acquired unproved reserves and leasehold (see Note 4).

• During 2014, we assigned our remaining natural gas storage capacity agreement to a third party and sold the remaining natural gas stored under this agreement for a total loss of approximately $18 million reflected in gas management expenses in the Consolidated Statements of Operations.

Net income for third-quarter 2014 includes the following pre-tax items:

• $22 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.

Net loss for second-quarter 2014 includes the following pre-tax items:

• $195 million loss on the sale of a portion of our working interests in certain Piceance Basin wells.

• $40 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.

• $11 million increase in gas management expense related to a tariff rate refund received in prior years which is no longer under appeal by the pipeline company.

Net income for first-quarter 2014 includes the following pre-tax items:

• $9 million deferred tax expense to accrue for the impact of new legislation (see Note 8.)

Net loss for fourth-quarter 2013 includes the following pre-tax items:

• $1,178 million of impairments of costs of producing properties, acquired unproved reserves, leasehold and equity method investment (see Note 4).

• $9 million buyout of a transportation agreement.

Net loss for third-quarter 2013 includes the following pre-tax items:

• $19 million of impairments of costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin (see Note 4).

Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:

	First Quarter			Second Quarter			Third Quarter (a)			Fourth Quarter
	(Millions, except per-share amounts)
	(Increase, (Decrease))
2014
Revenues	$	(93	)	$	(87	)	$	47		N/A
Operating costs and expenses	$	(62	)	$	62		$	31		N/A
Income (loss) from continuing operations	$	(19	)	$	(11	)	$	(15	)	N/A
Income (loss) from discontinued operations	19			11			15			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(18	)	$	(9	)	$	(16	)	N/A
Income (loss) from discontinued operations	18			9			16			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
2013
Revenues	$	(79	)	$	(93	)	$	35		$	(81	)
Operating costs and expenses	$	(76	)	$	(77	)	$	22		$	(74	)
Income (loss) from continuing operations	$	(2	)	$	(16	)	$	3		$	94
Income (loss) from discontinued operations	2			16			(3		)	(94		)
Net income (loss)	$	—		$	—		$	—		$	—
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	1		$	(12	)	$	9		$	95
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	—		$	—		$	—		$	—
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.01		$	(0.06	)	$	0.01		$	0.48
Income (loss) from discontinued operations	(0.01		)	0.06			(0.01		)	(0.48		)
Net income (loss)	$	—		$	—		$	—		$	—

__________

(a) Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

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Employee Benefit Plans - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer contribution	$ 17	$ 16	$ 6
Postretirement Defined Benefit Plans, Liabilities	$ 10	$ 11
Maximum
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer matching percentage	6.00%
If employee are 40 years or older [Member]
Employee Benefit And Retirement Plans [Line Items]
Non matching employer contribution under defined benefit contribution plan	8.00%
If employees are under age 40 [Member]
Employee Benefit And Retirement Plans [Line Items]
Non matching employer contribution under defined benefit contribution plan	6.00%

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Consolidated Statements of Changes in Equity (USD $) In Millions, unless otherwise specified		Total	Total Stockholders’ Equity	Common Stock	Capital in Excess of Par Value	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2011		$ 5,759	$ 5,678	$ 2	$ 5,457	$ 0	$ 219	$ 81	[1]
Comprehensive income:
Net income (loss)		(211)	(223)			(223)		12	[1]
Other comprehensive income (loss)		(217)	(217)				(217)
Comprehensive income (loss)		(428)
Contribution from noncontrolling interest		10
Contribution from noncontrolling interest	[1]							10
Stock based compensation, net of tax benefit		30	30		30
Balance at end of period at Dec. 31, 2012		5,371	5,268	2	5,487	(223)	2	103	[1]
Comprehensive income:
Net income (loss)		(1,191)	(1,185)			(1,185)		(6)	[1]
Other comprehensive income (loss)		(3)	(3)				(3)
Comprehensive income (loss)		(1,194)
Contribution from noncontrolling interest		4						4	[1]
Stock based compensation, net of tax benefit		29	29		29
Balance at end of period at Dec. 31, 2013		4,210	4,109	2	5,516	(1,408)	(1)	101	[1]
Comprehensive income:
Net income (loss)		171	164			164		7	[1]
Other comprehensive income (loss)		0	0				0
Comprehensive income (loss)		171
Contribution from noncontrolling interest		1						1	[1]
Stock based compensation, net of tax benefit		46	46		46
Balance at end of period at Dec. 31, 2014		$ 4,428	$ 4,319	$ 2	$ 5,562	$ (1,244)	$ (1)	$ 109	[1]

[1] Primarily represents the 31 percent of Apco Oil and Gas International Inc. owned by others.

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

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Provision (Benefit) for Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes

Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes from continuing operations includes:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision (benefit):
Current:
Federal	$	(3	)	$	(29	)	$	49
State	1			1			4
	(2		)	(28		)	53
Deferred:
Federal	76			(549		)	(125		)
State	1			(47		)	(12		)
	77			(596		)	(137		)
Total provision (benefit)	$	75		$	(624	)	$	(84	)

Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision (benefit) at statutory rate	$	71		$	(604	)	$	(90	)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	3			(111		)	(6		)
State income tax change in valuation allowance (net of federal benefit)	(1		)	80			—
State income tax legislation change (net of federal benefit)	9			—			—
Effective state income tax rate change (net of federal benefit)	(9		)	(3		)	—
Alternative minimum tax credits	—			—			11
Other	2			14			1
Provision (benefit) for income taxes	$	75		$	(624	)	$	(84	)

Significant components of deferred tax liabilities and deferred tax assets are as follows:

	December 31,
	2014		2013
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	738	$	961
Derivatives, net	170		—
Other, net	17		23
Total deferred tax liabilities	925		984
Deferred tax assets:
Accrued liabilities and other	124		176
Alternative minimum tax credits	60		76
Loss carryovers	51		83
Derivatives, net	—		21
Other, net	32		—
Total deferred tax assets	267		356
Less: valuation allowance	114		99
Total net deferred tax assets	153		257
Net deferred tax liabilities	$	772	$	727

Net cash payments for domestic income taxes were $9 million and $40 million in 2014 and 2012, respectively, while net cash refunds were $26 million in 2013.

We had federal net operating loss (“NOL”) carryovers of approximately $114 million at December 31, 2013, which were fully utilized in 2014. The Company has state NOL carryovers, primarily in Pennsylvania, of approximately $875 million and $825 million at 2014 and 2013, respectively, of which more than 90 percent expire after 2029.

Tax reform legislation was enacted by the state of New York on March, 31, 2014, and had an impact on us as a result of our marketing activities in the state. As a result, we recorded an additional $9 million of deferred tax expense in the first quarter of 2014 to accrue for the impact of this new legislation. However, due to announced asset sales in fourth-quarter 2014, our state effective tax rate decreased resulting in a $9 million deferred tax benefit.

We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania. In addition, we have recorded a valuation allowance against a portion of the excess tax basis in our investment in Apco, which have been included in discontinued operations (see Note 2). In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. As a result of our assessment of available evidence, a valuation allowance was recorded to reduce recognized tax assets, net of federal tax, to an amount that will more likely than not be realized by the Company.

Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the excess tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. At December 31, 2013, $7 million of excess tax benefit was not included in the Company’s loss carryovers deferred tax asset. The $7 million excess tax benefit was recognized in 2014 due to the utilization of loss carryovers.

Through the effective date of our spin-off from The Williams Companies, Inc. (“Williams”), December 31, 2011, our domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. Effective with the spin-off, we entered into a tax sharing agreement with Williams which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off. Pursuant to the tax sharing agreement, we remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. We are not aware of any significant adjustments related to our business, but the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments to 2011 unrelated to our business. Williams previously notified us of certain corrections that resulted in reductions in the alternative minimum tax credit allocated to us, of which $11 million was a reduction of a benefit for income taxes in 2012.

The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.

As of December 31, 2014, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.

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

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Quarterly Financial Data Quarterly Financial Data-Summarized Quarterly Financial Data (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Line Items]
Revenues	$ 1,125	$ 747	$ 727	$ 894	$ 576	$ 581	$ 722	$ 552	$ 3,493	$ 2,431	$ 2,900
Operating costs and expenses	656	570	659	783	1,024	621	612	634
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	227	46	(144)	0	(890)	(105)	6	(115)	129	(1,104)	(174)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	(8)	20	11	19	(94)	(11)	16	2	42	(87)	(37)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	219	66	(133)	19	(984)	(116)	22	(113)	171	(1,191)	(211)
Income (Loss) from Continuing Operations Attributable to WPX	227	46	(144)	0	(878)	(105)	6	(115)	129	(1,092)	(174)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX	(8)	16	9	18	(95)	(9)	12	(1)	35	(93)	(49)
Net Income (Loss) Attributable to Parent	$ 219	$ 62	$ (135)	$ 18	$ (973)	$ (114)	$ 18	$ (116)	$ 164	$ (1,185)	$ (223)
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.11	$ 0.23	$ (0.71)	$ 0.00					$ 0.63	$ (5.45)	$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	$ (0.03)	$ 0.07	$ 0.05	$ 0.09					$ 0.18	$ (0.46)	$ (0.25)
Earnings Per Share, Basic	$ 1.08	$ 0.30	$ (0.66)	$ 0.09					$ 0.81	$ (5.91)	$ (1.12)
Income (Loss) from Continuing Operations, Per Diluted Share	$ 1.10	$ 0.23	$ (0.71)	$ 0.00					$ 0.62	$ (5.45)	$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	$ (0.04)	$ 0.07	$ 0.05	$ 0.09					$ 0.18	$ (0.46)	$ (0.25)
Earnings Per Share, Diluted	$ 1.06	$ 0.30	$ (0.66)	$ 0.09					$ 0.80	$ (5.91)	$ (1.12)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share					$ (4.37)	$ (0.52)	$ 0.03	$ (0.57)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share					$ (0.48)	$ (0.05)	$ 0.06	$ (0.01)
Earnings Per Share, Basic and Diluted					$ (4.85)	$ (0.57)	$ 0.09	$ (0.58)

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 24, 2015	Jun. 30, 2014
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	WPX
Entity Registrant Name	WPX ENERGY, INC.
Entity Central Index Key	0001518832
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		203,877,415
Entity Public Float			$ 4,832,711,197

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Contingent Liabilities and Commitments

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

Contingent Liabilities and Commitments

Royalty litigation

In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We have completed the accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to seek a stay of this new lawsuit pending resolution of the first lawsuit in the Colorado Court of Appeals.

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.

Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2008 through December 2014, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $113 million.

Environmental matters

The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Matters related to Williams’ former power business

In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion on the Western States Antitrust Litigation. The panel held that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims, reversing the summary judgment entered in favor of the defendants. The panel further held that the district court did not abuse its discretion in denying the plaintiffs’ motions for leave to amend complaints. The U.S. Supreme Court granted Defendants' writ of certiorari. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.

Other Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.

At December 31, 2014, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

In connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.

Summary

As of December 31, 2014 and December 31, 2013, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

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

Commitments

As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2014 are as follows:

	(Millions)
2015	$	177
2016	162
2017	149
2018	138
2019	126
Thereafter	389
Total	$	1,141

Also, in conjunction with the closing of the Powder River sale and current terms therein, we may record certain pipeline capacity obligations held by our marketing company associated with our exiting the Powder River Basin. Our total commitments related to these pipeline agreements for 2015 and beyond total $172 million.

We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services, which total $305 million over approximately six years.

Excluded from the pipeline capacity and natural gas gathering and treating services commitments discussed above are commitments totaling $88 million and $43 million, respectively, which have been or are assumed to be assigned to the buyers of assets held for sale.

In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:

	(Millions)
2015	$	37
2016	32
2017	11
2018	7
2019	7
Thereafter	15
Total	$	109

Leases totaling $0.5 million associated with assets held for sale are excluded from the operating lease commitments discussed above.

Total rent expense, excluding amounts capitalized, was $27 million, $27 million and $19 million in 2014, 2013 and 2012, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.

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Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Fair Value Disclosures [Abstract]
Impairment of producing properties and costs of acquired unproved reserves (Note 4)	$ 20	[1]	$ 1,055	[2]	$ 225	[3]
Unproved leasehold	0		317	[2]	0
Equity method investment (Note 4)	$ 0		$ 20	[2]	$ 0

[1] As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:•$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.•$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

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

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

[1] (a)Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.

[2] (b)Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.

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

[1] Excludes related impairments of unproved leasehold included in exploration expenses.

[2] For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

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Earnings (Loss) Per Common Share from Continuing Operations

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

Earnings (Loss) Per Common Share from Continuing Operations

 Thefollowing table summarizes the calculation of earnings per share.

	Years Ended December 31,
	2014		2013			2012
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	129	$	(1,092	)	$	(174	)
Basic weighted-average shares	202.7		200.5			198.8
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	2.7
Stock options	0.9
Diluted weighted-average shares	206.3		200.5			198.8
Earnings (loss) per common share from continuing operations:
Basic	$	0.63	$	(5.45	)	$	(0.87	)
Diluted	$	0.62	$	(5.45	)	$	(0.87	)

__________

(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

The table below includes information related to stock options that were outstanding at December 31, 2014, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.

	2014		2013		2012
Options excluded (millions)	1.4		0.4		1.3
Weighted-average exercise price of options excluded	$	18.42	$	20.24	$	18.17
Exercise price range of options excluded	$16.46 - $21.81		$20.21  - $20.97		$16.46  - $20.97
Fourth quarter weighted-average market price	$	15.96	$	19.97	$	16.15

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Discontinued Operations

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

Discontinued Operations

On October 3, 2014, we announced an agreement to sell our international interests for approximately $294 million subject to the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco. During January 2015 we completed the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol. Together, these non-operated international holding comprised our international segment. We expect to book a gain of approximately $40 million related to this transaction during first quarter 2015.

During the third quarter of 2014, our management signed an agreement to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million, subject to closing adjustments such as net revenues from effective date to closing date. We continue to negotiate the divestiture. The original sales agreement was scheduled to terminate February 13, 2015, but both parties agreed to extend the timetable. If the agreement does not successfully close in March, WPX has the option to terminate the transaction. Additionally, we have recorded a $45 million impairment of the net assets to a probability weighted-average of expected sales prices. The Company has not actively drilled in the basin since 2011. The Powder River operations have firm gathering and treating agreements with total commitments of $128 million through 2020. These commitments have been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2015 and beyond totaling $172 million. Depending on the final terms upon closing of the Powder River sale, we may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Powder River Basin.

During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.

Summarized Results of Discontinued Operations

For the year ended December 31, 2014	Domestic		International		Total
			(Millions)
Total revenues	$	189	$	163	$	352
Costs and expenses:
Lease and facility operating	$	41	$	37	$	78
Gathering, processing and transportation	70		1		71
Taxes other than income	16		28		44
Exploration	—		4		4
Depreciation, depletion and amortization	11		42		53
Impairment of assets held for sale	45		—		45
General and administrative	4		16		20
Other—net	—		12		12
Total costs and expenses	187		140		327
Operating income (loss)	2		23		25
Interest capitalized	1		—		1
Investment income and other	6		19		25
Income (loss) from discontinued operations before income taxes	9		42		51
Provision (benefit) for income taxes(a)	2		7		9
Income (loss) from discontinued operations	$	7	$	35	$	42

__________

(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.

For the year ended December 31, 2013	Domestic			International		Total
				(Millions)
Total revenues	$	178		$	152	$	330
Costs and expenses:
Lease and facility operating	$	44		$	37	$	81
Gathering, processing and transportation	80			3		83
Taxes other than income	15			24		39
Exploration	1			7		8
Depreciation, depletion and amortization	48			34		82
Impairment of producing properties and costs of acquired unproved reserves	192			3		195
Gain on sale of Powder River Basin deep rights leasehold	(36		)	—		(36		)
General and administrative	6			14		20
Other—net	5			—		5
Total costs and expenses	355			122		477
Operating income (loss)	(177		)	30		(147		)
Interest capitalized	4			—		4
Investment income and other	4			21		25
Income (loss) from discontinued operations before income taxes	(169		)	51		(118		)
Provision (benefit) for income taxes(a)	(62		)	31		(31		)
Income (loss) from discontinued operations	$	(107	)	$	20	$	(87	)

__________

(a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

For the year ended December 31, 2012	Domestic			International		Total
				(Millions)
Total revenues	$	180		$	137	$	317
Costs and expenses:
Lease and facility operating	$	65		$	32	$	97
Gathering, processing and transportation	74			2		76
Taxes other than income	19			24		43
Gas management, including charges for unutilized pipeline capacity	1			—		1
Exploration	1			11		12
Depreciation, depletion and amortization	62			27		89
Impairment of producing properties and costs of acquired unproved reserves	102			—		102
Gain on sale of Barnett Shale and Arkoma Basin holdings	(38		)	—		(38		)
General and administrative	10			14		24
Other—net	(1		)	—		(1		)
Total costs and expenses	295			110		405
Operating income (loss)	(115		)	27		(88		)
Interest capitalized	6			—		6
Investment income and other	4			27		31
Income (loss) from discontinued operations before income taxes	(105		)	54		(51		)
Provision (benefit) for income taxes	(38		)	24		(14		)
Income (loss) from discontinued operations	$	(67	)	$	30	$	(37	)

Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations

December 31, 2014	Domestic			International			Total
				(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—		$	29		$	29
Accounts receivable	—			25			25
Inventories	1			7			8
Other	—			14			14
Total current assets	1			75			76
Investments	18			134			152
Properties and equipment (successful efforts method of accounting)(a)	132			445			577
Less—accumulated depreciation, depletion and amortization	(10		)	(228		)	(238		)
Properties and equipment, net	122			217			339
Other noncurrent assets	—			6			6
Total assets classified as held for sale—discontinued operations	$	141		$	432		$	573
Total assets classified as held for sale—continuing operations (Note 4)	200			—			200
Total assets classified as held for sale on the Consolidated Balance Sheets	$	341		$	432		$	773
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—		$	34		$	34
Accrued and other current liabilities	3			23			26
Total current liabilities	3			57			60
Deferred income taxes	—			13			13
Long-term debt	—			2			2
Asset retirement obligations	45			7			52
Other noncurrent liabilities	—			3			3
Total liabilities associated with assets held for sale—discontinued operations	$	48		$	82		$	130
Total liabilities associated with assets held for sale—continuing operations (Note 4)	$	2		$	—		$	2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	50		$	82		$	132

__________

(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

December 31, 2013	Domestic		International			Total
			(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—	$	51		$	51
Accounts receivable	—		18			18
Inventories	1		5			6
Other	—		17			17
Total current assets	1		91			92
Investments	17		125			142
Properties and equipment (successful efforts method of accounting)	166		360			526
Less—accumulated depreciation, depletion and amortization	—		(194		)	(194		)
Properties and equipment, net	166		166			332
Total assets classified as held for sale—discontinued operations(a)	$	184	$	382		$	566
Total assets classified as held for sale—continuing operations (Note 4)(a)	148		—			148
Total assets classified as held for sale on the Consolidated Balance Sheets(a)	$	332	$	382		$	714
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	18		$	18
Accrued and other current liabilities	3		20			23
Total current liabilities	3		38			41
Deferred income taxes	—		12			12
Long-term debt	—		5			5
Asset retirement obligations	47		4			51
Total liabilities associated with assets held for sale—discontinued operations(a)	$	50	$	59		$	109
Total liabilities associated with assets held for sale—continuing operations (Note 4)	2		—			2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(a)	$	52	$	59		$	111

__________

(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.

Noncontrolling interests in consolidated subsidiaries of $109 million and $101 million as of December 31, 2014 and 2013, respectively, related to assets classified as held for sale.

Cash Flows Attributable to Discontinued Operations

Excluding taxes and changes to working capital related to Powder River Basin, total cash provided by operating activities related to discontinued operations was $65 million, $36 million and $18 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related to Powder River Basin discontinued operations was $11 million, $3 million and $20 million for 2014, 2013 and 2012, respectively. Cash provided by operating activities related to our international operations was $65 million, $56 million and $50 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related our international operations was $85 million, $43 million and $56 million for 2014, 2013 and 2012, respectively.

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Derivatives and Concentration of Credit Risk

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Concentration of Credit Risk

Derivatives and Concentration of Credit Risk

Energy Commodity Derivatives

Risk Management Activities

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.

We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.

We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.

Derivatives related to production

The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2014.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Natural Gas
Natural Gas	2015	Fixed Price Swaps	Henry Hub	(442	)	$	4.10
Natural Gas	2015	Costless Collars	Henry Hub	(50	)	$ 4.00 - 4.50
Natural Gas	2015	Basis Swaps	NGPL	(13	)	$	(0.16	)
Natural Gas	2015	Basis Swaps	Rockies	(150	)	$	(0.11	)
Natural Gas	2015	Basis Swaps	San Juan	(85	)	$	(0.10	)
Natural Gas	2015	Basis Swaps	SoCal	(20	)	$	0.18
Natural Gas	2016	Fixed Price Swaps	Henry Hub	(200	)	$	3.98
Natural Gas	2016	Swaptions	Henry Hub	(90	)	$	4.23
Natural Gas	2017	Swaptions	Henry Hub	(65	)	$	4.19
Crude Oil
Crude Oil	2015	Fixed Price Swaps	WTI	(20,236	)	$	94.88
Crude Oil	2015	Swaptions	WTI	(882	)	$	97.29
Crude Oil	2016	Swaptions	WTI	(5,250	)	$	97.55

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.

(b) Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.

(c) The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

Derivatives primarily related to transportation

The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.

Commodity	Period	Contract Type (a)	Location (b)	Notional Volume (c)
Natural Gas	2015	Basis Swaps	Multiple	(3	)
Natural Gas	2015	Index	Multiple	(118	)
Natural Gas	2016	Index	Multiple	(70	)
Natural Gas	2017	Index	Multiple	(70	)
Natural Gas	2018+	Index	Multiple	(379	)

__________

(a) We enter into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.

(b) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.

(c) Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.

Fair values and gains (losses)

The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

	December 31,
	2014				2013
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Derivatives related to production not designated as hedging instruments	$	517	$	10	$	26	$	39
Derivatives related to physical marketing agreements not designated as hedging instruments	19		32		31		83
Total derivatives not designated as hedging instruments	$	536	$	42	$	57	$	122

The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.

	Years Ended December 31,						Classification
	2014		2013		2012
			(Millions)
Net gain recognized in other comprehensive income (loss) (effective portion)	$	—	$	—	$	90	AOCI
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)	$	—	$	5	$	434	Revenues

__________

(a) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.

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

	Years Ended December 31,
	2014			2013			2012
Gain (loss) from derivatives related to production not designated as hedging instruments (a)	$	515		$	(57	)	$	66
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)	(81		)	(67		)	12
Net gain (loss) on derivatives not designated as hedges	$	434		$	(124	)	$	78

__________

(a) Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.

(b) Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.

The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

Offsetting of derivative assets and liabilities

The following table presents our gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet			Netting Adjustments (a)			Cash Collateral Posted(Received)		Net Amount
December 31, 2014	(Millions)
Derivative assets with right of offset or master netting agreements	$	536		$	(25	)	$	—	$	511
Derivative liabilities with right of offset or master netting agreements	$	(42	)	$	25		$	17	$	—
December 31, 2013
Derivative assets with right of offset or master netting agreements	$	57		$	(50	)	$	—	$	7
Derivative liabilities with right of offset or master netting agreements	$	(122	)	$	50		$	52	$	(20	)

__________

(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from S&P’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

As of December 31, 2014, we had collateral totaling $26 million posted to derivative counterparties, which includes $9 million of initial margin to clearinghouses or exchanges to enter into positions and $17 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $17 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2013, we had collateral totaling $71 million posted to derivative counterparties, which includes $19 million of initial margin to clearinghouses or exchanges to enter into positions and $52 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $72 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was less than $1 million at December 31, 2014 and $20 million at December 31, 2013.

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark-to-market value. As of December 31, 2012, we had hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) were expected to be reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Actual gains or losses realized in the first quarter of 2013 matched these values. These gains substantially offset net losses that were realized in earnings from previous unfavorable market movements associated with underlying hedged transactions.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:

	2014		2013
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	340	$	339
Joint interest owners	106		168
Other	13		11
Total	$	459	$	518

Natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2014, 2013 and 2012, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

The gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:

Counterparty Type	Gross Total			Net Total
	(Millions)
Gas and electric utilities, integrated oil and gas companies, and other	$	4		$	4
Financial institutions (Investment Grade) (a)	533			508
	537			512
Credit reserves	(1		)	(1		)
Credit exposure from derivatives	$	536		$	511

__________

(a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Our nine largest net counterparty positions represent approximately 96 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

Other

At December 31, 2014, we held collateral support of approximately $32 million, either in the form of cash or letters of credit, related to our gas management sale agreements.

The customer margin deposits payable as of December 31, 2014 related to our commodity agreements. Collateral support for our commodity agreements could also include letters of credit and guarantees of payment by credit worthy parties.

Revenues

During 2014, 2013 and 2012, BP Energy Company, a domestic segment customer, accounted for 13 percent, 16 percent and 11 percent of our consolidated revenues, respectively. During 2014 and 2013, Southern California Gas Company accounted for 8 percent and 11 percent of our consolidated revenues, respectively. Williams accounted for 14 percent of our consolidated revenue for 2012. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2014

Postemployment Benefits [Abstract]

Employee Benefit Plans

Employee Benefit Plans

WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $17 million, $16 million and $6 million for 2014, 2013 and 2012, respectively. Approximately $10 million and $11 million were included in accrued and other current liabilities at December 31, 2014 and December 31, 2013 respectively, related to the non-matching annual employer contribution.

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

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Accounts Payable and Accrued and Other Current Liabilities

12 Months Ended

Dec. 31, 2014

Payables and Accruals [Abstract]

Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable

	December 31,
	2014		2013
	(Millions)
Trade	$	215	$	208
Accrual for capital expenditures	313		225
Royalties	125		130
Cash overdrafts	—		35
Other	59		36
	$	712	$	634

Accrued and other current liabilities

	December 31,
	2014		2013
	(Millions)
Taxes other than income taxes	$	41	$	41
Accrued interest	53		43
Compensation and benefit related accruals	55		52
Other, including other loss contingencies	28		31
	$	177	$	167

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Debt and Banking Arrangements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014 Contract	Nov. 30, 2011	Sep. 30, 2014
Debt Instrument [Line Items]
Debt redemption price as percentage of principal amount	100.00%
Debt Instrument, Description of Variable Rate Basis	0.01875
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.88%
Line of Credit Facility, Commitment Fee Percentage	0.30%
Limit On Consolidated Indebtedness to Consolidated EBITDAX	3.75
Reduction Attributable to Cash Maximum	$ 50,000,000
Maximum ratio of debt to capitalization	60.00%
Number of letter of credit agreements	3
Letters of credit issued	320,000,000
Unsecured Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility agreement	1,500,000,000.0
Debt instrument maturity period	5 years
Debt instrument additional borrowing capacity	300,000,000
Weighted average interest rate	3.01%
Outstanding amount	280,000,000
Unsecured Revolving Credit Facility | Federal Funds Rate
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Unsecured Revolving Credit Facility | one-month LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
5.250% Senior Notes due 2017
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		400,000,000
Senior Notes
Debt Instrument [Line Items]
Net proceeds from debt offering			494,000,000
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		1,100,000,000.0
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount			$ 500,000,000
Change of Control
Debt Instrument [Line Items]
Percentage of repurchase of notes on principal amount of notes	101.00%
Prior to December 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness	1.25
After December 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness	1.50

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Asset Sales, Impairments and Exploration Expenses

12 Months Ended

Dec. 31, 2014

Extractive Industries [Abstract]

Asset Sales, Impairments and Exploration Expenses

Asset Sales, Impairments and Exploration Expenses

In 2014, we recorded a total of $87 million in impairment charges associated with exploratory well costs and producing properties of which approximately $20 million is recorded as a separate line on the Consolidated Statements of Operations and $67 million is included in exploration expenses. In 2013, we recorded a total of $1.2 billion in impairment charges of which $860 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expenses and $20 million is included in investment income, impairment of equity method investment and other. These impairments are discussed further in the sections below.

Asset Sales

In June 2014, we sold portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP (“Legacy”) for $325 million cash with an effective date of January 1, 2014. The terms of the sale also provided us with a 10 percent ownership in a newly created class of incentive distribution rights (“IDR”) of Legacy. The working interests represented approximately 300 Bcfe of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. Production related to these working interests for January 2014 through May 2014 approximated 70 MMcfe per day of our production. Based on an estimated total value received of $329 million, which represents estimated final cash proceeds and an estimated fair value of the IDRs, we recorded a $195 million loss on the sale in second quarter 2014. In the third quarter of 2014, we recorded an additional loss on sale of $1 million related to this transaction.

On December 3, 2014, we announced that we have agreed to sell our operations in northeast Pennsylvania and release certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $300 million in cash. Net property, plant and equipment related to this transaction, as of December 31,2014, was $200 million and asset retirement obligation liability was $2 million. The transaction includes physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 operated horizontal wells. The assets are primarily located in Susquehanna County, Pennsylvania. The transaction also includes the release of firm transportation capacity that we have under contract in the northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we will be released from approximately $24 million per year in annual demand obligations associated with the transport. The transaction subsequently closed on January 30, 2015 and we estimate a net gain of at least $75 million will be recorded in first quarter 2015.

Impairments

The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments.

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)	$	20	$	860	$	123
Impairment of equity method investment in Appalachian Basin	$	—	$	20	$	—

__________

(a) Excludes related impairments of unproved leasehold included in exploration expenses.

As a result of declines in forward crude oil and natural gas prices primarily during the fourth-quarter 2014 as compared to forward prices as of December 31, 2013, we performed impairment assessments of our proved producing properties and costs of acquired unproved reserves. Accordingly, we recorded the following impairments during 2014:

• $11 million impairment in the fourth quarter in the Green River Basin; and

• $9 million of impairments in the fourth quarter of other properties.

As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded the following impairments during 2013:

• $772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin; and

• $88 million impairment in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area.

The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.

As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded the following impairments during 2012:

• $75 million impairment of capitalized costs of acquired unproved reserves in the Piceance Basin; and

• $48 million impairment of proved producing oil and gas properties in the Green River Basin.

Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 13).

Exploration Expenses

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Geologic and geophysical costs	$	11	$	18	$	12
Impairments of exploratory area well costs and dry hole costs	88		3		1
Unproved leasehold property impairments, amortization and expiration	74		402		58
Total exploration expenses	$	173	$	423	$	71

Impairments of exploratory well and dry hole costs for 2014 include $67 million of impairment related to our Niobrara Shale well costs in the Piceance Basin and $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities. The remaining amount represents dry hole costs associated with exploratory wells where hydrocarbons were not detected. The $67 million Niobrara Shale impairment relates to carrying costs on producing and science wells in excess of estimated discounted cash flows of the exploratory play. We continue to evaluate the potential of our Niobrara Shale exploratory play and plan to drill additional wells in 2015. As of December 31, 2014, our total domestic capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $37 million.

Unproved leasehold impairment, amortization and expiration in 2014 includes impairments of $41 million for unproved leasehold costs in exploratory areas where the company no longer intends to continue exploration activities.

Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold associated with our impairment of the producing properties in the Appalachian Basin.

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Properties and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Properties and Equipment

Properties and Equipment

Properties and equipment is carried at cost and consists of the following:

	Estimated Useful Life(a) (Years)	December 31,
		2014			2013
		(Millions)
Proved properties	(b)	$	10,386		$	10,955
Unproved properties	(c)	394			316
Gathering, processing and other facilities	15-25	251			209
Construction in progress	(c)	541			353
Other	3-40	181			178
Total properties and equipment, at cost		11,753			12,011
Accumulated depreciation, depletion and amortization		(4,911		)	(5,251		)
Properties and equipment—net		$	6,842		$	6,760

__________

(a) Estimated useful lives are presented as of December 31, 2014.

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

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

During 2014, we purchased oil and natural gas properties in the San Juan Basin for $150 million. The properties purchased included both producing wells and undeveloped locations. Approximately $50 million of the purchase price was allocated to proved producing properties and the remainder to proved undeveloped or unproved leasehold within properties and equipment. The purchase is included within our capital expenditures on the Consolidated Statements of Cash Flows. 

Also during 2014, we closed an agreement to farmout a portion of our Trail Ridge properties in the Piceance Basin with TRDC LLC, a subsidiary of G2X Energy. We received $50 million in cash for 49 percent of our working interests in approximately 100 proved developed wells and certain incurred drilling costs. TRDC LLC has committed to a $170 million drilling carry on nearly 400 future wells and will make additional investments for its 49 percent working interest.

Unproved properties consist primarily of non-producing leasehold in the San Juan, Williston and Piceance Basins.

Asset Retirement Obligations

Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.

A rollforward of our asset retirement obligations for the years ended 2014 and 2013 is presented below.

	2014			2013
	(Millions)
Balance, January 1	$	308		$	261
Liabilities incurred	19			11
Liabilities settled	(2		)	(1		)
Liabilities associated with assets sold	(65		)	—
Estimate revisions	(78		)	17
Accretion expense(a)	19			20
Balance, December 31	$	201		$	308
Amount reflected as current	$	3		$	3

__________

(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Estimate revisions in 2014 are primarily associated with decreases in anticipated plug and abandonment costs.

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Debt and Banking Arrangements

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt and Banking Arrangements

Debt and Banking Arrangements

As of the indicated dates, our debt consisted of the following:

	December 31,
	2014 (a)		2013 (a)
	(Millions)
5.250% Senior Notes due 2017	$	400	$	400
6.000% Senior Notes due 2022	1,100		1,100
5.250% Senior Notes due 2024	500		—
Credit facility agreement	280		410
Other	1		2
Total debt	$	2,281	$	1,912
Less: Current portion of long-term debt	1		1
Total long-term debt	$	2,280	$	1,911

__________

(a) Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

Senior Notes

In November 2011, we issued $400 million aggregate principal amount of 5.25% Senior Notes due 2017 (the “2017 Notes”) and $1.1 billion aggregate principal amount of 6.00% Senior Notes due 2022 (the “2022 Notes”) pursuant to a private offering, and in June 2012 we exchanged these notes for registered 2017 Notes and 2022 Notes. The 2017 Notes and 2022 Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee.

In September 2014, we issued $500 million aggregate principal amount of 5.25% Senior Notes due 2024 (“the 2024 Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 2024 Notes were issued under an indenture, as supplemented by a supplemental indenture, each between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the 2024 Notes were approximately $494 million after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility.

The terms of the indentures governing our 2017 Notes, 2022 Notes and 2024 Notes are substantially identical.

Optional Redemption. We have the option prior to maturity for the 2017 Notes, prior to October 15, 2021 for the 2022 Notes, and prior to June 15, 2024 for the 2024 Notes to redeem some or all of such notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. We also have the option at any time or from time to time on or after October 15, 2021 to redeem the 2022 Notes, or on or after June 15, 2024, to redeem the 2024 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date.

Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.

Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.

Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:

(1) a default in the payment of interest on the notes when due that continues for 30 days;

(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity, upon redemption, or otherwise;

(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and

(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.

Credit Facility Agreement

In October 2014, we amended and restated our $1.5 billionfive-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility Agreement matures on October 28, 2019. As of December 31, 2014, the weighted average variable interest rate was 3.01% on the $280 million outstanding under the Credit Facility Agreement. As of February 25, 2015, we did not have any outstanding borrowings under the Credit Facility Agreement as proceeds from asset sales were used to repay all outstanding amounts.

Interest on borrowings under the Credit Facility Agreement are payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5%, (ii) Citibank, N.A.'s publicly announced prime rate, and (iii) one-month LIBOR plus 1.0%. The Applicable Rate is defined in the Credit Facility Agreement and is determined by which interest rate we select and the ratings of our long-term unsecured debt. At December 31, 2014, the Applicable Rate was 1.875% on our LIBOR loans and 0.875% on our alternate base rate loans. Additionally, we will be required to pay a commitment fee, based on the ratings of our long-term unsecured debt, on the unused portion of the commitments under the Credit Facility Agreement. At December 31, 2014, the commitment fee rate was 0.30%.

Under the Credit Facility Agreement, when our long-term unsecured debt rating is not BBB- or better by S&P or Baa3 or better by Moody’s and the other of the two ratings is not less than BB+ by S&P or Ba1 by Moody's, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the Credit Facility Agreement) to Consolidated EBITDAX (as defined in the Credit Facility Agreement) of not greater than 3.75 to 1.00. Consolidated Net Indebtedness includes a reduction attributable to unrestricted cash and cash equivalents not to exceed $50 million. Consolidated EBITDAX will be calculated for the four fiscal quarters ending on the last day of any fiscal quarter for which financial statements have been or were required to be delivered. Additionally, the ratio of Consolidated Indebtedness (defined as Indebtedness of us and our consolidated subsidiaries determined on a consolidated basis) to Consolidated Total Capitalization (defined as Consolidated Indebtedness plus Consolidated Net Worth) will not be permitted to be greater than 60 percent and will be applicable for the life of the agreement.

When our long-term unsecured debt rating is BB or worse by S&P and Ba2 or worse by Moody's or BB- or worse by S&P or Ba3 or worse by Moody's, we will also be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the Credit Facility Agreement, to Consolidated Indebtedness ratio of at least 1.25 to 1.00 for fiscal periods ending on or prior to December 31, 2015, and 1.50 to 1.00 for fiscal periods ending after December 31, 2015. Based on our current long-term unsecured debt ratings, as of the date of this filing, we are not required to comply with this covenant. In addition, this covenant will not apply at any time after the occurrence of the Investment Grade Date, which is the first date after closing on which our long-term unsecured debt is rated BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or watch by either agency), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.

The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness; our and our subsidiaries' ability to grant certain liens, materially change the nature of our or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of our material subsidiaries to enter into certain restrictive agreements; our and our material subsidiaries' ability to enter into certain affiliate transactions; and our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person. We and our subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to certain exceptions and/or standards of materiality applicable to the contracting parties that differ from those applicable to investors.

The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.

Letters of Credit

WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2014 a total of $320 million in letters of credit have been issued.

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

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

[1] Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.

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

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

[1] Deducted from related assets.

[2] Deducted from related assets, with a portion included in assets held for sale.

[3] Included in revenues.

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

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Quarterly Financial Data -Adjusted Quarterly Financial Data (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended										12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data Adjustments [Line Items]
Revenues	$ 1,125	$ 747		$ 727	$ 894	$ 576	$ 581		$ 722	$ 552	$ 3,493	$ 2,431	$ 2,900
Operating costs and expenses	656	570		659	783	1,024	621		612	634
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	227	46		(144)	0	(890)	(105)		6	(115)	129	(1,104)	(174)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	(8)	20		11	19	(94)	(11)		16	2	42	(87)	(37)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	219	66		(133)	19	(984)	(116)		22	(113)	171	(1,191)	(211)
Income (Loss) from Continuing Operations Attributable to WPX	227	46		(144)	0	(878)	(105)		6	(115)	129	(1,092)	(174)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX	(8)	16		9	18	(95)	(9)		12	(1)	35	(93)	(49)
Net Income (Loss) Attributable to Parent	219	62		(135)	18	(973)	(114)		18	(116)	164	(1,185)	(223)
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.11	$ 0.23		$ (0.71)	$ 0.00						$ 0.63	$ (5.45)	$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	$ (0.03)	$ 0.07		$ 0.05	$ 0.09						$ 0.18	$ (0.46)	$ (0.25)
Earnings Per Share, Basic	$ 1.08	$ 0.30		$ (0.66)	$ 0.09						$ 0.81	$ (5.91)	$ (1.12)
Income (Loss) from Continuing Operations, Per Diluted Share	$ 1.10	$ 0.23		$ (0.71)	$ 0.00						$ 0.62	$ (5.45)	$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	$ (0.04)	$ 0.07		$ 0.05	$ 0.09						$ 0.18	$ (0.46)	$ (0.25)
Earnings Per Share, Diluted	$ 1.06	$ 0.30		$ (0.66)	$ 0.09						$ 0.80	$ (5.91)	$ (1.12)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share						$ (4.37)	$ (0.52)		$ 0.03	$ (0.57)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share						$ (0.48)	$ (0.05)		$ 0.06	$ (0.01)
Earnings Per Share, Basic and Diluted						$ (4.85)	$ (0.57)		$ 0.09	$ (0.58)
Quarterly [Member]
Quarterly Financial Data Adjustments [Line Items]
Revenues		47	[1]	(87)	(93)	(81)	35	[1]	(93)	(79)
Operating costs and expenses		31	[1]	62	(62)	(74)	22	[1]	(77)	(76)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		(15)	[1]	(11)	(19)	94	3	[1]	(16)	(2)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		15	[1]	11	19	(94)	(3)	[1]	16	2
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		0	[1]	0	0	0	0	[1]	0	0
Income (Loss) from Continuing Operations Attributable to WPX		(16)	[1]	(9)	(18)	95	9	[1]	(12)	1
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX		16	[1]	9	18	(95)	(9)	[1]	12	(1)
Net Income (Loss) Attributable to Parent		$ 0	[1]	$ 0	$ 0	$ 0	$ 0	[1]	$ 0	$ 0
Income (Loss) from Continuing Operations, Per Basic Share		$ (0.05)	[1]	$ (0.05)	$ (0.09)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share		$ 0.05	[1]	$ 0.05	$ 0.09
Earnings Per Share, Basic		$ 0.00	[1]	$ 0.00	$ 0.00
Income (Loss) from Continuing Operations, Per Diluted Share		$ (0.05)	[1]	$ (0.05)	$ (0.09)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share		$ 0.05	[1]	$ 0.05	$ 0.09
Earnings Per Share, Diluted		$ 0.00	[1]	$ 0.00	$ 0.00
Income (Loss) from Continuing Operations, Per Basic and Diluted Share						$ 0.48	$ 0.01	[1]	$ (0.06)	$ 0.01
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share						$ (0.48)	$ (0.01)	[1]	$ 0.06	$ (0.01)
Earnings Per Share, Basic and Diluted						$ 0.00	$ 0.00	[1]	$ 0.00	$ 0.00

[1] Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

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Accounts Payable and Accrued and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Payables and Accruals [Abstract]

Accounts Payable

Accounts Payable

	December 31,
	2014		2013
	(Millions)
Trade	$	215	$	208
Accrual for capital expenditures	313		225
Royalties	125		130
Cash overdrafts	—		35
Other	59		36
	$	712	$	634

Accrued and Other Current Liabilities

Accrued and other current liabilities

	December 31,
	2014		2013
	(Millions)
Taxes other than income taxes	$	41	$	41
Accrued interest	53		43
Compensation and benefit related accruals	55		52
Other, including other loss contingencies	28		31
	$	177	$	167

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

[1] Excludes related impairments of unproved leasehold included in exploration expenses.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Stockholders' Equity

Stockholders’ Equity

Common Stock

Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends were declared or paid for 2014, 2013 or 2012. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.

Preferred Stock

Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.

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Schedule II - Valuation And Qualifying Accounts

12 Months Ended

Dec. 31, 2014

Valuation and Qualifying Accounts [Abstract]

SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS

WPX Energy, Inc.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

	Beginning Balance		Charged (Credited) to Costs and Expenses			Other		Deductions			Ending Balance
2014:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	7	$	—		$	—	$	(1	)	$	6
Deferred tax asset valuation allowance(b)	102		(1		)	17		—			118
Price-risk management credit reserves—assets(a)(c)	—		—			1		—			1
2013:
Allowance for doubtful accounts—accounts and notes receivable(a)	11		(3		)	—		(1		)	7
Deferred tax asset valuation allowance(b)	19		80			3		—			102
2012:
Allowance for doubtful accounts—accounts and notes receivable(a)	13		(2		)	—		—			11
Deferred tax asset valuation allowance(b)	16		3			—		—			19

__________

(a) Deducted from related assets.

(b) Deducted from related assets, with a portion included in assets held for sale.

(c) Included in revenues.

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

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

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data Adjustments [Line Items]

Summarized Quarterly Financial Data

Summarized quarterly financial data are as follows:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Millions, except per-share amounts)
2014
Revenues	$	894		$	727		$	747		$	1,125
Operating costs and expenses	$	783		$	659		$	570		$	656
Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
Income (loss) from discontinued operations	19			11			20			(8		)
Net income (loss)	$	19		$	(133	)	$	66		$	219
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	—		$	(144	)	$	46		$	227
Income (loss) from discontinued operations	18			9			16			(8		)
Net income (loss)	$	18		$	(135	)	$	62		$	219
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.11
Income (loss) from discontinued operations	0.09			0.05			0.07			(0.03		)
Net income (loss)	$	0.09		$	(0.66	)	$	0.30		$	1.08
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	—		$	(0.71	)	$	0.23		$	1.10
Income (loss) from discontinued operations	0.09			0.05			0.07			(0.04		)
Net income (loss)	$	0.09		$	(0.66	)	$	0.30		$	1.06
2013
Revenues	$	552		$	722		$	581		$	576
Operating costs and expenses	$	634		$	612		$	621		$	1,024
Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(890	)
Income (loss) from discontinued operations	2			16			(11		)	(94		)
Net income (loss)	$	(113	)	$	22		$	(116	)	$	(984	)
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(115	)	$	6		$	(105	)	$	(878	)
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	(116	)	$	18		$	(114	)	$	(973	)
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.57	)	$	0.03		$	(0.52	)	$	(4.37	)
Income (loss) from discontinued operations	(0.01		)	0.06			(0.05		)	(0.48		)
Net income (loss)	$	(0.58	)	$	0.09		$	(0.57	)	$	(4.85	)

Quarterly Financial Data Adjustments [Table Text Block]

Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:

	First Quarter			Second Quarter			Third Quarter (a)			Fourth Quarter
	(Millions, except per-share amounts)
	(Increase, (Decrease))
2014
Revenues	$	(93	)	$	(87	)	$	47		N/A
Operating costs and expenses	$	(62	)	$	62		$	31		N/A
Income (loss) from continuing operations	$	(19	)	$	(11	)	$	(15	)	N/A
Income (loss) from discontinued operations	19			11			15			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	(18	)	$	(9	)	$	(16	)	N/A
Income (loss) from discontinued operations	18			9			16			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.09	)	$	(0.05	)	$	(0.05	)	N/A
Income (loss) from discontinued operations	0.09			0.05			0.05			N/A
Net income (loss)	$	—		$	—		$	—		N/A
2013
Revenues	$	(79	)	$	(93	)	$	35		$	(81	)
Operating costs and expenses	$	(76	)	$	(77	)	$	22		$	(74	)
Income (loss) from continuing operations	$	(2	)	$	(16	)	$	3		$	94
Income (loss) from discontinued operations	2			16			(3		)	(94		)
Net income (loss)	$	—		$	—		$	—		$	—
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	1		$	(12	)	$	9		$	95
Income (loss) from discontinued operations	(1		)	12			(9		)	(95		)
Net income (loss)	$	—		$	—		$	—		$	—
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.01		$	(0.06	)	$	0.01		$	0.48
Income (loss) from discontinued operations	(0.01		)	0.06			(0.01		)	(0.48		)
Net income (loss)	$	—		$	—		$	—		$	—

__________

(a) Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.

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Consolidated Statements of Comprehensive Income (Loss) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Condensed Statement of Income Captions [Line Items]
Comprehensive income (loss) attributable to WPX Energy, Inc.	$ 164		$ (1,188)		$ (440)
Other comprehensive income (loss):
Change in fair value of cash flow hedges, net of tax	0	[1]	0	[1]	57	[1]
Net reclassifications into earnings of net cash flow hedge gains, net of tax	0	[2]	(3)	[2]	(274)	[2]
Other comprehensive income (loss), net of tax	0		(3)		(217)
Net income (loss) attributable to WPX Energy, Inc.	$ (164)		$ 1,185		$ 223

[1] Change in fair value of cash flow hedges is net of income tax of $33 million for 2012. 2012 includes a $15 million before tax unrealized gain that was recognized in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations, as the underlying transaction was no longer probable of occurring (see Note 14).

[2] Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million and $159 million of income tax for 2013 and 2012, respectively. Before tax amounts realized and reclassified to product revenues, primarily natural gas sales revenues, on the Consolidated Statements of Operations were $5 million and $434 million for 2013 and 2012, respectively.

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

[1] We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

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

[1] Increase to properties and equipment$(1,934) $(1,207) $(1,449)Changes in related accounts payable127 53 (72)Capital expenditures$(1,807) $(1,154) $(1,521)

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

[1] Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.

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Derivatives and Concentration of Credit Risk - Derivative Volumes that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production (Detail) (Short)	12 Months Ended
	Dec. 31, 2014
2015 [Member] | Derivatives related to production | Crude Oil Commodity Contract One | Fixed Priced Swaps | WTI
Derivative [Line Items]
Notional Volume	(20,236)	[1],[2]
Underlying, Derivative	94.88	[1],[3]
2015 [Member] | Derivatives related to production | Crude Oil Commodity Contract Two | Swaptions | WTI
Derivative [Line Items]
Notional Volume	(882)	[1],[2]
Underlying, Derivative	97.29	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract One | Fixed Priced Swaps | Henry Hub
Derivative [Line Items]
Notional Volume	(442,000)	[1],[2]
Underlying, Derivative	4.10	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub
Derivative [Line Items]
Notional Volume	(50,000)	[1],[2]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Minimum
Derivative [Line Items]
Underlying, Derivative	4.00
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Three | Costless Collar | Henry Hub | Maximum
Derivative [Line Items]
Underlying, Derivative	4.50	[1],[4]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Five | Basis Swap | NGPL [Member]
Derivative [Line Items]
Notional Volume	(13,000)	[1],[2]
Underlying, Derivative	(0.16)	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Six | Basis Swap | Rockies
Derivative [Line Items]
Notional Volume	(150,000)	[1],[2]
Underlying, Derivative	(0.11)	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Seven | Basis Swap | San Juan [Member]
Derivative [Line Items]
Notional Volume	(85,000)	[1],[2]
Underlying, Derivative	(0.10)	[1],[3]
2015 [Member] | Derivatives related to production | Natural Gas Commodity Contract Seven | Basis Swap | Southern California Gas [Member]
Derivative [Line Items]
Notional Volume	(20,000)	[1],[2]
Underlying, Derivative	0.18	[1],[3]
2015 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Two | Basis Swap | Multiple Location
Derivative [Line Items]
Notional Volume	(3,000)	[4],[5],[6]
2015 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Three | Index | Multiple Location
Derivative [Line Items]
Notional Volume	(118,000)	[4],[5],[6]
2016 [Member] | Derivatives related to production | Crude Oil Commodity Contract Two | Swaptions | WTI
Derivative [Line Items]
Notional Volume	(5,250)	[1],[2]
Underlying, Derivative	97.55	[1],[3]
2016 [Member] | Derivatives related to production | Natural Gas Commodity Contract Eight | Fixed Priced Swaps | Henry Hub
Derivative [Line Items]
Notional Volume	(200,000)	[1],[2]
Underlying, Derivative	3.98	[1],[3]
2016 [Member] | Derivatives related to production | Natural Gas Commodity Contract Nine | Swaptions | Henry Hub
Derivative [Line Items]
Notional Volume	(90,000)	[1],[2]
Underlying, Derivative	4.23	[1],[3]
2016 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Five | Index | Multiple Location
Derivative [Line Items]
Notional Volume	(70,000)	[4],[5],[6]
2017 [Member] | Derivatives related to production | Natural Gas Commodity Contract Nine | Swaptions | Henry Hub
Derivative [Line Items]
Notional Volume	(65,000)	[1],[2]
Underlying, Derivative	4.19	[1],[3]
2017 [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Six | Index | Multiple Location
Derivative [Line Items]
Notional Volume	(70,000)	[4],[5],[6]
2018 and beyond [Member] | Derivatives primarily related to storage and transportation | Natural Gas Commodity Contract Seven | Index | Multiple Location
Derivative [Line Items]
Notional Volume	(379,000)	[4],[5],[6]

[1] (a)Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.

[2] (b)Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.

[3] (c)The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

[4] (c)Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.

[5] (a)We enter into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.

[6] (b)We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.

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Stock-Based Compensation - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Based Compensation Activity [Line Items]
Common stock share authorized	2,000,000,000	2,000,000,000
Employee stock purchase plan purchase price first offering start date	Mar. 01, 2012
Employee stock purchase plan purchase price first offering end date	Jun. 30, 2012
Stock option exercisable period	3 years
Stock option term	10 years
Restricted stock units vesting period	3 years
Unrecognized stock based compensation	$ 41
Value of stock option exercised during year	13	5	5
Cash received from stock option exercises	14	4	2
Unearned grant expected to be recognized in period			3 years
Minimum
Stock Based Compensation Activity [Line Items]
Range of vested shares of original grant amount	0.00%
Maximum
Stock Based Compensation Activity [Line Items]
Range of vested shares of original grant amount	200.00%
Nonvested Restricted Stock Units
Stock Based Compensation Activity [Line Items]
Performance based share granted, percent of nonvested restricted stock units outstanding	15.00%
Administrative expenses
Stock Based Compensation Activity [Line Items]
Stock based compensation expense	35	31	28
Stock Options
Stock Based Compensation Activity [Line Items]
Unrecognized stock based compensation	1
Unrecognized stock based compensation, weighted average period of recognition	1 year 9 months 18 days
Restricted Stock Units
Stock Based Compensation Activity [Line Items]
Unrecognized stock based compensation	$ 40
Two Thousand Thirteen Incentive Plan [Member]
Stock Based Compensation Activity [Line Items]
Common stock share authorized	19,800,000
Discount allowed on employee stock purchase plan	15.00%
Number of share purchased under stock option plan	124,000
Stock option plan, average purchase price	$ 12.56
Two Thousand Thirteen Incentive Plan [Member] | Maximum
Stock Based Compensation Activity [Line Items]
Number of share available for purchase under stock option plan	1,000,000

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Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Description of Business

Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.

In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of Powder River Basin and Apco are reported as discontinued operations.

The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we,” “us” or “our.”

Basis of Presentation

These financial statements are prepared on a consolidated basis.

Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.

Discontinued operations

On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.

Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).

See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions which impact these financials include:

• impairment assessments of long-lived assets;

• valuations of derivatives;

• estimation of natural gas and oil reserves;

• assessments of litigation-related contingencies; and

• asset retirement obligations.

These estimates are discussed further throughout these notes.

Cash and cash equivalents

Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Restricted cash

Restricted cash consists of approximately $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

Inventories

All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. The following table presents a summary of inventories.

	Years ended December 31,
	2014		2013
	(Millions)
Material, supplies and other	$	43	$	43
Crude oil production in transit	2		10
Natural gas in underground storage	—		13
	$	45	$	66

During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.

Properties and equipment

Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.

Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.

Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.

Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.

Depreciation, depletion and amortization

Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.

Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.

Impairment of long-lived assets

We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.

Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

Contingent liabilities

Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.

Asset retirement obligations

We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.

Cash flows from revolving credit facilities

Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.

Derivative instruments and hedging activities

We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.

We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.

Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

• unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;

• unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;

• the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;

• realized gains and losses on all derivatives that settle financially;

• realized gains and losses on derivatives held for trading purposes; and

• realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Product revenues

Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423 million in 2013 and 2012, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.

Gas management revenues and expenses

Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.

Charges for unutilized transportation capacity included in gas management expenses were $57 million, $61 million and $46 million in 2014, 2013 and 2012, respectively.

Capitalization of interest

We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million. We use the weighted average rate of our outstanding debt (see Note 7).

Income taxes

We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.

Employee stock-based compensation

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

Foreign exchange

Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.

Earnings (loss) per common share

Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 3).

Description of Business

Description of Business

Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.

In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of Powder River Basin and Apco are reported as discontinued operations.

The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we,” “us” or “our.”

Basis of Presentation

Basis of Presentation

These financial statements are prepared on a consolidated basis.

Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.

Discontinued operations

Discontinued operations

On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.

Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).

See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.

Principles of consolidation

Principles of consolidation

The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.

Use of estimates

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions which impact these financials include:

• impairment assessments of long-lived assets;

• valuations of derivatives;

• estimation of natural gas and oil reserves;

• assessments of litigation-related contingencies; and

• asset retirement obligations.

These estimates are discussed further throughout these notes.

Cash and cash equivalents

Cash and cash equivalents

Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Restricted cash

Restricted cash

Restricted cash consists of approximately $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.

Accounts receivable

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

Inventories

Inventories

All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. The following table presents a summary of inventories.

	Years ended December 31,
	2014		2013
	(Millions)
Material, supplies and other	$	43	$	43
Crude oil production in transit	2		10
Natural gas in underground storage	—		13
	$	45	$	66

During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.

Properties and equipment

Properties and equipment

Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.

Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.

Other capitalized costs

Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.

Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.

Depreciation, depletion and amortization

Depreciation, depletion and amortization

Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.

Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.

Impairment of long-lived assets

Impairment of long-lived assets

We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.

Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

Contingent liabilities

Contingent liabilities

Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.

Asset retirement obligations

Asset retirement obligations

We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.

Cash flows from revolving credit facilities

Cash flows from revolving credit facilities

Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.

Derivative instruments and hedging activities

Derivative instruments and hedging activities

We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.

We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.

Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

• unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;

• unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;

• the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;

• realized gains and losses on all derivatives that settle financially;

• realized gains and losses on derivatives held for trading purposes; and

• realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Product revenues

Product revenues

Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423 million in 2013 and 2012, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.

Gas management revenues and expenses

Gas management revenues and expenses

Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.

Charges for unutilized transportation capacity included in gas management expenses were $57 million, $61 million and $46 million in 2014, 2013 and 2012, respectively.

Capitalization of interest

Capitalization of interest

We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million. We use the weighted average rate of our outstanding debt (see Note 7).

Income taxes

Income taxes

We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.

Employee stock-based compensation

Employee stock-based compensation

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

Foreign exchange

Foreign exchange

Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.

Earnings (loss) per common share

Earnings (loss) per common share

Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 3).

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

[1] Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Stock Option Activity and Related Information

The following summary reflects stock option activity and related information for the year ended December 31, 2014.

	WPX Plan
Stock Options	Options		Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)				(Millions)
Outstanding at December 31, 2013(a)	4.1		$	13.27	$	29
Granted	0.4		$	19.03
Exercised	(1.3	)	$	11.11
Forfeited	(0.1	)	$	15.39
Outstanding at December 31, 2014(a)	3.1		$	14.80	$	2
Exercisable at December 31, 2014	2.7		$	14.26	$	2

__________

(a) Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.

Additional Information about Stock Options Outstanding and Exercisable

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2014.

	WPX Plan
	Stock Options Outstanding				Stock Options Exercisable
Range of Exercise Prices	Options	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life	Options	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life
	(Millions)			(Years)	(Millions)			(Years)
$ 6.02 to $10.68	0.5	$	7.59	2.8	0.5	$	7.59	2.8
$ 11.32 to $13.46	0.6	$	11.82	4.0	0.6	$	11.82	4.0
$14.41 to $18.23	1.5	$	16.39	6.1	1.2	$	16.36	5.6
$19.95 to $21.81	0.5	$	20.61	5.0	0.4	$	20.24	3.2
Total	3.1	$	14.80	5.0	2.7	$	14.26	4.4

Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model

The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows:

	WPX Plan
	2014			2013			2012
Weighted-average grant date fair value of options granted	$	18.94		$	6.04		$	7.79
Weighted-average assumptions:
Dividend yield	—			—			—
Volatility	43.0		%	42.8		%	43.8		%
Risk-free interest rate	1.85		%	1.06		%	1.17		%
Expected life (years)	5.9			6.0			6.0

Summary of Nonvested Restricted Stock Unit Activity and Related Information

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.

	WPX Plan
Restricted Stock Units	Shares		Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2013	5.2		$	16.97
Granted	2.5		$	18.37
Forfeited	(0.7	)	$	16.92
Vested	(1.9	)	$	16.92
Nonvested at December 31, 2014	5.1		$	17.58

__________

(a) Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Other Restricted Stock Unit Information

Other restricted stock unit information

	WPX Plan
	2014		2013		2012
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.37	$	14.97	$	17.35
Total fair value of restricted stock units vested during the year (millions)	$	33	$	18	$	14

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Stock-Based Compensation

WPX Energy, Inc. 2013 Incentive Plan

We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2013 Incentive Plan is 19.8 million shares. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.

The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 124 thousand shares at an average price of $12.56 per share during 2014.

Employee stock-based awards

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.

Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

Restricted stock units are generally valued at fair value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

Total stock-based compensation expense reflected in general and administrative expense for the years ended December 31, 2014, 2013 and 2012 was $35 million, $31 million and $28 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2014 was $41 million. This amount is comprised of $1 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2014.

	WPX Plan
Stock Options	Options		Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)				(Millions)
Outstanding at December 31, 2013(a)	4.1		$	13.27	$	29
Granted	0.4		$	19.03
Exercised	(1.3	)	$	11.11
Forfeited	(0.1	)	$	15.39
Outstanding at December 31, 2014(a)	3.1		$	14.80	$	2
Exercisable at December 31, 2014	2.7		$	14.26	$	2

__________

(a) Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.

The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $13 million, $5 million and $5 million, respectively.

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2014.

	WPX Plan
	Stock Options Outstanding				Stock Options Exercisable
Range of Exercise Prices	Options	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life	Options	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life
	(Millions)			(Years)	(Millions)			(Years)
$ 6.02 to $10.68	0.5	$	7.59	2.8	0.5	$	7.59	2.8
$ 11.32 to $13.46	0.6	$	11.82	4.0	0.6	$	11.82	4.0
$14.41 to $18.23	1.5	$	16.39	6.1	1.2	$	16.36	5.6
$19.95 to $21.81	0.5	$	20.61	5.0	0.4	$	20.24	3.2
Total	3.1	$	14.80	5.0	2.7	$	14.26	4.4

The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows:

	WPX Plan
	2014			2013			2012
Weighted-average grant date fair value of options granted	$	18.94		$	6.04		$	7.79
Weighted-average assumptions:
Dividend yield	—			—			—
Volatility	43.0		%	42.8		%	43.8		%
Risk-free interest rate	1.85		%	1.06		%	1.17		%
Expected life (years)	5.9			6.0			6.0

For 2014, 2013 and 2012, we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method.

Cash received from stock option exercises was $14 million, $4 million and $2 million during 2014, 2013 and 2012, respectively.

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.

	WPX Plan
Restricted Stock Units	Shares		Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2013	5.2		$	16.97
Granted	2.5		$	18.37
Forfeited	(0.7	)	$	16.92
Vested	(1.9	)	$	16.92
Nonvested at December 31, 2014	5.1		$	17.58

__________

(a) Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Other restricted stock unit information

	WPX Plan
	2014		2013		2012
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.37	$	14.97	$	17.35
Total fair value of restricted stock units vested during the year (millions)	$	33	$	18	$	14

Performance-based shares granted represent 15 percent of nonvested restricted stock units outstanding at December 31, 2014. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

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