10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018 

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  þ  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  þ

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    Yes  þ 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. þ

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

Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨ Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

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 $7,172,269,200.

The number of shares outstanding of the registrant’s common stock outstanding at February 20, 2019 was 420,465,218.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement to be delivered to stockholders in connection with its 2019 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	14
	Environmental Matters	16
	Competition	21
	Employees	22
	Financial Information about Segments	22
	Website Access to Reports and Other Information	22
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	39
Item 2.	Properties	39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
Item 9A.	Controls and Procedures	107
Item 9B.	Other Information	108
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	108
Item 11.	Executive Compensation	108
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	108
Item 13.	Certain Relationships and Related Transactions, and Director Independence	108
Item 14.	Principal Accountant Fees and Services	108
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	109

1

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.

Bcf—means one billion cubic feet of natural gas.

Boe—means one barrel of oil equivalent, calculated by converting natural gas volumes to equivalent oil barrels at a ratio of six Mcf to one barrel of oil.

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.

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.

MMbbls—means one million barrels.

MMboe—means one million barrels of oil equivalent.

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.

NGL—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.

2

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 oil and natural gas exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting, developing and growing our oil positions in the Delaware Basin (a subset of the Permian Basin) in Texas and New Mexico and the Williston Basin in North Dakota.

We have a geographically diverse portfolio of oil and natural gas reserves. Our proved reserves at December 31, 2018 were 479 MMboe. Our reserves reflect a mix of 61 percent crude oil, 21 percent natural gas and 18 percent NGLs. During 2018, we replaced our production for all commodities at a rate of 308 percent, before consideration of divestitures.

Our principal areas of operation are the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Our principal executive office is located at 3500 One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 855-979-2012. We maintain an Internet site at www.wpxenergy.com.

3

BUSINESS OVERVIEW AND PROPERTIES

Our Business Strategy

•Focused, Long-Term Portfolio Management. We are focused on long-term profitable growth. Our objective over time is disciplined production growth within our cash flow and reduce our costs. With that in mind, we regularly 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. Since mid-2014, we have undertaken $8 billion of asset acquisitions and divestitures, allowing us to focus on our core areas and strengthen our financial position. With regard to our core assets, we will allocate capital to the most profitable opportunities based on expected returns, commodity price cycles and other market conditions, enabling us to grow our reserves and production in a manner that maximizes our returns on investments.

•Margin Expansion thru Focus on Costs. We believe we can expand our margins by focusing on opportunities to reduce our cost structure and being disciplined both operationally and financially. This requires consistent execution as well as managing potential disruptions in our business. We continue to manage the cost and availability of skilled labor, drilling rigs and equipment, transportation and other supplies.

•Maintain Financial Flexibility. We believe our continued focus on cost reductions, increased capital efficiency and disciplined production growth will allow us to generate increased and sustainable annual cash flows from operations. This cash flow, combined with our capital structure and available sources of liquidity, will allow us to efficiently develop and grow our resource base and pursue reserve growth throughout a variety of commodity price environments. We have engaged and will continue to engage in commodity derivative hedging activities to maintain a degree of cash flow certainty. Typically, we target hedging at least 50 percent of expected revenue from 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 and the impact of such decisions on our leverage and ability to be cash flow neutral. See the Commodity Price Risk section of Item 7 for additional information regarding our derivatives.

•Build Asset Scale and Remain Opportunistic. We may 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 or leasehold exchanges that are directed at driving operational efficiencies through increased scale or contiguous acreage blocks. 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.

Significant Properties

Our principal areas of operation are the Delaware Basin (a subset of the Permian Basin) and Williston Basin.

Delaware Basin

We entered the Delaware Basin in August 2015 upon the closing of our acquisition of RKI Exploration & Production, LLC (“RKI”) (the “RKI Acquisition”). We operate 657 wells in the Delaware Basin and also own interests in 808 wells operated by others. We hold approximately 130,000 net acres in the Delaware Basin, with core operations located in Eddy, Lea and Chaves Counties in New Mexico and Loving, Pecos, Reeves, Ward and Winkler Counties in Texas. Approximately 79 percent of the leasehold is held by production. The Permian Basin is one of the most prolific hydrocarbon producing regions of the United States and spans an area approximately 250 miles wide by 300 miles long. The basin is characterized by numerous stacked reservoirs, high oil and natural gas content, extensive production history, long-lived reserves and high drilling success rates.

During 2018, we operated an average of 6.6 drilling rigs in the Delaware Basin and have had an average of 78.2 Mboe per day of net production. We expect to operate 5 rigs in the Delaware Basin in 2019. Capital expenditures in 2018, including land purchases and infrastructure, were approximately $1,048 million. During 2018, we completed 128 gross (87 net) wells and we have another 30 gross operated wells awaiting completion as of December 31, 2018. 

Our activity in the Delaware Basin is primarily focused on the Wolfcamp Shale formation and the Bone Spring interval (which includes the Avalon sand and shales, and the Bone Springs sands, shales and carbonates). We have a multi-year inventory of stacked pays (including the shallower Delaware sand interval) on approximately 130,000 net acres.

4

The Permian Basin, of which the Delaware Basin is a substantial sub-basin, covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita fold belt. It is one of the largest sedimentary basins in the United States, and has oil and gas production from several reservoirs from Permian through Ordovician in age.

From the mid-Pennsylvanian period to the early Permian period, the Delaware Basin was a slowly subsiding area that was characterized by shallow marine shales and limestone. Influxes of clastic sands generally occurred as turbidite deposits formed during periodic sea-level changes. Records indicate a rapid deepening of the Delaware Basin relative to the emergent Central Basin Platform, during the early Permian period. Marine shale deposition continued to dominate the basin during this period. Episodic pulses of carbonate and clastic debris and density flows punctuated the shale deposition and eventually became significant reservoirs. Through the late Permian period, the basin became increasingly more clastic dominated as emergent shelf areas to the north shed sands into the basin.

The Wolfcamp formation within the Delaware Basin is a long-established reservoir, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Wolfcamp reservoirs consist of debris-flow and grain-flow sediments, which were deposited in a submarine fan setting. The best carbonate reservoirs within the Wolfcamp are generally found in proximity to the Central Basin Platform, while the shale reservoirs thicken basinward away from the Central Basin Platform. The Wolfcamp contains organic-rich mudstone and shales which, when buried to sufficient depth for maturation, became the source of the hydrocarbons found both within the shales themselves and in the more conventional clastic and carbonate reservoirs between the shales.

We also have midstream and operational infrastructure in the Delaware Basin to support drilling activities and keep pace with production growth, including investing in low and high pressure gathering lines, compression systems, electrical power supply systems, fresh water supply systems and saltwater disposal systems. We believe these midstream assets provide a competitive advantage and reduce reliance on third parties for takeaway capacity. In October 2017, we closed a transaction with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area. At closing, we contributed crude oil gathering and natural gas processing assets already in service or under construction, and received a $300 million special distribution plus $49 million for capital expenditures in 2017 as part of Howard's $263 million carry obligation. In connection with this joint venture, we have dedicated our current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to twenty-year fixed-fee oil gathering and natural gas processing agreements. These agreements do not include any minimum volume commitments.

Some of our acreage in the Delaware Basin is leased to us by or with the approval of the federal government or its agencies, including the United States Forest Service and Bureau of Land Management (“BLM”). These particular leases are subject to federal authority, including the National Environmental Policy Act (“NEPA”), 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.

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 323 wells in the Williston Basin and also own interest in 87 wells operated by others. We hold 85,087 net acres in the Williston Basin.

During 2018, we operated an average of 2.8 rigs on our Williston Basin properties and we had an average of 48.9 Mboe per day of net production from our Williston Basin wells. We expect to operate 3 rigs in the Williston Basin in 2019. Capital expenditures in 2018 were approximately $412 million. During 2018, we completed 60 gross (52 net) wells and we have another 15 gross operated wells awaiting completion as of December 31, 2018.

We are developing oil reserves through horizontal drilling in the Middle Bakken and the Upper Three Forks 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.

5

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 part of the Pronghorn formation. 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 is leased to us by or with the approval of the federal government or its agencies, and is subject to federal authority, the 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 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.

Acquisitions and Divestitures

In March 2018, we sold our remaining operations in the San Juan Basin, comprised of an oil position in the Mancos Gallup Sandstone, for approximately $700 million (subject to closing and post-closing adjustments). After completion of the sale in 2018, we no longer have a presence in the San Juan Basin.

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 oil and natural gas 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 oil and natural gas 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 in the Delaware and Williston Basins located in the United States. As previously noted, we sold our remaining operations in the San Juan Basin in early 2018 and have reflected the San Juan Basin as discontinued operations.

6

Oil and Gas Reserves

The following table sets forth our estimated net proved developed and undeveloped reserves expressed by product and on an oil equivalent basis for the reporting periods December 31, 2018, 2017 and 2016.

	As of December 31, 2018
	Oil (Mbbls)	Gas (MMcf)	NGL (Mbbls)	Equivalent (Mboe)	%
Proved Developed	156,421	365,456	48,426	265,756	55%
Proved Undeveloped	134,884	252,265	36,611	213,539	45%
Total Proved	291,305	617,721	85,037	479,295

	As of December 31, 2017
	Oil (Mbbls)	Gas (MMcf)	NGL (Mbbls)	Equivalent (Mboe)	%
Proved Developed	130,333	321,231	38,813	222,685	51%
Proved Undeveloped	133,337	269,785	35,198	213,499	49%
Total Proved	263,670	591,016	74,011	436,184
Less: Discontinued operations	27,950	83,627	10,718	52,604
Total Proved less discontinued operations	235,720	507,389	63,293	383,580

	As of December 31, 2016
	Oil (Mbbls)	Gas (MMcf)	NGL (Mbbls)	Equivalent (Mboe)	%
Proved Developed	84,372	440,161	24,065	181,797	52%
Proved Undeveloped	90,191	294,240	25,378	164,609	48%
Total Proved	174,563	734,401	49,443	346,406
Less: Discontinued operations	20,817	367,943	8,820	90,961
Total Proved less discontinued operations	153,746	366,458	40,623	255,445

The following table sets forth our estimated net proved reserves for our largest areas of activity expressed by product and on an oil equivalent basis as of December 31, 2018.

	As of December 31, 2018
	Oil (Mbbls)	Gas (MMcf)	NGL (Mbbls)	Equivalent (Mboe)
Delaware Basin	161,982	540,306	70,345	322,377
Williston Basin	129,323	77,415	14,692	156,918
Total Proved	291,305	617,721	85,037	479,295

We prepare our own reserves estimates and approximately 100 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 2018 year-end estimated proved reserves reflect an average oil price of $61.57 per barrel, an average natural gas price of $1.21 per Mcf and average NGL price of $26.76 per barrel. These prices were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. During 2018, we added 137 MMboe of extensions and discoveries to our proved reserves. During 2018, we incurred $1,350 million in development expenditures which included the drilling of 235 gross (180 net) wells.

7

Proved reserves reconciliation

Production of 49 MMboe includes approximately 2 MMboe related to our oil-producing properties in the San Juan Basin through the completion of the sale. The 137 MMboe of extensions and discoveries reflects 52 MMboe added for drilled locations, and 85 MMboe added for new proved undeveloped locations. Of the extensions and discoveries, 70 percent were in the Delaware Basin. The divestitures of 51 MMboe primarily relates to the sale of our oil-producing properties in the San Juan Basin. The overall net positive revisions of 3 MMboe reflect 8 MMboe of net positive price revisions due to the increase in the 12-month average prices partially offset by 5 MMboe net negative technical revisions.

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 and shale reservoirs is established by combinations of subsurface analysis, 2D and 3D seismic analysis, and pressure data. Understanding of reservoir quality may be augmented by core 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 costs and oil/gas quality. The various departments and their roles in the year-end reserves process are coordinated by our corporate reserves department. The corporate reserves 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 corporate reserves department. After review by the corporate reserves 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, corporate reserves department and NSAI. In 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 corporate reserves department is independent and

8

does not work within an asset team or report directly to anyone on an asset team. The corporate reserves 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 corporate reserves department is not directly linked to reserves additions or revisions.

Approximately 100 percent of our total year-end 2018 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, 2018 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 Company’s internal technical person primarily responsible for overseeing preparation of the reserves estimates and the third-party reserves audit has 18 years of relevant experience in Reservoir and Evaluation Engineering, a B.S. in Petroleum Engineering from Montana Tech, and membership in the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

Proved undeveloped reserves

The majority of our reserves is concentrated in unconventional tight-sands and shale reservoirs. We use available geoscience and engineering data to establish drainage areas and reservoir continuity beyond one direct offset from a producing well, which may provide for additional proved undeveloped reserves. Inherent in the methodology is a requirement for significant well density of economically producing wells to establish reasonable certainty. In areas 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, 2018 and 2017 our proved undeveloped reserves were 214 MMboe.  Proved undeveloped reserves represents 45 percent and 49 percent of our total proved reserves as of December 31, 2018 and 2017, respectively.  Below is a reconciliation of our proved undeveloped reserves for 2018:

		% of	% of
	MMboe	December 31, 2017	December 31, 2018
Proved Undeveloped Reserves at December 31, 2017	214
Converted to Proved Developed Reserves	(63)	(29)%	(29)%
Extensions and Discoveries	85	40%	40%
Revisions	(13)	(6)%	(6)%
Acquisitions	2	1%	1%
Divestitures	(11)	(5)%	(5)%
Proved Undeveloped Reserves at December 31, 2018	214

During 2018, 63 MMboe of our December 31, 2017 proved undeveloped reserves were converted to proved developed reserves at a cost of $746 million of which $181 million was incurred in prior years. This represents a proved undeveloped conversion rate of 29 percent. Of the converted proved undeveloped reserves, 61 percent were in the Delaware Basin in the Bone Springs and Wolfcamp formations, and 39 percent were converted in the Williston Basin in the Bakken and Three Forks formations.

Of the 85 MMboe of proved undeveloped extensions and discoveries, 69 percent are in the Delaware Basin, primarily in the Wolfcamp formation, and 31 percent are in the Williston Basin in the Bakken and Three Forks formations.

In 2018, net negative revisions for our proved undeveloped reserves were 13 MMboe, which reflects 15 MMboe of downward technical revisions partially offset by an upward revision of 2 MMboe of reserves based on the 12-month trailing prices.

The 2 MMboe of proved undeveloped acquisitions relates to the Delaware Basin. The 11 MMboe of proved undeveloped divestitures relate to properties in the San Juan Basin that were sold in March 2018.

9

All proved undeveloped locations are scheduled to be drilled within the next five years. 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. 

Oil and Gas Production, Production Prices and Production Costs

Production Sales Data

The following table summarizes our net production sales volumes for the years indicated.

	Total Volume for the Years Ended December 31,			Per Day Volume for the Years Ended December 31,
	2018	2017	2016	2018	2017	2016
Oil	(Mbbls)			(Mbbls/d)
Delaware Basin	14,976	8,013	4,773	41.0	22.0	13.0
Williston Basin	14,793	10,951	7,596	40.6	30.0	20.8
Other	—	—	27	—	—	0.1
Total continuing operations	29,769	18,964	12,396	81.6	52.0	33.9
Discontinued operations(a)	1,029	3,398	2,931	2.8	9.3	8.0
Total continuing and discontinued operations	30,798	22,362	15,327	84.4	61.3	41.9
Natural Gas	(MMcf)			(MMcf/d)
Delaware Basin	50,275	28,554	15,818	137.7	78.2	43.2
Williston Basin	9,090	5,054	4,603	24.9	13.8	12.6
Other	—	1,703	6,694	—	4.7	18.3
Total continuing operations	59,365	35,311	27,115	162.6	96.7	74.1
Discontinued operations(a)	4,433	40,791	91,535	12.2	111.8	250.1
Total continuing and discontinued operations	63,798	76,102	118,650	174.8	208.5	324.2
NGLs	(Mbbls)			(Mbbls/d)
Delaware Basin	5,204	2,748	1,445	14.2	7.5	4.0
Williston Basin	1,529	896	782	4.2	2.5	2.1
Other	—	12	29	—	—	0.1
Total continuing operations	6,733	3,656	2,256	18.4	10.0	6.2
Discontinued operations(a)	433	1,381	2,495	1.2	3.8	6.8
Total continuing and discontinued operations	7,166	5,037	4,751	19.6	13.8	13.0
Combined Equivalent Volumes	(Mboe)			(Mboe/d)
Delaware Basin	28,559	15,520	8,854	78.2	42.5	24.2
Williston Basin	17,837	12,689	9,145	48.9	34.8	25.0
Other	—	296	1,173	—	0.8	3.2
Total continuing operations	46,396	28,505	19,172	127.1	78.1	52.4
Discontinued operations(a)	2,201	11,578	20,682	6.0	31.7	56.5
Total continuing and discontinued operations	48,597	40,083	39,854	133.1	109.8	108.9

 __________

(a) Reflects production from discontinued operations (primarily the San Juan Basin) through the date of disposition.

10

Realized average price per unit

The following table summarizes our sales prices for the years indicated.

	Continuing operations						Total Company(a)
	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2018		2017		2016
Oil(b):
Oil excluding all derivative settlements (per barrel)	$	60.14	$	46.36	$	36.36	$	59.98	$	46.02	$	36.20
Impact of net cash received (paid) related to settlement of derivatives (per barrel)	(8.56)		(0.33)		15.30		(8.27)		(0.27)		12.38
Oil net price including all derivative settlements (per barrel)	$	51.58	$	46.03	$	51.66	$	51.71	$	45.75	$	48.58
Natural gas(b):
Natural gas excluding all derivative settlements (per Mcf)	$	1.46	$	1.89	$	1.30	$	1.46	$	2.14	$	1.73
Impact of net cash received related to settlement of derivatives (per Mcf)	0.51		0.28		4.13		0.47		0.13		1.06
Natural gas net price including all derivative settlements (per Mcf)	$	1.97	$	2.17	$	5.43	$	1.93	$	2.27	$	2.79
NGL(b):
NGL excluding all derivative settlements (per barrel)	$	21.97	$	19.26	$	9.43	$	22.24	$	22.91	$	12.06
Impact of net cash paid related to settlement of derivatives (per barrel)	(1.98)		—		—		(1.85)		—		—
NGL net price including all derivative settlements (per barrel)	$	19.99	$	19.26	$	9.43	$	20.39	$	22.91	$	12.06
Combined commodity price per boe, including all derivative settlements	$	38.52	$	35.78	$	42.19	$	38.32	$	32.71	$	28.44

 __________

(a) Represents both continuing operations and discontinued operations through the dates of respective disposition.

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

Expenses per boe

The following table summarizes our costs for the years indicated.

	Continuing operations						Total Company(a)
	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2018		2017		2016
Production costs:
Lifting costs and workovers	$	5.25	$	5.42	$	5.67	$	5.16	$	4.92	$	3.99
Facilities operating expense	0.52		0.37		0.35		0.49		0.34		0.34
Accretion expense	0.06		0.07		0.10		0.06		0.15		0.20
Other operating and maintenance	0.02		0.04		0.04		0.02		0.03		0.02
Total lease and facility operating	$	5.85	$	5.90	$	6.16	$	5.73	$	5.44	$	4.55
Gathering, processing and transportation charges	2.30		0.83		0.61		2.43		2.46		3.13
Taxes other than income	3.39		2.78		2.24		3.33		2.55		1.56
Total production cost	$	11.54	$	9.51	$	9.01	$	11.49	$	10.45	$	9.24
General and administrative	$	3.92	$	5.80	$	10.54	$	3.78	$	4.37	$	5.57
Depreciation, depletion and amortization	$	16.75	$	19.03	$	23.01	$	16.15	$	16.79	$	15.84

 __________

(a) Represents both continuing operations and discontinued operations through the dates of respective disposition.

11

Productive Oil and Gas Wells

The table below summarizes 2018 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.

	Oil Wells (Gross)	Oil Wells (Net)	Gas Wells (Gross)	Gas Wells (Net)
Delaware Basin	1,225	587	240	124
Williston Basin	410	268	—	—
Total	1,635	855	240	124

Developed and Undeveloped Acreage

The following table summarizes our leased acreage as of December 31, 2018.

	Developed		Undeveloped		Total
	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres
Delaware Basin	134,846	82,038	84,867	47,388	219,713	129,426
Williston Basin	72,875	62,161	61,654	22,926	134,529	85,087
Other(a)	5,159	1,598	32,944	11,523	38,103	13,121
Total	212,880	145,797	179,465	81,837	392,345	227,634

 __________

(a) Primarily acreage in exploratory areas we no longer plan to develop.

At December 31, 2018, we also owned mineral interests in 22,585 gross and 1,496 net acres. These interests do not expire.

Drilling and Exploratory Activities

We focus on lower-risk development drilling. Our development drilling success rate was 100 percent in 2018, 2017 and 2016. Our combined development and exploration success rate was 100 percent, in 2018, 2017 and 2016, respectively.

The following table summarizes the number of wells drilled for the periods indicated and excludes discontinued operations.

	2018		2017		2016
	Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells
Development wells:
Delaware Basin	158	112	94	76	40	31
Williston Basin	77	68	44	34	25	21
Other(a)	—	—	—	—	41	—	(a)
Development well total	235	180	138	110	106	52
Exploration well total	—	—	—	—	—	—
Total Drilled	235	180	138	110	106	52

 __________

(a) Includes Appalachia Basin, Green River Basin and other miscellaneous properties through dates of respective dispositions.

Total gross operated wells drilled were 193, 118 and 51 in 2018, 2017 and 2016, respectively.

Present Activities

At December 31, 2018, we had 19 gross (16 net) wells in the process of being drilled.

12

Scheduled Lease Expirations

The table below sets forth, as of December 31, 2018, 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.

	2019	2020	2021	2022+	Total
Delaware Basin	10,577	5,285	28	20,992	36,882
Williston Basin	—	—	640	—	640
Other(a)	31	—	—	—	31
Total (Gross Acres)	10,608	5,285	668	20,992	37,553

	2019	2020	2021	2022+	Total
Delaware Basin	3,012	3,468	6	20,992	27,478
Williston Basin	—	—	640	—	640
Other(a)	31	—	—	—	31
Total (Net Acres)	3,043	3,468	646	20,992	28,149

__________

(a) Primarily acreage in exploratory areas we no longer plan to develop.

Seasonality

Generally, the demand for oil and natural gas decreases during the summer months and increases during the winter months. In some areas, natural gas increases 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 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 crude oil, natural gas 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.”

Delivery Commitments

We have certain obligations which range from one to eight years for the physical delivery of oil in both the Delaware and Williston Basins. The minimum aggregate volume for these sales commitments ranges from 45 to 56 Mbbls per day for years 2019 through 2021, 25 Mbbls per day for 2022 and approximately 5 Mbbls per day for years 2023 through 2026. We believe that our future production, which is dependent on sufficient infrastructure, will be adequate to meet these commitments. 

Customers

Oil, natural gas 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 2018, we had three customers that individually accounted for 10 percent or more of our consolidated total revenues adjusted for net gain (loss) on derivatives. See further detail in Note 16 of Notes to Consolidated Financial Statements. We believe that the loss of one or more of our current oil, natural gas 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.

13

REGLATORY 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 oil, natural gas 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.

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 oil, natural gas 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.

14

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.

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.

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. 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.

Operations 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

15

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 operating 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, 2014 – 2016, and 2016 – 2019 National Enforcement Initiatives include Energy Extraction and “Ensuring 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 has settled a number of high-impact cases under this initiative resulting in significant air emissions reductions, and will continue to identify the best ways to address pollution through greater use of advanced pollution monitoring and reporting techniques. 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. 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 of 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

16

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 January 11, 2017, the EPA issued the final 2017 construction general permit (“CGP”) for storm water discharges from construction activities involving more than one acre, which will provide coverage for a five-year period and will take effect on February 16, 2017. The 2017 CGP implements Effluent Limitations Guidelines and New Source Performance Standards for the Construction and Development Industry. The rule includes stringent restrictions on erosion and sediment control, pollution prevention and stabilization.

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, and in June 2016, EPA again expanded the regulations (new Subpart OOOOa). On May 26, 2017, EPA issued a stay on certain Subpart OOOOa requirements (primarily those going into effect in January 2018), and on June 14, 2017, EPA proposed a two-year stay of the requirements and reconsideration of certain requirements and implementation dates. On July 3, 2017, a federal court determined that the May 2017 stay was unlawful. On October 15, 2018, EPA proposed revision to the Subpart OOOOa regulations and has not yet issued the final revised regulations. 

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

17

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 increase productivity of our oil and gas wells in each of the basins in which we operate. In particular, wells that we drill and complete in our core Delaware and Williston assets require hydraulic fracturing. 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 forty-five to fifty-five percent 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: (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.

18

•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.

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

•There are currently no regulatory requirements to conduct baseline water monitoring in the Williston Basin or the Delaware Basin.

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 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, 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 and chemical 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

19

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, 2018, we have loaded data on more than 2,250 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.

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.

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 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 August 2015, the EPA published its Final 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 specifically investigate centralized water treatment facilities that accept oil and gas extraction wastewaters. The EPA has also collected information as part of a multi-year study into the effects of hydraulic fracturing on drinking water. The EPA published its Final “Assessment of Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources” on December 13, 2016. The Final Assessment concluded that “EPA found scientific evidence that hydraulic fracturing activities can impact drinking water resources under some circumstances.” The final report could result in additional regulations, which could lead to operational burdens similar to those described above. In connection with the EPA study, we 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 final report on hydraulic fracturing in November 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. On November 18, 2016, the Department of the Interior, Bureau of Land Management (“BLM”) issued its final rule related to the reduction of waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on federal and Indian lands, with provisions to take effect on January 17, 2017 and in January 2018. The rule, which was to be phased in over time, requires oil and gas producers to use currently available technologies and processes to cut flaring in half at oil wells on public and tribal lands, periodically inspect their operations for leaks, replace outdated equipment, limit venting from storage tanks and to use best practices to limit gas losses when removing liquids from wells. On November 18, 2018, BLM issued a revised rule that took effect on November 27, 2018, eliminating many of the requirements included in the 2016 rule. The 2018 rule has been challenged in court and litigation is ongoing.

20

Several states, including North Dakota and New Mexico, have adopted or are considering adopting, regulations that could restrict or impose additional requirements related to hydraulic fracturing. New Mexico and Texas require 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 New Mexico and Texas.

In addition, New Mexico has 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. 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 health 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.

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, although that plan was rescinded by the White House in March 2017. In August 2015, EPA proposed its new NSPS OOOOa requirements, which add additional methane reduction requirements applicable to the oil and gas sector for both new and modified sources, although the current scope of the requirements are being litigated. 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 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 oil and 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.

21

EMPLOYEES

At December 31, 2018, we had approximately 600 full-time employees.

FINANCIAL INFORMATION ABOUT SEGMENTS

We operate in the exploration and production segment of the oil and gas industry and our operations are conducted in the United States. We report our financial results as a single industry segment.

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.  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

•Lead Director 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.

22

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 oil and natural gas reserves;

•reserve potential;

•development drilling potential;

•cash flow from operations or results of operations;

•acquisitions or divestitures;

•seasonality of our business; and

•crude oil, natural gas and NGL 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.”

23

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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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:

24

•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 oil and natural gas;

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

Accounting rules require that we review periodically the carrying value of our oil and natural gas 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 oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. In the fourth quarter of 2018, we performed impairment assessments of our proved and unproved properties. We determined that no impairment charges were required as a result of these assessments. These reviews included approximately $5.4 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 oil and natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices may lead to decreased earnings, losses or impairment of oil and natural gas 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.

25

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

Approximately 45 percent of our total estimated proved reserves at December 31, 2018 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas properties will be affected by factors such as:

•actual prices we receive for oil and natural gas;

•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 oil and natural gas 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 oil and natural gas 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, oil and natural gas 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 oil, natural gas 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 oil, natural gas 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 oil, natural gas 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 oil, natural gas and NGLs;

•turmoil in the Middle East and other producing regions;

26

•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 oil and natural gas;

•domestic and foreign governmental regulations and taxes;

•volatility in the oil and natural gas 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 oil, natural gas and NGL transportation systems and facilities.

The marketability of our oil, natural gas 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 Delaware Basin and Williston 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, 2018, we were not the operator of approximately 5 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 oil, natural gas 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.

27

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 oil, natural gas 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 oil, natural gas 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.

Our hedging activities limit participation in commodity price increases and involve other risks.

We enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. Moreover, as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation, hedging transactions and many of our contract counterparties have come under increasing governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedging arrangements, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.

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 oil and natural gas and securing equipment and trained personnel in the oil and natural gas 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 oil and natural gas 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.

28

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 oil and natural gas 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 oil, natural gas (including sour gas), NGLs, brine or industrial chemicals;

•operator error;

•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. See recently adopted accounting standards in Note 1 of Notes to Consolidated Financial Statements.

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.

29

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 significant indebtedness reduces our financial flexibility and could impede our ability to operate.

We have historically operated with, and anticipate continuing to operate with, a significant amount of debt. Our substantial amount of debt could have important consequences for investors in our common stock, including the following:

•make it more difficult for us to satisfy our obligations with respect to our revolving credit facility;

•impair our ability to obtain additional financing, if necessary, for working capital, letters of credit or other forms of guarantees, capital expenditures, acquisitions or other purposes or make such financing unavailable on favorable terms;

•require us to dedicate a substantial portion of our cash flow from operations to make payments on our debt, thereby reducing funds available for operations, capital expenditures, future business opportunities and other purposes;

•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•reduce our ability to make acquisitions or expand our business;

•limit our ability to borrow additional funds;

•limit our ability to sell assets to raise funds if needed for working capital, capital expenditures, acquisitions or other purposes;

•make it difficult for us to pay dividends on shares of our common stock;

•increase our vulnerability to adverse economic and industry conditions, including increases in interest rates; and

•place us at a competitive disadvantage compared to competitors who might have relatively less debt.

Additionally, we may be able to incur substantial additional indebtedness in the future. Although our revolving credit facility contains restrictions on the incurrence of additional indebtedness by our subsidiaries, such restrictions are subject to a number of qualifications and exceptions, and indebtedness incurred in compliance with such restrictions could be substantial. To the extent that new indebtedness is added to our current debt levels, the negative consequences listed above may be exacerbated.

The market price of our common stock may be volatile or may decline and it may be difficult for you to resell shares of our common stock at prices you find attractive.

The market price of our common stock has historically experienced and may continue to experience volatility. For example, during the twelve months ended December 31, 2018, the high sales price per share of our common stock on the NYSE was $20.80 and the low sales price per share was $9.89. The sales price per share of our common stock has traded as low as $8.39 in the past two years. The market price of our common stock could be subject to wide fluctuations in the future in response to the following events or factors that may vary over time and some of which are beyond our control, including but not limited to:

•changes in oil and natural gas prices, including in different geographic locations;

•demand for oil and natural gas;

•the success of our drilling program;

•changes in our drilling schedule;

•adjustments to our reserve estimates and differences between actual and estimated production, revenue and expenditures;

•competition from other oil and gas companies;

•costs and liabilities relating to governmental laws and regulations and environmental risks;

•general market, political and economic conditions;

•our failure to meet financial analysts’ performance or financing expectations;

•changes in recommendations by financial analysts; and

•changes in market valuations of other companies in our industry.

In particular, a significant or extended decline in oil and natural gas prices would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of oil and natural gas that we can produce economically.

30

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 are 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 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.

Any significant reduction in our borrowing base under our revolving credit facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

As of December 31, 2018, our revolving credit facility is subject to a borrowing base of $2.0 billion which is currently limited by total commitments of $1.5 billion. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2018, we had $330 million of outstanding borrowings and $52 million of letters of credit issued under our revolving credit facility resulting in unused borrowing capacity of $1.1 billion. Any significant reduction in our borrowing base as a result of borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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.

31

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, although that plan was rescinded by the White House in March 2017. In August 2015, EPA issued a suite of proposed regulations applicable to the oil and gas sector to decrease 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 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 environmental 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.

32

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 oil, natural gas 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. In addition, Non-Governmental Organizations who oppose the development of fossil fuels for a number of reasons, including environmental concerns, have recently increased their activities in ways outside the normal legal process by staging protests and demonstrations in a way that may disrupt our ability to conduct our operations and market our production. To date, most of this activity has been related to issues associated with the development of infrastructure but the possibility exists that these activities could be directed to other aspects of our business.

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 now through 2019, which include Energy Extraction and “Ensuring Energy Extraction Activities Comply with Environmental Laws.” The EPA has settled a number of high-impact cases under this initiative resulting in significant air emissions reductions, and will continue to identify the best ways to address pollution through greater use of advanced pollution monitoring and reporting techniques. 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 issued a suite of proposed regulations to cut methane emissions from the oil and gas sector in August 2015 to petroleum-sector methane emissions by 40 to 45 percent by 2025 from 2012 levels. EPA issued its proposed rules for new and modified wells in 2015 and finalized them in 2016, revising them again in 2018. The Interior Department submitted proposed rules to the Office of Management and Budget in the fall of 2015 aimed at reducing methane flaring at wells on federal land, and the rule went into effect on January 17, 2017, although it was revised in 2018 with the revisions currently under legal challenge; the Department of Energy is to develop new ways to detect and repair methane leaks; and the Department of Transportation developed new pipeline safety standards issued January 13, 2017 that also reduce leaks. In addition, federal and state agencies could impose additional safety requirements, any of which could affect our profitability.

33

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 oil and natural gas 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 finalized a multi-year study of the potential environmental impacts of hydraulic fracturing on drinking water resources. The EPA published its Final “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources” on December 13, 2016. In August 2015, the EPA published its Final 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 specifically investigate centralized water treatment facilities that accept oil and gas extraction wastewaters. In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a final report on hydraulic fracturing in November 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., Texas, 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 issued its final rules considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. After various legal challenges and agency action associated with that rule, a revised rule was issued in November 2018 and is currently under legal challenge. 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.

Our ability to produce oil and natural 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 in our Delaware Basin and Williston 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 August 2015, the EPA published its Final 2014 Effluent Guidelines Program Plans under the CWA confirming its intention to regulate wastewater discharges from onshore unconventional oil and gas extraction and to specifically investigate centralized water treatment facilities that accept oil and gas extraction wastewaters. 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

34

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 oil and gas 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 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 oil or natural gas development and production operations on such lands.

Our liabilities could be adversely affected in the event one or more of our transaction counterparties ceases to perform.

We have taken actions in recent years to enhance and streamline our asset portfolio through the divestitures of noncore assets and the monetization of certain nonstrategic assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows and similar arrangements. One or more of the counterparties in these transactions could, either as a result of a decline in oil or natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on its ability to perform its obligations under these agreements and its solvency and ability to continue as a going concern. In the event that any such counterparty were to become unable financially to perform its liabilities or obligations assumed and as a result become the subject of a case or proceeding under relevant insolvency laws or similar laws (which we collectively refer to as Insolvency Laws) the counterparty may not perform its obligations under the agreements related to these transactions. In that case, our remedy would be a claim in a bankruptcy proceeding or a direct action for damages for the breach of the contractual arrangement. Resolution of our damage claim in such a proceeding may be delayed or unsuccessful, and we may be forced to use available cash to cover the costs of the obligations assumed by the counterparties under such agreements should they arise.

Despite the provisions in our agreements requiring purchasers of our leasehold interests to assume certain liabilities and obligations related to such interests, if a purchaser of such interests becomes the subject of a case or proceeding under relevant Insolvency Laws and/or becomes unable financially to perform such liabilities or obligations, applicable local law and/or relevant governmental authorities could require us to perform, and hold us responsible for, such liabilities and obligations, such as the decommissioning of such transferred assets. In such event, we may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

35

If a court or a governmental authority were to make any of the foregoing determinations or take any of the foregoing actions, or any similar determination or action, or in circumstances where we determined that applicable law required us to perform the obligations of a counterparty, the result of such actions or circumstances could adversely impact our cash flows, operations, or financial condition.

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.

In recent years, leaders in government have proposed changes to certain federal income tax provisions currently available to oil and gas exploration and production companies. Domestic energy-related changes generally discussed include, but are not limited to, (i) elimination of the ability to fully deduct intangible drilling and development costs in the year incurred;(ii) extension of the amortization period for certain geological and geophysical expenditures; and (iii) technical corrections or other subsequent revisions to recently enacted Tax Reform legislation. 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.

36

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 oil, natural gas, 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.

Cyber attacks targeting our systems and infrastructure may adversely impact our operations.

Our industry has become increasingly dependent on digital technologies to conduct daily operations. Concurrently, the industry has become the subject of increased levels of cyber-attack activity. Cyber attacks often attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption and may be carried out by third parties or insiders. The techniques utilized range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be carried out in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. Although we have not suffered material losses related to cyber attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.

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.

We continue to be subject to a tax-sharing agreement with The Williams Companies, Inc. (“Williams”).

Prior to our spin-off from Williams on December 31, 2011, Williams received an opinion of its outside tax advisor as well as a private letter ruling from the IRS holding 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 with Williams that we executed as part of the spin-off, 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 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.

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. Under the tax sharing agreement with Williams, for each period in which we were consolidated with Williams for purposes of any tax return, a pro forma tax return was prepared for us as if we filed our own consolidated return. The only open federal tax period for which we are still subject to the tax sharing agreement with Williams is 2011. For any adjustments to the 2011 pro forma tax return we will reimburse Williams for any additional taxes shown on the pro forma tax return, and Williams will reimburse us for reductions in the taxes shown on the pro forma tax

37

return. We also have deferred tax assets that Williams was required to allocate to us by the Internal Revenue Code that could decrease or increase due to adjustments that change those allocations, whether or not related to our business. Williams effectively controls all tax decisions in connection with their 2011 consolidated income tax return. Thus, Williams will be able to choose whether 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.

We rely on key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business are assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer or our President and Chief Operating Officer, could disrupt our operations. We do not maintain, nor do we plan to obtain, “key person” life insurance policies or any other insurance policies against the loss of any of these individuals.  

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:

•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; and

•supermajority voting requirements for stockholders to amend our organizational documents.

38

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.

Our ability to utilize our net operating loss (“NOL”) carryovers for income tax purposes to reduce future

taxable income as well as our ability to utilize our minimum tax credit (“MTC”) carryovers will be limited if we undergo an ownership change.

Beginning with our 2015 tax year and continuing with our 2016 and 2017 tax years we generated an NOL that is being carried forward to future years. In addition, we have MTC carryovers available for future reductions in federal income tax or refunds. In the event that we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”)), our NOL and MTC carryovers generated prior to the ownership change would be subject to annual limitations, which could defer utilization or in the case of our NOL carryovers, eliminate our ability to utilize these tax losses against future taxable income. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns 5% or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50% over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. See the Critical Accounting Estimates section of Item 7 for further discussion of our Valuation of Deferred Tax Assets and Liabilities.

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 11 of our Notes to Consolidated Financial Statements for the information that is called for by this item.

Item 4. Mine Safety Disclosures

Not applicable.

39

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,
	2018				2017
	High		Low		High		Low
Common Stock:
Fourth quarter	$	20.80	$	9.89	$	14.55	$	9.91
Third quarter	$	20.37	$	16.94	$	11.67	$	8.87
Second quarter	$	19.23	$	12.75	$	14.08	$	8.39
First quarter	$	16.09	$	12.34	$	15.44	$	11.57

At February 20, 2019, there were 6,517 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.

40

Stockholder Return Performance Presentation

The following stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that WPX specifically requests that such information be treated as “soliciting material” or specifically incorporates such information by reference into such a filing.

The performance graph below compares the cumulative five-year total return to stockholders on WPX’s common stock as compared to the cumulative five-year total returns on the Standard and Poor’s Midcap 400 Index (“MID”), and the Standard and Poor’s Oil and Gas Exploration and Production Select Industry Index (“S&P O&G”). The comparison assumed a $100 investment was made in WPX’s stock, the MID Index and the S&P O&G Index at the beginning of the period.

	As of December 31,
Total Return Analysis data:	2013		2014		2015		2016		2017		2018
WPX	$	100.00	$	57.07	$	28.16	$	71.49	$	69.04	$	55.69
MID	$	100.00	$	108.19	$	104.17	$	123.69	$	141.57	$	123.87
S&P O&G	$	100.00	$	69.91	$	44.25	$	60.66	$	54.55	$	38.88

41

Item 6. Selected Financial Data

The following financial data at December 31, 2018 and 2017, and for each of the three years ended December 31, 2018, 2017 and 2016 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.

	Years Ended December 31,
	2018		2017		2016		2015		2014
Statement of operations data:	(Millions, except per share amounts)
Product revenues	$	2,025	$	1,016	$	507	$	403	$	708
Net gain (loss) on derivatives	$	81	$	3	$	(207)	$	418	$	434
Commodity management revenue	$	204	$	25	$	177	$	286	$	1,110
Total revenues	$	2,310	$	1,045	$	478	$	1,113	$	2,260
Income (loss) from continuing operations(a)	$	242	$	24	$	(672)	$	40	$	219
Income (loss) from discontinued operations(b)	(91)		(40)		71		(1,766)		(48)
Net income (loss)	$	151	$	(16)	$	(601)	$	(1,726)	$	171
Less: Net income attributable to noncontrolling interests	—		—		—		1		7
Net income (loss) attributable to WPX Energy, Inc.	$	151	$	(16)	$	(601)	$	(1,727)	$	164
Less: Dividends on preferred stock	8		15		18		9		—
Less: Loss on induced conversion of preferred stock	—		—		22		—		—
Net income (loss) available to WPX Energy, Inc. common stockholders	$	143	$	(31)	$	(641)	$	(1,736)	$	164
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	234	$	9	$	(712)	$	31	$	219
Income (loss) from discontinued operations	$	(91)	$	(40)	$	71	$	(1,767)	$	(55)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.57	$	0.02	$	(2.28)	$	0.13	$	1.08
Income (loss) from discontinued operations	$	(0.22)	$	(0.10)	$	0.23	$	(7.55)	$	(0.27)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.57	$	0.02	$	(2.28)	$	0.13	$	1.06
Income (loss) from discontinued operations	$	(0.22)	$	(0.10)	$	0.23	$	(7.50)	$	(0.26)

	As of December 31,
	2018		2017		2016		2015		2014
Balance sheet data:	(Millions)
Total assets	$	8,203	$	8,207	$	7,264	$	8,393	$	8,896
Long-term debt	$	2,485	$	2,575	$	2,575	$	3,189	$	2,260
Total stockholders’ equity	$	4,301	$	4,127	$	3,466	$	3,535	$	4,319
Total equity, including noncontrolling interests	$	4,301	$	4,127	$	3,466	$	3,535	$	4,428

 __________

42

(a) Income (loss) from continuing operations includes significant pre-tax items comprised of the following:

	Years Ended December 31,
	2018		2017		2016		2015		2014
	(Millions)
Net (gain) loss on sales of assets, divestment of transportation contracts or impairment of producing properties	$	(3)	$	(161)	$	239	$	(349)	$	15
Impairment of unproved leasehold property	$	—	$	—	$	—	$	—	$	41

See Note 5 of Notes to Consolidated Financial Statements for further discussion of the impairments and asset sales in 2018, 2017 and 2016. In 2015, we completed sales of a package of marketing contracts and released certain firm transportation capacity resulting in a $209 million gain. We also sold a North Dakota gathering system resulting in a $70 million gain and sold a portion of Appalachian properties resulting in a gain of $69 million.

(b) Income (loss) from discontinued operations includes the results of holdings in the San Juan Basin, holdings in the Piceance Basin, holdings in the Powder River Basin, and Apco Oil and Gas International Inc. Significant components included in income (loss) from discontinued operations are comprised of the following:

	Years Ended December 31,
	2018		2017		2016		2015		2014
	(Millions)
Net pre-tax (gain) loss on divestments	$	147	$	(10)	$	(268)	$	(26)	$	—
San Juan pre-tax impairment	$	—	$	60	$	—	$	—	$	—
Piceance pre-tax impairments, including impairment of producing properties, costs of acquired unproved reserves and exploratory area well costs	$	—	$	—	$	—	$	2,334	$	72
Powder River pre-tax impairments	$	—	$	—	$	—	$	16	$	45
Loss on sale of working interests in the Piceance Basin	$	—	$	—	$	—	$	—	$	196

See Note 3 of Notes to Consolidated Financial Statements for further discussion of discontinued operations in 2018, 2017 and 2016.

43

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

General and Basis of Presentation

We are an independent oil and natural gas exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting, developing and growing our oil positions in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Associated with our commodity production are sales and marketing activities, which include oil and natural gas purchased from working interest owners in operated wells and other third-party producers and, to a lesser extent, the management of various natural gas related contracts such as transportation and storage. The revenues and expenses related to these sales and marketing activities are reported on a gross basis as part of commodity management revenues and costs and expenses.

In March 2017, we completed the acquisition of certain assets in the Delaware Basin (the “Panther Acquisition”). See Note 2 of Notes to Consolidated Financial Statements for a further discussion of this acquisition.

In late 2017 and early 2018, we divested our natural gas and oil properties in the San Juan Basin through two separate transactions. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. We also had operations in the Piceance Basin in Colorado until April 8, 2016. For all periods presented, the results of the San Juan and Piceance Basins are reported as discontinued operations. See Note 3 of Notes to Consolidated Financial Statements for further discussion of our discontinued operations. Unless indicated otherwise, the following discussion relates to continuing operations.

The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes in Part II, Item 8, Financial Statements and Supplemental Data of 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 10-K, particularly in “Risk Factors” and “Forward-Looking Statements.”

44

Overview

Composition of Production (based on MBoe) and Product Revenue

Years Ended December 31,

Our 2018 oil production as a percent of total production declined compared to 2017 due to Delaware production growth which has a higher natural gas component than our Williston production. The following table presents our production volumes and financial highlights for 2018, 2017 and 2016:

	Years Ended December 31,
	2018			2017			2016
Production Sales Volume Data(a):			Per day			Per day			Per day
Oil (Mbbls)	29,769		81.6	18,964		52.0	12,396		33.9
Natural gas (MMcf)	59,365		162.6	35,311		96.7	27,115		74.1
NGLs (Mbbls)	6,733		18.4	3,656		10.0	2,256		6.2
Combined equivalent volumes (Mboe)	46,396		127.1	28,505		78.1	19,172		52.4
Financial Data (millions):
Total product revenues	$	2,025		$	1,016		$	507
Total revenues	$	2,310		$	1,045		$	478
Operating income (loss)	$	554		$	98		$	(826)
Capital expenditure activity(b)	$	(1,510)		$	(1,232)		$	(584)

 __________

(a)	Excludes production from our discontinued operations.
(b)	Includes capital expenditures related to discontinued operations of $27 million, $176 million and $113 million for the years ended December 31, 2018, 2017 and 2016, respectively, and excludes capital expenditures related to acquisitions.

Our 2018 operating results were $456 million favorable compared to 2017. The primary items impacting 2018 results compared to 2017 results include:

•$1,009 million increase in product revenues, primarily oil sales, of which $501 million related to higher oil volumes and $410 million related to higher oil prices; and

45

•$78 million favorable change in net gain on derivatives.

Offset by:

•$500 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and

•The absence in 2018 of $161 million net gain on sales of assets, including leasehold exchanges, which were included in 2017 (see Note 5 of Notes to Consolidated Financial Statements).

Our 2017 operating results were $924 million favorable compared to 2016. The primary items impacting 2017 results compared to 2016 results include:

•$509 million increase in product revenues, primarily oil sales, of which $239 million related to higher oil volumes and $189 million related to higher oil prices;

•$210 million favorable change in net gain (loss) on derivatives;

•$161 million net gain on sales of assets, including leasehold exchanges, for 2017 compared to $239 million net loss primarily related to divestment of transportation contracts for 2016 (see Note 5 of Notes to Consolidated Financial Statements); and

•$36 million decrease in general and administrative expenses.

Offset by:

•$199 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and

•$61 million higher exploration costs (see Note 5 of Notes to Consolidated Financial Statements).

Outlook

After our multi-year transformation of WPX, our oil-prone positions in the Delaware (Permian) and Williston Basins now form the foundation of WPX. Our acreage positions in each of these basins contains some of the top geology in the plays and in North America. We have also assembled an attractive infrastructure portfolio in the Permian which will help flow our production out of the basin and will create additional value either through monetization of our midstream investments or lower operating costs. In addition to our joint venture with Howard Energy Partners LLC, we have made additional investments during 2018 in our equity positions in Whitewater and Oryx pipeline systems. We believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. For 2019, we currently expect our operating cash flows to approximate our base capital expenditures plan. However, the challenging and dynamic environment of oil and gas industry, along with future market conditions, may alter these expectations or plans. We would make appropriate adjustments to our plans if we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices.

Our expected base capital budget for full year 2019 is $1.1 billion to $1.275 billion excluding land purchases. This is a reduction from our estimates previously communicated as we respond to the decline in oil prices toward the end of 2018. Additionally, we estimate between $70 million and $90 million for equity method investments. Planned capital for drilling and completions, including non-operated wells, is $1.050 billion to $1.175 billion for the full year 2019. Additionally and subsequent to December 31, 2018, we have signed or closed separate sales agreements for aggregate proceeds in excess of $200 million for our 20 percent equity interest in Whitewater and roughly 5,600 net acres in the Delaware Basin, while closing on a purchase of 14,000 surface acres for $100 million. WPX may also monetize its equity position in the Oryx pipeline systems.

Our December 31, 2018 liquidity totaled approximately $1.1 billion, reflecting amounts available under the Credit Facility Agreement and cash on hand. Our next Senior Note maturity of $529 million is not due until 2022. Our Credit Facility Agreement is subject to a $2.0 billion borrowing base with aggregate elected commitments of $1.5 billion and a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 (see Note 9 of Notes to Consolidated Financial Statements for further discussion). We believe our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a downturn. 

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

46

•value driven development of our positions in the Delaware and Williston Basins;

•continuing to pursue cost improvements and efficiency gains;

•employing new technology and operating methods;

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

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

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

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

•lower than anticipated energy commodity prices;

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

•higher capital costs of developing our properties, including the impact of inflation;

•lower than expected levels of cash flow from operations;

•counterparty credit and performance risk;

•general economic, financial markets or industry downturn;

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

•changes in the political and regulatory environments; and

•decreased drilling success.

We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel over the past five years. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. If forecasted oil and natural gas prices were to decline, we would need to review the producing properties net book value for possible impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant. The net book value of our proved properties is $5.4 billion. In addition, the net book value associated with unproved leasehold is approximately $1.8 billion and is primarily associated with our Delaware Basin properties. See our discussion of impairment of long-lived assets in our Critical Accounting Estimates discussion later in this section.

Results of Operations

2018 vs. 2017 

Revenue Analysis

	Years ended December 31,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2018		2017
	(Millions)
Revenues:
Oil sales	$	1,790	$	879	$	911	104	%
Natural gas sales	87		67		20		30	%
Natural gas liquid sales	148		70		78		111	%
Total product revenues	2,025		1,016		1,009		99	%
Net gain on derivatives	81		3		78		NM
Commodity management	204		25		179		NM
Other	—		1		(1)		(100)	%
Total revenues	$	2,310	$	1,045	$	1,265	121	%

__________

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

47

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

•$911 million increase in oil sales reflects $501 million related to higher production sales volumes and $410 million related to higher sales prices for 2018 compared to 2017. The Delaware and Williston Basin volumes were 41.0 and 40.6 Mbbls per day, respectively, for 2018 compared to 22.0 and 30.0 Mbbls per day, respectively, for 2017. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for 2018 and 2017.

	Years ended December 31,
	2018		2017
Oil sales (per barrel)	$	60.14	$	46.36
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	(8.56)		(0.33)
Oil net price including all derivative settlements (per barrel)	$	51.58	$	46.03
Oil production sales volumes (Mbbls)	29,769		18,964
Per day oil production sales volumes (Mbbls/d)	81.6		52.0

__________

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

•$20 million increase in natural gas sales reflects $45 million related to higher production sales volumes offset by $25 million decrease related to lower gas sales prices for 2018 compared to 2017. The increase in our production sales volumes primarily relates to our Delaware Basin which had production volumes of 137.7 MMcf per day for 2018 compared to 78.2 MMcf per day for 2017. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2018 and 2017.

	Years ended December 31,
	2018		2017
Natural gas sales (per Mcf)	$	1.46	$	1.89
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.51		0.28
Natural gas net price including all derivative settlements (per Mcf)	$	1.97	$	2.17
Natural gas production sales volumes (MMcf)	59,365		35,311
Per day natural gas production sales volumes (MMcf/d)	162.6		96.7

__________ 

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

•$78 million increase in natural gas liquids sales primarily reflects $59 million related to higher production sales volumes and $18 million related to higher NGL sales prices for 2018 compared to 2017. The Delaware Basin volumes were 14.2 MBbls per day compared to 7.5 MBbls per day for 2018 and 2017, respectively. The Williston Basin volumes were 4.2 MBbls per day compared to 2.5 MBbls per day for 2018 and 2017, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for 2018 and 2017.

	Years ended December 31,
	2018		2017
NGL sales (per barrel)	$	21.97	$	19.26
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	(1.98)		—
NGL net price including all derivative settlements (per barrel)	$	19.99	$	19.26
NGL production sales volumes (Mbbls)	6,733		3,656
Per day NGL production sales volumes (Mbbls/d)	18.4		10.0

__________ 

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

•$78 million favorable change in net gain on derivatives primarily reflects changes in crude oil derivatives which were a result of decreases in 2018 of forward commodity prices relative to our hedge positions. Settlements to be paid on derivatives totaled $237 million for 2018 and settlements to be received totaled $4 million for 2017.

48

•$179 million increase in commodity management revenues primarily due to higher crude and natural gas sales volumes. A similar increase is reflected in the $155 million increase in related commodity management costs and expenses, discussed below. The increase in crude sales volumes is due to increased crude purchases to fulfill certain sales commitments. The increase in natural gas volumes resulted from the utilization of excess pipeline capacity we currently have in the Delaware Basin.

Cost and operating expense and operating income analysis:

	Years ended December 31,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change		Per Boe Expense
	2018		2017						2018	2017
	(Millions)
Costs and expenses:
Depreciation, depletion and amortization	$	777	$	542	$	(235)	(43)	%	$16.75	$19.03
Lease and facility operating	272		168		(104)		(62)	%	$5.85	$5.90
Gathering, processing and transportation	107		24		(83)		NM		$2.30	$0.83
Taxes other than income	157		79		(78)		(99)	%	$3.39	$2.78
Exploration	75		87		12		14	%
General and administrative:
General and administrative expenses	150		138		(12)		(9)	%	$3.22	$4.79
Equity based compensation	32		28		(4)		(14)	%	$0.70	$1.01
Total general and administrative	182		166		(16)		(10)	%	$3.92	$5.80
Commodity management	182		27		(155)		NM
Net gain—sales of assets and divestment of transportation contracts (Note 5)	(3)		(161)		(158)		(98)	%
Other—net	7		15		8		53	%
Total costs and expenses	$	1,756	$	947	$	(809)	(85)	%
Operating income	$	554	$	98	$	456	NM

__________

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

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

•$235 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $2.28 per Boe decrease in rate which was impacted by higher estimated reserves as compared to 2017 due to a higher 12-month average price, the addition of new wells with lower relative cost per Boe and an increase in Delaware production, which has a lower rate per Boe, relative to the overall total.

•$104 million increase in lease and facility operating expenses primarily related to the 63 percent increase in production volumes for 2018 compared to 2017.

•$83 million increase in gathering, processing and transportation is due in part to the adoption of ASU 2014-09, Revenue from Contracts with Customers, for which the net expense on certain transportation related arrangements that were recorded as a reduction in oil revenue in 2017 are included in gathering, processing and transportation in 2018 as well as the impact of the growth in production volumes in 2018.

•$78 million increase in taxes other than income related to increased product revenues, previously discussed.

•$12 million decrease in exploration expenses is primarily due to costs, recorded during first-quarter 2017,  associated with certain expired leases in the Delaware Basin in excess of the accumulated amortization balance. See Note 5 of Notes to Consolidated Financial Statements.

•$16 million increase in general and administrative expenses for 2018 compared to 2017. Our general and administrative expenses per BOE decreased to an average $3.92 for 2018 compared to $5.80 for 2017.

•$155 million increase in commodity management expenses is primarily due to higher crude and natural gas purchase volumes as discussed above.

•The $161 net gain on sales of assets in 2017 primarily related to $103 million of gains on exchanges of leasehold acreage in the Delaware Basin and $48 million from recognition of deferred gains related to completion of commitments from a prior year disposition. See Note 5 of Notes to Consolidated Financial Statements for further discussion of these items.

49

Results below operating income

	Years ended December 31,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2018		2017
	(Millions)
Operating income	$	554	$	98	$	456	NM
Interest expense	(163)		(188)		25		13	%
Loss on extinguishment of debt	(71)		(17)		(54)		NM
Investment income and other	(4)		3		(7)		NM
Income (loss) from continuing operations before income taxes	316		(104)		420		NM
Provision (benefit) for income taxes	74		(128)		(202)		NM
Income from continuing operations	242		24		218		NM
Loss from discontinued operations	(91)		(40)		(51)		(128)	%
Net income (loss)	$	151	$	(16)	$	167	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 decrease in interest expense primarily relates to lower level of debt outstanding in 2018 compared to 2017.

In the second-quarter of 2018, we used proceeds from the San Juan Gallup disposition and proceeds from the issuance of$500 million Senior Notes due in 2026 to retire $921 million aggregate principal amount of our Senior Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $71 million in second-quarter 2018. See Note 9 of Notes to Consolidated Financial Statements for additional information regarding these transactions. In the third quarter of 2017, we issued $150 million of debt onto our 2024 Notes and extinguished $150 million of the 2020 Notes. As a result, we recorded a loss on extinguishment of debt of $17 million in 2017.

Income taxes for 2018 changed unfavorably compared to 2017 primarily due to pretax income in 2018 compared to a pre-tax loss from continuing operations in 2017. See Note 10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods. Our effective rate in future periods could be impacted by a valuation allowance on federal NOL carryovers (see Note 10 of Notes to Consolidated Financial Statements).

Loss from discontinued operations in 2018 primarily relates to a $147 million pretax loss on the sale of our San Juan Gallup operations which was sold in the first quarter of 2018. Loss from discontinued operations in 2017 primarily relates to a $60 million impairment of San Juan Legacy assets partially offset by operating results from the San Juan Basin. Other items in 2017 include accretion on the previously accrued liability for the contracts discussed below, partially offset by $10 million of severance tax refunds in the Piceance Basin related to prior years. See Note 3 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.

2017 vs. 2016 

Revenue Analysis

	Years ended December 31,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2017		2016
	(Millions)
Revenues:
Oil sales	$	879	$	451	$	428	95	%
Natural gas sales	67		35		32		91	%
Natural gas liquid sales	70		21		49		NM
Total product revenues	1,016		507		509		100	%
Net gain (loss) on derivatives	3		(207)		210		NM
Commodity management	25		177		(152)		(86)	%
Other	1		1		—		—	%
Total revenues	$	1,045	$	478	$	567	119	%

__________

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

50

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

•$428 million increase in oil sales reflects $239 million related to higher production sales volumes and $189 million related to higher sales prices for 2017 compared to 2016. The Delaware and Williston Basin volumes were 22.0 and 30.0 Mbbls per day, respectively, for 2017 compared to 13.0 and 20.8 Mbbls per day, respectively, for 2016. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for 2017 and 2016.

	Years ended December 31,
	2017		2016
Oil sales (per barrel)	$	46.36	$	36.36
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	(0.33)		15.30
Oil net price including all derivative settlements (per barrel)	$	46.03	$	51.66
Oil production sales volumes (Mbbls)	18,964		12,396
Per day oil production sales volumes (Mbbls/d)	52.0		33.9

__________

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

•$32 million increase in natural gas sales reflects $21 million related to higher sales prices and $11 million increase related to higher production sales volumes for 2017 compared to 2016. The increase in our production sales volumes occurred primarily in our Delaware Basin partially offset by the absence of volumes due to the sales of our natural gas producing properties in the Appalachian and Green River Basins. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2017 and 2016.

	Years ended December 31,
	2017		2016
Natural gas sales (per Mcf)	$	1.89	$	1.30
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.28		4.13
Natural gas net price including all derivative settlements (per Mcf)	$	2.17	$	5.43
Natural gas production sales volumes (MMcf)	35,311		27,115
Per day natural gas production sales volumes (MMcf/d)	96.7		74.1

__________

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

•$49 million increase in natural gas liquids sales is due to $36 million related to higher NGL sales prices and $13 million related to higher production sales volumes for 2017 compared to 2016. The increase in our production sales volumes is due to our Delaware Basin. The following table reflects NGL production prices and volumes for 2017 and 2016.

	Years ended December 31,
	2017		2016
NGL sales (per barrel)	$	19.26	$	9.43
NGL production sales volumes (Mbbls)	3,656		2,256
Per day NGL production sales volumes (Mbbls/d)	10.0		6.2

•$210 million favorable change in net gain (loss) on derivatives primarily reflects a favorable change from a loss of $207 million in 2016 to a gain of $3 million in 2017. Settlements from our derivatives totaled $4 million for 2017 and $302 million for 2016.

•$152 million decrease in commodity management revenues primarily due to lower natural gas sales volumes. Our volumes were higher in 2016 due in part to a short-term marketing agreement with the buyer of the Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. A similar decrease is reflected in the $181 million decrease in related commodity management costs and expenses, discussed below.

51

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

	Years ended December 31,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change		Per Boe Expense
	2017		2016						2017		2016
	(Millions)
Costs and expenses:
Depreciation, depletion and amortization	$	542	$	441	$	(101)	(23)	%	$	19.03	$	23.01
Lease and facility operating	168		118		(50)		(42)	%	$	5.90	$	6.16
Gathering, processing and transportation	24		12		(12)		(100)	%	$	0.83	$	0.61
Taxes other than income	79		43		(36)		(84)	%	$	2.78	$	2.24
Exploration	87		26		(61)		NM
General and administrative:
General and administrative expenses	138		171		33		19	%	$	4.79	$	8.94
Equity based compensation	28		31		3		10	%	$	1.01	$	1.60
Total general and administrative	166		202		36		18	%	$	5.80	$	10.54
Commodity management	27		208		181		87	%
Net (gain) loss—sales of assets and divestment  of transportation contracts (Note 5)	(161)		239		400		NM
Other—net	15		15		—		—	%
Total costs and expenses	$	947	$	1,304	$	357	27	%
Operating income (loss)	$	98	$	(826)	$	924	NM

__________

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

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

•$101 million increase in depreciation, depletion and amortization is due to increased production volumes partially offset by a $3.98 per Boe decrease in rate which was impacted by both an increase in the reserves due to an increase in the 12-month average price and the addition of new wells with lower relative cost per Boe.

•$50 million increase in lease and facility operating expenses primarily related to increased production volumes.

•$12 million increase in gathering, processing and transportation primarily due to higher volumes in the Delaware Basin.

•$36 million increase in taxes other than income primarily relates to increased product revenues.

•$61 million increase in exploration expenses is primarily due to unproved leasehold property impairment, amortization and expiration in 2017 which includes costs associated with certain expired leases in the Delaware Basin in excess of the accumulated amortization balance recorded during first-quarter 2017. These leases were renewed in second-quarter 2017. See Note 5 of Notes to Consolidated Financial Statements.

•$36 million decrease in general and administrative expenses primarily due to workforce reductions. In addition, 2016 included $15 million for severance and relocation costs associated with workforce reductions in third-quarter 2016 and office consolidations. Excluding the severance and relocation costs, total general and administrative expenses would have averaged $9.78 per Boe for 2016.

•$181 million decrease in commodity management expenses is primarily due to lower natural gas purchase volumes for 2017 compared to 2016. The higher volumes in 2016 were due in part to the marketing of the volumes for the purchaser of our Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. Also included in commodity management expenses for 2016 is $27 million for unutilized pipeline capacity related to divested transportation contracts.

•$161 net gain on sales of assets in 2017 primarily related to $103 million of gains on exchanges of leasehold acreage in the Delaware Basin and $48 million from recognition of deferred gains related to completion of commitments from a prior year disposition. The $239 million net loss on sales of assets and divestment of transportation contracts in 2016 relates to the divestment of transportation obligations. See Note 5 of Notes to Consolidated Financial Statements for further discussion of these items.

52

Results below operating income (loss)

	Years ended December 31,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2017		2016
	(Millions)
Operating income (loss)	$	98	$	(826)	$	924	NM
Interest expense	(188)		(207)		19		9	%
Loss on extinguishment of debt	(17)		(1)		(16)		NM
Investment income and other	3		2		1		(50)	%
Loss from continuing operations before income taxes	(104)		(1,032)		928		90	%
Benefit for income taxes	(128)		(360)		(232)		(64)	%
Income (loss) from continuing operations	24		(672)		696		NM
Income (loss) from discontinued operations	(40)		71		(111)		NM
Net loss	(16)		(601)		585		97	%

__________

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

The decrease in interest expense primarily relates to lower level of debt outstanding in 2017 compared to 2016.

In the third quarter of 2017, we issued $150 million of debt onto our 2024 Notes and extinguished $150 million of the 2020 Notes. As a result, we recorded a loss on extinguishment of debt of $17 million in 2017.

The benefit for income taxes for 2017 was less than the benefit in 2016 primarily due to lower pretax loss from continuing operations before income taxes in 2017 compared to 2016 offset by the $97 million impact to our net deferred tax liability of the enacted tax law change reducing the federal statutory rate from 35 percent to 21 percent. See Note 10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods. 

Loss from discontinued operations in 2017 primarily relates to a $60 million impairment of San Juan Legacy assets partially offset by operating results from the San Juan Basin. Other items in 2017 include accretion on the previously accrued liability for the contracts discussed below, partially offset by $10 million of severance tax refunds in the Piceance Basin related to prior years. Income from discontinued operations in 2016 primarily related to activity from the San Juan Basin including the gain on the sale of the San Juan gathering system as well as activity from the Piceance Basin which was sold early in the second quarter of 2016. In conjunction with our exit from the Powder River Basin in 2015, we recorded a liability in 2015 related to retained future commitments under gathering, processing and transportation contracts in the Powder River Basin. In 2017, we increased the remaining liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 3 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview and Liquidity

We expect our capital structure will provide us financial flexibility to meet our requirements for working capital and capital expenditures while maintaining a sufficient level of liquidity. Our primary sources of liquidity in 2019 are cash on hand, expected cash flows from operations, anticipated proceeds from the sales of non-core assets, and, if necessary, borrowings on our credit facility. We anticipate that the combination of these sources should be sufficient to allow us to pursue our business strategy and goals through at least 2019. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities.

We note the following assumptions for 2019 capital expenditures:

•our planned capital expenditures, excluding acquisitions and equity investments, are estimated to be approximately $1.1 billion to $1.275 billion of which $1.050 billion to $1.175 billion relates to drilling and completions, including facilities; and

•we have hedged a portion of our anticipated 2019 oil and gas production as disclosed in Commodity Price Risk Management following this section.

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

53

•lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs;

•lower than anticipated proceeds from asset sales;

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

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

•higher than expected development costs, including the impact of inflation.

Credit Facility

Our Credit Facility, as amended, includes total commitments of $1.5 billion, on a $2.0 billion Borrowing Base with a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. For additional information regarding the terms of our Credit Facility see Note 9 of Notes to Consolidated Financial Statements. As of December 31, 2018, WPX had $330 million borrowings outstanding, had $52 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement. Our unused borrowing availability was $1,118 million as of December 31, 2018.

Commodity Price Risk Management

To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 16 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 the date of this filing shown at weighted average volumes and basin-level weighted average prices:

Crude Oil	2019			2020
	Volume (Bbls/d)	Weighted Average Price ($/Bbl)		Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Fixed Price Swaps—WTI	48,274	$	54.24	—	$	—
Fixed Price Calls—WTI	5,000	$	54.08	—	$	—
Fixed Price Costless Collars—WTI	7,321	$50.00 - $60.19		—	$	—
Basis Swaps— Midland	21,008	$	(1.16)	7,486	$	(1.31)
Basis Swaps— Magellan East Houston/Midland	1,841	$	8.12	—	$	—
Basis Swaps— Argus LLS/Midland	838	$	8.60	—	$	—
Basis Swaps— Brent/WTI Spread	—	$	—	5,000	$	8.36
Basis Swaps— Nymex Calendar Monthly Avg Roll	20,000	$	0.11	—	$	—

Natural Gas	2019			2020
	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)		Volume (BBtu/d)	Weighted Average Price ($/MMBtu)
Fixed Price Swaps—Henry Hub	108	$	3.07	—	$	—
Basis Swaps—Permian	25	$	(0.39)	—	$	—
Basis Swaps—Waha	15	$	2.94	60	$	(0.79)
Basis Swaps—Houston Ship Channel	30	$	(0.09)		$	—

54

Credit Ratings

Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analyses when assigning credit ratings. While not a current factor related to our credit facility, a downgrade of our current rating could increase our future cost of borrowing, thereby negatively affecting our available liquidity. The ratings as of February 21, 2019 were as follows:

Standard and Poor’s
Corporate Credit Rating	BB-
Senior Unsecured Debt Rating	BB-
Outlook	Stable
Moody’s Investors Service
LT Corporate Family Rating	Ba3
Senior Unsecured Debt Rating	B1
Outlook	Stable

Sources (Uses) of Cash

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Net cash provided by (used in):
Operating activities	$	883	$	507	$	268
Investing activities	(896)		(1,436)		311
Financing activities	(170)		624		(120)
Increase (decrease) in cash and cash equivalents and restricted cash	$	(183)	$	(305)	$	459

Operating activities

Net cash provided by operating activities increased in 2018 from 2017 primarily due to higher production volumes and higher commodity prices in 2018, partially offset by higher operating costs and an increase in settlements paid on our derivatives.

Net cash provided by operating activities increased in 2017 from 2016 primarily due to higher commodity prices and higher production volumes in 2017, partially offset by lower realizations on our derivatives and higher operating costs.

Excluding changes in working capital, total cash provided by operating activities related to discontinued operations was approximately $44 million, $143 million and $102 million for 2018, 2017 and 2016, respectively. Cash outflows related to previous accruals for Powder River Basin gathering and transportation contracts retained were $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively.

Investing activities

The table below includes cash and incurred capital expenditures for drilling and completions and capital expenditures for land acquisitions.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Cash capital expenditures for drilling and completions:
Continuing operations	$	1,296	$	815	$	343
Discontinued operations	25		166		117
Total	$	1,321	$	981	$	460
Capital expenditures incurred for drilling and completions:
Continuing operations	$	1,327	$	880	$	369
Discontinued operations	23		168		103
Total	$	1,350	$	1,048	$	472
Land acquisitions	$	65	$	63	$	84

55

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

2018

•$645 million of net proceeds from the sale of San Juan Gallup (see Note 3 of Notes to Consolidated Financial Statements).

2017

•$155 million related to the sale of our natural gas-producing properties in the San Juan Basin (see Note 3 of Notes to Consolidated Financial Statements).

2016

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

•$280 million for the sale of our San Juan Basin gathering system during the first quarter of 2016 (see Note 3 of Notes to Consolidated Financial Statements).

Net cash used in investing activities for 2018 includes $102 million of additional investment in equity method investments. Net cash used in investing activities for the year ended December 31, 2017 includes $798 million related to the Panther Acquisition.

Investing activities in 2017 includes net proceeds of $338 million from the formation of the joint venture with Howard (see Note 6 of Notes to Consolidated Financial Statements).

Cash provided by investing activities in 2016 was impacted by a $238 million divestment of certain transportation contracts (see Note 5 of Notes to Consolidated Financial Statements).

Financing activities 

The following are significant financing activities by year:

2018

•$986 million of payments for retirement of long-term debt, including approximately $63 million of premium partially offset by $494 million net proceeds from a debt issuance in the second quarter of 2018. See Note 9 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance; and

•$330 million net borrowings on the Credit Facility.

2017

•In January 2017, we completed an equity offering of 51.675 million shares for net proceeds of approximately $670 million in conjunction with the Panther Acquisition;

•$15 million of preferred stock dividends; and

•payment of $165 million, including premium, to repurchase some of our 2020 Senior Notes partially offset by $148 million of net proceeds related to the issuance of additional notes due 2024.

2016

•In June 2016, we completed an equity offering of 56.925 million shares of our common stock for net proceeds of approximately $538 million;

•net repayments under the Credit Facility of $265 million;

•$355 million repayment of our Senior Notes due 2017;

•$18 million of preferred stock dividends; and

•$10 million of cash paid as an inducement for the conversion of a portion of outstanding preferred stock to common stock.

56

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, 2018 and December 31, 2017. Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a divestment.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2018.

	2019		2020 – 2021		2022 – 2023		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal	$	—	$	—	$	1,359	$	1,150	$	2,509
Interest	151		302		243		106		802
Operating leases and associated service commitments:
Drilling rig commitments(a)	65		40		—		—		105
Other	27		32		3		—		62
Transportation commitments(b)	115		163		106		352		736
Oil and gas activities(c)	106		121		83		74		384
Financial derivatives(d)	23		8		7		—		38
Other	11		15		7		1		34
Total obligations	$	498	$	681	$	1,808	$	1,683	$	4,670

 __________

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

(b) Includes firm demand obligations of $44 million of which $40 million is recorded as a liability as of December 31, 2018. A liability was recorded in 2015 in conjunction with our exit from the Powder River Basin (see Note 3 of Notes to Consolidated Financial Statements). Excludes additional commitments totaling $123 million associated with projects for which a counterparty has not completed construction.

(c) Includes gathering, processing and other oil and gas related services commitments of which $24 million is recorded as a liability as of December 31, 2018. Liabilities were recorded in 2015 in conjunction with our exit from the Powder River Basin and associated with an abandoned area in the Appalachian Basin. Excluded are liabilities associated with asset retirement obligations totaling $72 million as of December 31, 2018. The ultimate settlement and timing of asset retirement obligations cannot be precisely determined in advance; however, we estimate that approximately 26 percent of this liability will be settled in the next five years.

(d) Obligations for financial derivatives are based on market information as of December 31, 2018, 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.

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 oil, natural gas, 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 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.

57

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

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

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

The process of estimating oil and natural gas reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, approximately 100 percent of our 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 and amortization expense between approximately $69 million and $84 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 oil and natural gas also impact certain costs associated with our underlying production and future capital costs. The prices of oil and natural gas 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. See impairments of long-lived assets below.

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 $1.8 billion at December 31, 2018 and is primarily associated with our Delaware Basin acreage.

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. When an indicator of impairment has occurred, we compare our estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine if an impairment has occurred. If an impairment has occurred, we determine the amount of impairment by estimating the fair value of the assets. 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.

We assess our proved properties for impairment using estimates of future undiscounted 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. The assessment performed as of December 31, 2018 did not identify any properties with a carrying value in excess of those estimated undiscounted cash flows. Therefore, no impairment charges were recorded in 2018 based on this assessment.

58

The assessments described above included approximately $5.4 billion of net book value associated with our proved properties. 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. As previously noted within “Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities”, estimated natural gas and oil reserves and estimated future commodity prices for oil and gas are a significant part of our impairment analysis. Commodity prices are significantly volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel over the past five years. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. Approximately 51 percent of our future production considered in the impairment assessment is in years 2024 and beyond. If the estimated commodity revenues (only one of the many estimates involved) of the predominately oil proved properties were lower by 20 to 30 percent, these properties could be at risk for impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant.

Valuation of Deferred Tax Assets and Liabilities

We record deferred taxes for the differences between the tax and book basis of our assets and liabilities as well as loss or credit carryovers to future years. Included in our deferred taxes are deferred tax assets primarily resulting from certain federal and state tax loss carryovers generated in the current and prior years, capital loss carryovers and 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 primarily consider future reversals of existing taxable temporary differences. To a lesser extent, we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets.

As of December 31, 2018, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss or limitation due to an ownership change may result in the need for a valuation allowance on our deferred 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.

Fair Value Measurements

A small portion of our energy derivative assets and liabilities trade in markets with limited 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 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, 2018, 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, 2018, 99 percent of the fair value of our derivatives portfolio expires in the next 12 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.

59

There were $3 million of instruments included in Level 3 at December 31, 2018.

For the year ended December 31, 2017, we recognized an impairment in discontinued operations on natural gas-producing properties held for sale in the San Juan Basin as a result of comparing our book value to the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected sales proceeds. In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. See Note 15 of Notes to Consolidated Financial Statements.

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 11 of Notes to Consolidated Financial Statements.

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, $529 million matures in 2022, $500 million matures in 2023, $650 million matures in 2024 and $500 million matures in 2026. Interest rates for each group are 6.00 percent, 8.25 percent, 5.25 percent and 5.75 percent, respectively. The aggregate fair value of the senior notes is $2,084 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, 2018, we had $330 million outstanding under the Credit Facility Agreement. See Note 9 of Notes to Consolidated Financial Statements.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of oil, natural gas 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 15 and 16 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.

60

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

We currently have entered into no other derivative contracts for purposes other than economically hedging our commodity price-risk exposure.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our energy commodity purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $141 million at December 31, 2018 and net liability of $177 million at December 31, 2017.

The value at risk for derivative contracts held for nontrading purposes was $26 million at December 31, 2018, and $56 million at December 31, 2017. During the year ended December 31, 2018, our value at risk for these contracts ranged from a high of $52 million to a low of $26 million. The decrease in value at risk from December 31, 2017 primarily reflects positions entered into to economically hedge our equity production being realized.

61

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, 2018, based on the criteria set forth in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2018, 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.

62

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of WPX Energy, Inc.,

Opinion on Internal Control over Financial Reporting

We have audited WPX Energy, Inc.’s internal control over financial reporting as of December 31, 2018, 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). In our opinion, WPX Energy, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of WPX Energy, Inc. as of December 31, 2018 and 2017, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and financial statement schedule listed in the Index at Item 15.(a) and our report dated February 21, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. 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.

Definition and Limitations of Internal Control Over Financial Reporting

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.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 21, 2019 

63

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of WPX Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of WPX Energy, Inc. (the Company) as of December 31, 2018 and 2017, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and financial statement schedule listed in the Index at Item 15.(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, 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 21, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Tulsa, Oklahoma

February 21, 2019

64

WPX Energy, Inc.

Consolidated Balance Sheets 

	December 31,
	2018		2017
	(Millions)
Assets
Current assets:
Cash and cash equivalents	$	3	$	189
Accounts receivable, net of allowance	405		307
Derivative assets	174		36
Inventories	48		30
Assets classified as held for sale	79		811
Other	30		28
Total current assets	739		1,401
Investments	167		70
Properties and equipment, net (successful efforts method of accounting)	7,266		6,691
Derivative assets	4		23
Other noncurrent assets	27		22
Total assets	$	8,203	$	8,207
Liabilities and Equity
Current liabilities:
Accounts payable	$	514	$	446
Accrued and other current liabilities	178		209
Liabilities associated with assets held for sale	—		20
Derivative liabilities	23		171
Total current liabilities	715		846
Deferred income taxes	201		117
Long-term debt, net	2,485		2,575
Derivative liabilities	14		65
Other noncurrent liabilities	487		477
Contingent liabilities and commitments (Note 11)
Equity:
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding at December 31, 2018 and 4.8 million shares outstanding at December 31, 2017)	—		232
Common stock (2 billion shares authorized at $0.01 par value; 420.6 million and 398.3 million shares issued and outstanding at December 31, 2018 and 2017)	4		4
Additional paid-in-capital	7,734		7,479
Accumulated deficit	(3,437)		(3,588)
Total equity	4,301		4,127
Total liabilities and equity	$	8,203	$	8,207

See accompanying notes.

65

WPX Energy, Inc.

Consolidated Statements of Operations

	Years Ended December 31,
	2018		2017		2016
Revenues:	(Millions, except per share amounts)
Product revenues:
Oil sales	$	1,790	$	879	$	451
Natural gas sales	87		67		35
Natural gas liquid sales	148		70		21
Total product revenues	2,025		1,016		507
Net gain (loss) on derivatives	81		3		(207)
Commodity management	204		25		177
Other	—		1		1
Total revenues	2,310		1,045		478
Costs and expenses:
Depreciation, depletion and amortization	777		542		441
Lease and facility operating	272		168		118
Gathering, processing and transportation	107		24		12
Taxes other than income	157		79		43
Exploration	75		87		26
General and administrative (including equity-based compensation of $32 million, $28 million and $31 million for the respective periods)	182		166		202
Commodity management	182		27		208
Net (gain) loss on sales of assets and divestment of transportation contracts (Note 5)	(3)		(161)		239
Other—net	7		15		15
Total costs and expenses	1,756		947		1,304
Operating income (loss)	554		98		(826)
Interest expense	(163)		(188)		(207)
Loss on extinguishment of debt (Note 9)	(71)		(17)		(1)
Investment income (loss) and other	(4)		3		2
Income (loss) from continuing operations before income taxes	316		(104)		(1,032)
Provision (benefit) for income taxes	74		(128)		(360)
Income (loss) from continuing operations	242		24		(672)
Income (loss) from discontinued operations	(91)		(40)		71
Net income (loss)	151		(16)		(601)
Less: Dividends on preferred stock	8		15		18
Less: Loss on induced conversion of preferred stock	—		—		22
Net income (loss) available to WPX Energy, Inc. common stockholders	$	143	$	(31)	$	(641)
(continued on next page)

66

WPX Energy, Inc.
Consolidated Statements of Operations-(Continued)
	Years Ended December 31,
	2018		2017		2016
	(Millions, except per share amounts)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	234	$	9	$	(712)
Income (loss) from discontinued operations	(91)		(40)		71
Net income (loss)	$	143	$	(31)	$	(641)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.57	$	0.02	$	(2.28)
Income (loss) from discontinued operations	(0.22)		(0.10)		0.23
Net income (loss)	$	0.35	$	(0.08)	$	(2.05)
Basic weighted-average shares	408.4		395.1		313.3
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.57	$	0.02	$	(2.28)
Income (loss) from discontinued operations	(0.22)		(0.10)		0.23
Net income (loss)	$	0.35	$	(0.08)	$	(2.05)
Diluted weighted-average shares	411.7		397.4		313.3

See accompanying notes.

67

WPX Energy, Inc.

Consolidated Statements of Changes in Equity

			WPX Energy, Inc., Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Accumulated Deficit		Total Stockholders’ Equity
	(Millions)
Balance at December 31, 2015	$	339	$	3	$	6,164	$	(2,971)	$	3,535
Net loss							(601)		(601)
Stock based compensation, net of tax benefit					23				23
Issuance of common stock to public, net of offering costs					538				538
Conversion of preferred stock to common stock	(107)				118				11
Loss on induced conversion of preferred stock and related conversion costs					(22)				(22)
Dividends on preferred stock					(18)				(18)
Balance at December 31, 2016	232		3		6,803		(3,572)		3,466
Net loss							(16)		(16)
Stock based compensation, net of tax impact					22				22
Issuance of common stock to public, net of offering costs			1		669				670
Dividends on preferred stock					(15)				(15)
Balance at December 31, 2017	232		4		7,479		(3,588)		4,127
Net income							151		151
Stock based compensation, net of tax impact					31				31
Conversion of preferred stock to common stock	(232)				232				—
Dividends on preferred stock					(8)				(8)
Balance at December 31, 2018	$	—	$	4	$	7,734	$	(3,437)	$	4,301

See accompanying notes.

68

WPX Energy, Inc.

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2018		2017		2016
Operating Activities(a)	(Millions)
Net income (loss)	$	151	$	(16)	$	(601)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	785		673		631
Deferred income tax provision (benefit)	84		(134)		(281)
Provision for impairment of properties and equipment (including certain  exploration expenses) and investments	73		158		38
Net (gain) loss on derivatives in continuing operations	(81)		(3)		207
Net (payments) settlements related to derivatives in continuing operations	(237)		4		302
Net loss on derivatives included in discontinued operations	—		—		46
Amortization of stock-based awards	34		32		36
Loss on extinguishment of debt and acquisition bridge financing fees	71		17		1
Net (gains) losses on sales of assets and divestment of transportation contracts	145		(170)		(29)
Cash provided by (used in) operating assets and liabilities:
Accounts receivable	(59)		(153)		126
Inventories	(15)		(8)		10
Other current assets	2		(8)		5
Accounts payable	17		158		(72)
Federal income tax receivable and payable	(38)		12		(19)
Accrued and other current liabilities	(22)		(31)		(45)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	(47)		(53)		(53)
Other, including changes in other noncurrent assets and liabilities	20		29		(34)
Net cash provided by operating activities(a)	883		507		268
Investing Activities(a)
Capital expenditures(b)	(1,476)		(1,161)		(578)
Proceeds from sales of assets	682		193		1,127
Payments related to divestment of transportation contracts	—		—		(238)
Purchases of a business, net of cash acquired	—		(799)		—
Net proceeds from the joint venture formation	—		338		—
Purchases of or contributions to investments	(102)		(8)		—
Other	—		1		—
Net cash provided by (used in) investing activities(a)	(896)		(1,436)		311
Financing Activities
Proceeds from common stock	10		672		540
Dividends paid on preferred stock	(11)		(15)		(18)
Payments related to induced conversion of preferred stock to common stock	—		—		(10)
Borrowings on credit facility	1,453		661		380
Payments on credit facility	(1,123)		(661)		(645)
Proceeds from long-term debt, net of discount	494		148		—
Payments for retirement of long-term debt, including premium	(986)		(165)		(356)
Taxes paid for shares withheld	(14)		(12)		(6)
Payments for debt issuance costs and credit facility amendment fees	(10)		(2)		(5)
Other	17		(2)		—
Net cash provided by (used in) financing activities	(170)		624		(120)
Net increase (decrease) in cash and cash equivalents and restricted cash	(183)		(305)		459
Cash and cash equivalents and restricted cash at beginning of period	201		506		47
Cash and cash equivalents and restricted cash at end of period	$	18	$	201	$	506
__________
(a) Amounts reflect continuing and discontinued operations unless otherwise noted.
(b)   Increase to properties and equipment	$	(1,510)	$	(1,232)	$	(584)
Changes in related accounts payable and accounts receivable	34		71		6
Capital expenditures	$	(1,476)	$	(1,161)	$	(578)

See accompanying notes.

69

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 oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3).

We had operations in the San Juan Basin which were sold in 2017 and 2018 that are reported in discontinued operations as discussed below. We also had other operations sold in 2016 which are reported as discontinued operations, as discussed below.

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

Basis of Presentation and 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. The Company has no other elements of comprehensive income (loss) other than net income (loss).

Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.

Discontinued Operations 

On January 30, 2018, we signed an agreement to sell our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC for $700 million (subject to closing and post-closing adjustments). This sale closed in March 2018. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million, a portion of which closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. The assets and liabilities were reclassified as held for sale on the Consolidated Balance Sheet as of December 31, 2017 and the results of operations of the San Juan Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3).

Our discontinued operations also include the results of previously owned properties in the Piceance Basin.

See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

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;

•valuation of deferred tax assets and liabilities;

•valuations of derivatives;

•estimation of oil and natural gas reserves; and

•assessments of litigation-related contingencies.

These estimates are discussed further throughout these notes.

70

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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 was approximately $15 million and $12 million as of December 31, 2018 and 2017, respectively, and is included in other current assets on the Consolidated Balance Sheets.

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. The following table presents a summary of inventories.

	Years ended December 31,
	2018		2017
	(Millions)
Material, supplies and other	$	46	$	29
Commodity production in storage	2		1
	$	48	$	30

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. 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 on the Consolidated Statements of Operations. 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 as unproved properties.

From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange in which commercial substance is established, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.

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.

71

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. 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.

72

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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.

Certain gains and losses on derivative instruments included on 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 commodity management and for which we have not elected the normal purchases and normal sales exception;

•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 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 and commodity management revenues

Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.

Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.

Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Significant judgments related to revenue recognition include principal versus agent considerations.

We record revenue on a gross basis when we control a promised good or service before transferring it to a customer. We record

73

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

revenue on a net basis when we arrange for another company to provide the good or service. Determining the point and time when control of a product transfers to a customer requires significant judgment. Payment is typically due 30 to 45 days following delivery of product to our customers. 

Revenues from production 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 revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2018 and 2017 was insignificant.

Commodity management expenses

Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million in 2016.

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. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.

Employee stock-based compensation

Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Performance-based awards are tied to shareholder return over time relative to our peer group and are valued using a Monte Carlo method using measures of total shareholder return.

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 and awards (see Note 4).

Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $35 million and $32 million as of December 31, 2018 and 2017, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets. 

Recently Adopted Accounting Standards

The Company adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is 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. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at December 31, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are

74

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

wholly unsatisfied at the reporting period end. In addition, see Note 16 for receivables related to sales of oil, natural gas and related products and services.

We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $15 million, $12 million and $10 million as of December 31, 2018, 2017 and 2016, respectively.

We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.

We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.

Accounting Standards Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on review of the guidance and the Company’s current commitments, the Company believes it will be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and other arrangements. In 2018, we began the process of evaluating our contracts with components that may be subject to ASU 2016-02 and engaged a third party to assist with implementing the standard. In 2018 and 2019, we have implemented appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company is finalizing the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We believe the amounts recorded as right to use assets and lease payment liabilities will be less than $100 million.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to exclude from evaluation any land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. The amendments affect trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with and expected loss model for instruments measured at amortized cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

75

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.

Note 2. Acquisition

On January 12, 2017, we signed an agreement to acquire certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”) for $775 million, subject to post-closing adjustments. The transaction closed in March 2017 for $798 million including estimated closing adjustments. The assets, as of the closing date, included 25 producing wells (18 horizontals), three drilled but uncompleted horizontal laterals, approximately 18,000 net acres and more than 900 gross undeveloped locations in the Delaware Basin. We estimated that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved developed properties and facilities. This estimate is based on discounted cash flow models, which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. These assumptions represent Level 3 inputs. At the time of the acquisition closing, production was approximately 10,000 Boe per day. The impact of this acquisition to prior periods is not material to our results of operations for those periods. 

Note 3. Discontinued Operations

On January 30, 2018, we signed an agreement to sell our operations in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC (“Enduring”) for $700 million (subject to closing and post-closing adjustments). The transaction closed on March 28, 2018 and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. We believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and Enduring and the declining size of the obligations subject to the guarantee over time. Although we believe the probability of performance by WPX is low, we must determine the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018. The operations in the San Juan Gallup represented 12 percent of our total proved reserves at December 31, 2017 and 16 percent of our total production for 2017.

In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million and recorded a gain of approximately $2 million. A portion of the San Juan Legacy sale closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin.

Significant transactions for the San Juan Basin operations reflected in the tables below are as follows:

76

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

•In the third quarter of 2017, we began a process to market our San Juan Legacy properties and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value at September 30, 2017 which resulted in an impairment of $60 million recorded in third-quarter 2017. At the close of the sale, we recorded a gain of $2 million.

•On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million. The consideration reflected $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX’s development in the Gallup oil play. We were obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and additional gains of $18 million in the subsequent quarters of 2016 as certain in-progress construction was completed. As of December 31, 2017, the remaining deferred gain was approximately $3 million.

On February 8, 2016, we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations for $910 million. The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million, subject to post-closing adjustments, resulting in a gain of $52 million. We performed certain transition services for the buyer which concluded during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in commodity management revenue and expenses.

We sold our Powder River Basin properties in 2015; however, we retained certain firm gathering and treating obligations that continue through 2020 related to the Powder River properties sold. These commitments had been in excess of the production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company that continue through 2021. We recorded liabilities related to these commitments in 2015. In 2017, we increased the liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 11 for additional information related to these liabilities.

Summarized Results of Discontinued Operations

The following table presents the results of discontinued operations for the years presented.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Total revenues	$	75	$	291	$	279
Costs and expenses:
Depreciation, depletion and amortization	$	8	$	131	$	191
Lease and facility operating	7		50		63
Gathering, processing and transportation	12		70		113
Taxes other than income	5		23		19
Exploration	3		14		16
General and administrative	1		8		21
Accrual for contract obligations retained	—		5		—
Net (gain) loss—sales of assets and impairments	—		50		(217)
Accretion of liabilities related to contract obligations retained	6		6		2
Other—net(a)	5		(3)		7
Total costs and expenses	47		354		215
Operating income (loss)	28		(63)		64
Gain (loss) on sales of domestic assets	(148)		—		51
Income (loss) from discontinued operations before income taxes	(120)		(63)		115
Provision (benefit) for income taxes	(29)		(23)		44
Income (loss) from discontinued operations	$	(91)	$	(40)	$	71

 __________

(a) Includes severance tax refund received in 2017.

77

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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

	December 31,
	2017
	(Millions)
Assets classified as held for sale
Inventories	$	14
Properties and equipment, net (successful efforts method of accounting)	797
Total assets classified as held for sale on the Consolidated Balance Sheets	$	811
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	1
Accrued and other current liabilities	1
Total current liabilities	2
Asset retirement obligations	15
Other noncurrent liabilities	3
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	20

Cash Flows Attributable to Discontinued Operations

In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Cash provided by operating activities(a)	$	44	$	143	$	102
Cash capital expenditures within investing activities	$	29	$	175	$	135

 __________

(a) Excluding income taxes and changes to working capital.

78

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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

 The following table summarizes the calculation of earnings per share.

	Years Ended December 31,
	2018		2017		2016
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	242	$	24	$	(672)
Less: Dividends on preferred stock	8		15		18
Less: Loss on induced conversion of preferred stock	—		—		22
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income (loss) per common share	$	234	$	9	$	(712)
Basic weighted-average shares	408.4		395.1		313.3
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	3.1		2.1		—
Stock options	0.2		0.2		—
Diluted weighted-average shares(a)	411.7		397.4		313.3
Income (loss) per common share from continuing operations:
Basic	$	0.57	$	0.02	$	(2.28)
Diluted	$	0.57	$	0.02	$	(2.28)

 __________

(a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:  

	Years Ended December 31,
	2018	2017	2016
	(Millions)
Weighted-average nonvested restricted stock units and awards	—	—	2.2
Weighted-average stock options	—	—	0.01
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)	11.4	19.8	23.8
Nonvested restricted stock units antidilutive under the treasury stock method	0.7	0.6	—

The table below includes information related to stock options that were outstanding at December 31, 2018, 2017 and 2016 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.

	December 31,
	2018		2017		2016
Options excluded (millions)	0.7		1.5		2.0
Weighted-average exercise price of options excluded	$	18.05	$	17.80	$	17.42
Exercise price range of options excluded	$16.46 - $21.81		$14.41 - $21.81		$14.41 - $21.81
Fourth quarter weighted-average market price	$	15.16	$	12.10	$	13.23

79

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 5. Asset Sales and Exploration Expenses

Asset Sales

2017

Net gain on sales of assets for the year ended December 31, 2017 primarily reflect total gains of $103 million from exchanges of leasehold acreage in the Permian Basin, $48 million from the recognition of deferred gains related to the completion of commitments from the sale in 2015 of a North Dakota gathering system and $8 million recognized on the sales of certain Green River Basin and Appalachian Basin assets.

In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs.

2016

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

Exploration Expenses

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Unproved leasehold property impairments, amortization and expiration	$	69	$	84	$	22
Geologic and geophysical costs	6		$	3	3
Impairments of exploratory area well costs and dry hole costs	—		—		1
Total exploration expenses	$	75	$	87	$	26

Unproved leasehold property impairment, amortization and expiration for 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Permian Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.

Note 6. Investments

In June 2017, we signed an agreement with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the agreement, WPX and Howard each have a 50 percent voting interest in the newly formed joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity will serve as operator. In addition to a $300 million cash contribution, Howard is obligated to fund the first $263 million of joint venture capital expenditures. At closing in October 2017, WPX contributed subsidiaries holding crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $53 million. WPX also paid $11 million for advisory services and legal fees on the transaction. Howard contributed $439 million in cash at closing, $139 million of which applies to the $263 million carry obligation of Howard including $49 million for capital expenditures from January 1, 2017 to closing. Concurrently, WPX received a $300 million special distribution plus the $49 million for capital expenditures from Catalyst. We will account for our investment in Catalyst as an equity method investment. In connection with the joint venture, a consolidated subsidiary of WPX dedicated production from its current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to 20 year fixed-fee oil gathering and natural gas processing agreements with subsidiaries of Catalyst. The agreements do not include any minimum volume commitments. Our investment in Catalyst totaled $58 million and $64 million as of December 31, 2018 and 2017, respectively. In 2017, we deferred recognition of the $349 million and will recognize it over the 20 years based on production volumes as a deduction to gathering, processing and transportation expense. As of December 31, 2018, the deferred amount was $346 million of which $336 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.

During 2018, we contributed an additional $93 million to our equity method investment in the Oryx II pipeline project, of which $23 million increased our ownership from 12.5 percent to 25 percent.

80

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 7. Properties and Equipment

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

	Estimated Useful Life(a) (Years)	December 31,
		2018		2017
		(Millions)
Proved properties	(b)	$	7,289	$	5,815
Unproved properties	(c)	1,891		2,194
Gathering, processing and other facilities	15-25	294		242
Construction in progress	(c)	350		305
Other	3-40	125		118
Total properties and equipment, at cost		9,949		8,674
Accumulated depreciation, depletion and amortization		(2,683)		(1,983)
Properties and equipment—net		$	7,266	$	6,691

__________

(a) Estimated useful lives are presented as of December 31, 2018.

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

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

Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.

In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 17).

Asset Retirement Obligations 

Our asset retirement obligations relate to producing wells, 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. Asset retirement obligations are reported in other noncurrent liabilities on the Consolidated Balance Sheets.

A rollforward of our asset retirement obligations for the years ended 2018 and 2017 is presented below.

	2018		2017
	(Millions)
Balance, January 1	$	39	$	40
Liabilities incurred	8		5
Liabilities settled	(7)		(11)
Estimate revisions	30		3
Accretion expense(a)	2		2
Balance, December 31	$	72	$	39
Amount reflected as current	$	5	$	7

__________

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

81

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 8. Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable

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

	December 31,
	2018		2017
	(Millions)
Trade	$	130	$	120
Accrual for capital expenditures	190		151
Royalties	170		150
Cash overdrafts	17		—
Other	7		25
	$	514	$	446

Accrued and other current liabilities

The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.

	December 31,
	2018		2017
	(Millions)
Taxes other than income taxes	$	19	$	14
Accrued interest	45		69
Compensation and benefit related accruals	39		39
Gathering and transportation	7		11
Gathering and transportation related to exited areas	30		53
Other, including other loss contingencies	38		23
	$	178	$	209

Note 9. Debt and Banking Arrangements

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

	December 31,
	2018 (a)		2017 (a)
	(Millions)
Credit facility agreement	$	330	$	—
7.500% Senior Notes due 2020	—		350
6.000% Senior Notes due 2022	529		1,100
8.250% Senior Notes due 2023	500		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		—
Total debt	$	2,509	$	2,600
Less: Current portion of long-term debt	—		—
Total long-term debt	$	2,509	$	2,600
Less: Debt issuance costs(b)	24		25
Total long-term debt, net(b)	$	2,485	$	2,575

__________

(a) Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.

(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

82

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Credit Facility

On April 17, 2018, the Company entered into a Second Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, increases total commitments to $1.5 billion, increases the Borrowing Base to $1.8 billion, and extends the maturity date to April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2018, WPX had $330 million borrowings outstanding, had $52 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement.

Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. In October 2018, the Borrowing Base was increased to $2.0 billion and will remain in effect until the next Redetermination Date as set forth in the Credit Facility. At this time, the Credit Facility Agreement is limited by the total commitments on the Credit Facility which remained at $1.5 billion. The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.

Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.

The Collateral Trigger Termination Date is the first date following the Second Amendment Effective Date and the first date following any Collateral Trigger Date, as applicable, on which:

1.(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or

2.in the case of a Voluntary Collateral Trigger Period, WPX elects to cause a Collateral Trigger Termination Date to occur.

Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings.

Significant Financial Covenants.

Currently, the Company is required to maintain:

• ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 4.25 to 1.00 as of the last day of the Rolling Period; and

•a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.

If a Collateral Trigger Termination Date occurs, other financial covenants would apply.

Covenants. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit,

83

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties.

Events of Default. The Credit Facility includes customary events of default, including events of default relating to:

•non-payment of principal, interest or fees;

•inaccuracy of representations and warranties in any material respect when made or when deemed made;

•violation of covenants;

•cross payment-defaults;

•cross acceleration;

•bankruptcy and insolvency events;

•certain unsatisfied judgments;

•a change of control; and

•during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.

If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2018.  

Senior Note	Face Value (Millions)		Maturity Date	Interest Payment Dates	Optional Redemption Period(a)
6.000% Senior Notes due 2022 (the “2022 Notes”)	$	529	January 15, 2022	January 15, July 15	October 15, 2021
8.250% Senior Notes due 2023 (the “2023 Notes”)	$	500	August 1, 2023	February 1, August 1	June 1, 2023
5.250% Senior Notes due 2024 (the “2024 Notes”)	$	650	September 15, 2024	March 15, September 15	June 15, 2024
5.750% Senior Notes due 2026 (the “2026 Notes”)	$	500	June 1, 2026	June 1, December 1	June 1, 2021

 __________

(a) At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the 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 as more fully described in the indenture.

In the second quarter of 2018, we used proceeds from our San Juan Gallup disposition and the issuance of new senior notes discussed below to retire $921 million aggregate principal amount of our senior notes ($350 million due 2020 and $571 million due 2022) through a series of cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $71 million, which includes approximately $63 million of premium and approximately $6 million write-off of previously capitalized costs.

84

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

On May 23, 2018, we completed a debt offering of $500 million of 5.750% Senior Notes due in 2026 (the “2026 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on June 1 and December 1 of each year commencing on December 1, 2018. The 2026 Notes will mature on June 1, 2026 with the option, prior to June 1, 2021, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, after June 1, 2021, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2026 Notes was approximately $494 million and approximately $1 million of debt issuance costs were capitalized.

During third-quarter 2017, we issued an additional $150 million of our 5.250% senior notes due 2024. The proceeds were used to fund the tender offer of $150 million of our 7.500% senior notes due 2020. As a result, we recorded a loss on extinguishment of debt of $17 million.

The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes and 2026 Notes are substantially identical.

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.

Note 10. Provision (Benefit) for Income Taxes

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

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Provision (benefit):
Current:
Federal	$	(38)	$	(18)	$	(26)
State	1		1		(7)
	(37)		(17)		(33)
Deferred:
Federal	107		(100)		(333)
State	4		(11)		6
	111		(111)		(327)
Total provision (benefit)	$	74	$	(128)	$	(360)

85

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Act”). The income tax effects of changes in tax laws are recognized in the period when enacted. The Act repealed the corporate alternative minimum tax (“AMT”) and amended Section 53 of the Internal Revenue Code to allow for refunds of AMT credit carryforwards. Under Section 53(e), taxpayers receive 50 percent of their uncredited balance in years 2018–2020. Taxpayers receive 100 percent of the remaining balance in 2021. Accordingly, the Company recorded a current receivable of $38 million as of December 31, 2018 related to AMT credit refunds expected to be collected in 2019. However, our AMT credit carryforwards are subject to change based on the results of the 2011 Williams audit discussed below and may impact future refunds.

The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.

	Years Ended December 31,
	2018			2017			2016
	(Millions)
Federal Statutory Rate	21		%	35		%	35		%
Provision (benefit) at statutory rate	$	66		$	(36)		$	(361)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	(8)			(12)			(42)
Valuation allowance on current year state income taxes (net of federal   benefit)	17			17			18
Valuation allowance on state income taxes resulting from sale (net of   federal benefit)	—			—			8
Effective state income tax rate change (net of federal benefit)	(5)			(12)			15
Provisional impact of Tax Cuts and Jobs Act	—			(92)			—
Other	4			7			2
Provision (benefit) for income taxes	$	74		$	(128)		$	(360)

As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years. As a result of the sale of our Piceance Basin operations in Colorado in the second quarter of 2016, we recorded $8 million of valuation allowances against Colorado NOL and credit carryovers generated in prior years.

Significant changes to our operations during 2018, 2017 and 2016 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we recorded an additional $5 million and $12 million deferred tax benefit in 2018 and 2017, respectively. We also accrued an additional $15 million of deferred tax expense in 2016.

Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allowed us to provide a provisional estimate of the impacts of the Act in our earnings for the year ending December 31, 2017. Additional impacts from the enactment of the Act were allowed to be recorded as they were identified during the one-year measurement period as provided for in SAB 118. Accordingly, the Company did not have any adjustments to its provisional amounts.

86

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

The following table includes significant components of deferred tax liabilities and deferred tax assets.

	December 31,
	2018		2017
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	797	$	792
Derivatives, net	33		—
Other, net	—		1
Total deferred tax liabilities	830		793
Deferred tax assets:
Accrued liabilities and other	137		79
Alternative minimum tax credits	40		78
Loss carryovers	665		672
Derivatives, net	—		42
Total deferred tax assets	842		871
Less: valuation allowance	213		195
Total net deferred tax assets	629		676
Net deferred tax liabilities	$	201	$	117

Net cash payments (refunds) for income taxes were $2 million, $(39) million and $21 million in 2018, 2017 and 2016, respectively.

The Company has federal NOL carryovers of approximately $2,021 million at December 31, 2018, including a $353 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, we have $48 million of federal capital loss carryovers at December 31, 2018, that will begin to expire in 2020. 

The Company has state NOL carryovers of approximately $4.1 billion and $3.8 billion at 2018 and 2017, respectively, of which more than 99 percent expire after 2029.

We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. As of December 31, 2018, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss may result in the need for a valuation allowance on our deferred tax assets.

The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of December 31, 2018, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI NOL that arose prior to the acquisition.

Pursuant to our tax sharing agreement with The Williams Companies ("Williams"), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. The IRS has proposed an adjustment related to our business for which a payment to Williams could be required. We have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not 

87

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS.

The Company files a consolidated federal income tax return and several state income tax returns. The Company’s federal income tax returns for tax years 2014 through 2016 remain open for examination. The statute of limitations for most states expires one year after expiration of the IRS statute. During the year ended December 31, 2017, the IRS began an examination of the Company’s 2014, 2015 and 2016 federal income tax returns. In addition, the IRS began an examination of RKI’s 2014 and short-period 2015 federal income tax returns. These examinations remain ongoing and no additional taxes or refunds have been recorded at this time.

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 less than $1 million for 2018 and 2017. The impact of this accrual is included within Other in our reconciliation of the provision (benefit) at statutory rate to recorded provision (benefit) for income taxes.

As of December 31, 2018, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. 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 11. Contingent Liabilities and Commitments

Contingent Liabilities

Royalty litigation

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and on September 21, 2018 the Tenth Circuit dismissed the appeal for lack of jurisdiction. On January 22, 2019, plaintiffs’ filed a petition for certiorari to the United States Supreme Court. At this time, we believe that our royalty calculations were 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 many of 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. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.

Environmental matters

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

88

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Matters related to Williams’ former power business

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

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. On October 23, 2018, a settlement in principle with the Kansas and Missouri class claimants was reached. Final documents have not been finalized and approved by the Court. In the Wisconsin class action, defendants’ motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs’ motion to remand the case to the originally filed district court.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.

Other Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements.

The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.

As of December 31, 2018, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

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

89

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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, 2018 and December 31, 2017, the Company had accrued approximately $11 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 

We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our oil and natural gas production and third-party purchases of oil and natural gas to other locations in an attempt to obtain more favorable pricing differentials. During 2017 and 2018, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. As of December 31, 2018, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:

	Midstream Services		Transportation		Total
	(Millions)
2019	$	55	$	115	$	170
2020	58		95		153
2021	48		68		116
2022	43		59		102
2023	40		47		87
Thereafter	68		352		420
Total commitments	$	312	$	736	$	1,048
Accrued liabilities	$	24	$	40	$	64

Our midstream service commitments will be settled over approximately seven years.

Future minimum annual rentals under noncancelable operating leases as of December 31, 2018, are payable as follows:

	(Millions)
2019	$	38
2020	37
2021	12
2022	3
2023	—
Thereafter	—
Total	$	90

Total rent expense, excluding amounts capitalized, was $25 million, $19 million and $23 million in 2018, 2017 and 2016, 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 12. 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 equal to 8 percent of eligible pay if they are age 40 or

90

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $10 million, $11 million and $13 million for 2018, 2017 and 2016, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2018, and 2017 related to the non-matching annual employer contribution.

Note 13. Stock-Based Compensation

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 (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units and awards for purposes of this footnote). During 2018, the 2013 Incentive Plan was amended to authorize an additional 7.4 million shares for issuance under the plan. At December 31, 2018, 18 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 12 million shares were available for future grants. 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.

Total stock-based compensation expense was $32 million, $28 million and $31 million for of the years ended December 31, 2018, 2017 and 2016, respectively, and is reflected in general and administrative expense. Measured but unrecognized stock-based compensation expense related to restricted stock units and awards at December 31, 2018 was $40 million and is expected to be recognized over a weighted-average period of 2.6 years. There was no unrecognized stock-based compensation expense related to stock options at December 31, 2018.

The ESPP allows 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. During 2018, the ESPP was amended to replenish the number of shares of our common stock that may be issued under the ESPP by 750 thousand. Offering periods are from January through June and from July through December. Employees purchased 97 thousand shares at an average price of $10.74 per share during 2018.

Nonvested Restricted Stock Units and Awards

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2018.

Restricted Stock Units	Shares	Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2017	5.7	$	12.06
Granted	2.4	$	16.74
Forfeited	(0.1)	$	12.63
Vested	(2.6)	$	10.18
Nonvested at December 31, 2018	5.4	$	15.01

__________

(a) Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.

Other restricted stock unit information

	2018		2017		2016
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	16.74	$	13.76	$	10.99
Total fair value of restricted stock units vested during the year (millions)	$	26	$	33	$	37

Performance-based shares granted represent 36 percent of nonvested restricted stock units outstanding at December 31, 2018. 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.

91

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Based on the extent to which certain financial targets are achieved, vested shares may range from zero to 200 percent of the original grant amount.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2018.

Stock Options	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value
	(Millions)			(Years)	(Millions)
Outstanding at December 31, 2017	2.2	$	15.35		$	3
Granted	—	$	—
Exercised	(0.8)	$	12.35
Forfeited	(0.3)	$	20.19
Outstanding at December 31, 2018	1.1	$	16.00	2.2	$	0.3
Exercisable at December 31, 2018	1.1	$	16.00	2.2	$	0.3

The total intrinsic value of options exercised was $4.3 million, $224 thousand and $160 thousand for the years ended December 31, 2018, 2017 and 2016, respectively.

Cash received from stock option exercises was $9.2 million, $0.4 million and $0.4 million during 2018, 2017 and 2016, respectively.

The Company did not grant stock options during the years ended 2018, 2017 and 2016. 

Note 14. Stockholders’ Equity

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.

Series A Mandatory Convertible Preferred Stock

On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our Preferred Stock at $50 per share, for gross proceeds of approximately $350 million, before underwriting discounts and commissions. Dividends on our Preferred Stock were paid in cash on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018. 

On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our Preferred Stock, pursuant to which each of the Preferred Holders agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders agreed to convert an aggregate of approximately 2.2 million shares of Preferred Stock into approximately 10.2 million shares of our common stock in the Conversion, and we made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million in 2016. 

On July 30, 2018, all of the outstanding shares, approximately 4.8 million, of our preferred stock converted into approximately 19.8 million shares of our common stock pursuant to the mandatory conversion provisions of the preferred stock offering.

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

92

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2018, 2017 or 2016. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.

Subject to certain exceptions, so long as any share of our Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Preferred Stock.

On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

On January 12, 2017, we completed an underwritten public offering of 51.675 million shares of our common stock, which included 6.675 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $12.97 per share and we received proceeds of approximately $670 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. We used these proceeds, and cash on hand, to close the Panther Acquisition (see Note 2).

Note 15. 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, calls 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.

93

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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 approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

	December 31, 2018								December 31, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	175	$	3	$	178	$	—	$	59	$	—	$	59
Energy derivative liabilities	$	—	$	37	$	—	$	37	$	—	$	236	$	—	$	236
Total debt(a)	$	—	$	2,414	$	—	$	2,414	$	—	$	2,746	$	—	$	2,746

__________

(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,509 million and $2,600 million as of December 31, 2018 and 2017, respectively.

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

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

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

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

Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, calls or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil and natural gas swaps entered into, we granted swaptions and calls to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions and calls 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 extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling $3 million included in Level 3 as of December 31, 2018. There were no instruments included in Level 3 as of December 31, 2017.

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, Level 2 and Level 3 occurred during the years ended December 31, 2018 or 2017.

94

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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

Other

In addition to the items discussed below, we performed other nonrecurring fair value assessments as discussed in Note 2.

2017

In conjunction with the $103 million of gains from exchanges of leasehold during 2017, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs. The total fair value of leasehold exchanges in 2017 approximated $200 million. See Note 5 for additional discussion related to leasehold exchanges.

In addition, during the third quarter of 2017, we began a process to market our natural gas-producing properties in the San Juan Basin and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value which resulted in an impairment of $60 million recorded in the third-quarter of 2017. See Note 3 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin reported as discontinued operations.

Note 16. Derivatives and Concentration of Credit Risk

Energy Commodity Derivatives

Risk Management Activities

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of crude oil, natural gas and natural gas liquids attributable to commodity price risk.

We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaptions.

95

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Derivatives related to production

The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2018.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	2019	Fixed Price Swaps	WTI	(38,000)	$	53.49
Crude Oil	2019	Basis Swaps	Midland/Cushing	(21,008)	$	(1.16)
Crude Oil	2019	Basis Swaps	Nymex CMA Roll	(20,000)	$	0.11
Crude Oil	2019	Basis Swaps	Magellan East Houston/Midland	(1,841)	$	8.12
Crude Oil	2019	Basis Swaps	Argus LLS/Midland	(838)	$	8.60
Crude Oil	2019	Fixed Price Calls	WTI	(5,000)	$	54.08
Crude Oil	2020	Basis Swaps	Midland/Cushing	(7,486)	$	(1.31)
Crude Oil	2020	Basis Swaps	Brent/WTI Spread	(5,000)	$	8.36
Crude Oil	2021	Basis Swaps	Brent/WTI Spread	(1,000)	$	8.00
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75
Natural Gas
Natural Gas	2019	Fixed Price Swaps	Henry Hub	(108)	$	3.07
Natural Gas	2019	Basis Swaps	Permian	(25)	$	(0.39)
Natural Gas	2019	Basis Swaps	Waha	(15)	$	2.94
Natural Gas	2019	Basis Swaps	Houston Ship Channel	(30)	$	(0.09)
Natural Gas	2020	Basis Swaps	Waha	(60)	$	(0.79)
Natural Gas	2021	Basis Swaps	Waha	(70)	$	(0.59)
Natural Gas	2022	Basis Swaps	Waha	(70)	$	(0.57)
Natural Gas	2023	Basis Swaps	Waha	(70)	$	(0.51)

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread.

(b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.

(c) The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.

96

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Fair values and gains (losses)

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, our derivatives do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Gain (loss) from derivatives related to production(a)	$	78	$	3	$	(207)
Gain (loss) from derivatives related to physical marketing agreements(b)	3		—		—
Net gain (loss) on derivatives	$	81	$	3	$	(207)

__________

(a) Includes payments totaling $237 million for the year ended December 31, 2018 and settlements totaling $4 million and $301 million for the years ended December 31, 2017 and 2016, respectively.

(b) Includes payments totaling less than $1 million for the years ended December 31, 2018 and 2017 and settlements totaling  $1 million for the year ended December 31, 2016.

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

Offsetting of derivative assets and liabilities

The following table presents our gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet		Netting Adjustments (a)		Net Amount
December 31, 2018	(Millions)
Derivative assets with right of offset or master netting agreements	$	178	$	(37)	$	141
Derivative liabilities with right of offset or master netting agreements	$	(37)	$	37	$	—
December 31, 2017
Derivative assets with right of offset or master netting agreements	$	59	$	(42)	$	17
Derivative liabilities with right of offset or master netting agreements	$	(236)	$	42	$	(194)

__________

(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional

97

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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, 2018, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net less than $1 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. As of December 31, 2017, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $194 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $4 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 and $194 million at December 31, 2018 and 2017, respectively.

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 dates indicated below. 

	December 31,
	2018		2017
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	269	$	251
Joint interest owners	98		54
Income tax receivable	38		—
Other	—		2
Total	$	405	$	307

Oil and natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the southwestern United States 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 creditworthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2018, 2017 and 2016, 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.

98

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Our gross and net credit exposure from our derivative contracts were $178 million and $141 million, respectively, as of December 31, 2018. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We consider counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.

Our six largest net counterparty positions represent approximately 91 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

Other

At December 31, 2018, we held collateral support of $10 million, either in the form of cash, letters of credit or surety bond, related to our commodity management agreements.

Collateral support for our commodity agreements could include margin deposits, letters of credit, and guarantees of payment by credit worthy parties.

Revenues

The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. 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.

	Year ended December 31,
	2018	2017	2016
United Energy Trading LLC	23%	(a)	(a)
Occidental Energy Marketing	16%	(a)	(a)
Crestwood Midstream Partners LP	(a)	21%	(a)
St. Paul Refining	(a)	16%	13%
NGL Crude Logistics	14%	13%	(a)
Delek Refining, Ltd	(a)	10%	(a)
Plains Marketing	(a)	(a)	15%

__________

(a) Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives.

One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course

of business, we sell crude oil to NGL Energy. For the year ended 2018, sales to NGL Energy were approximately 14 percent of our total consolidated revenues adjusted for gain (loss) on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 1 percent of operating expenses.

99

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 17. Subsequent Events

We have signed agreements to divest certain holdings for aggregate proceeds in excess of $200 million. The agreements consist of separate sales transactions for our 20 percent equity interest in the Whitewater natural gas pipeline which we expect to close in first-quarter 2019 and roughly 5,600 net acres in the Delaware Basin which has closed in 2019. We have also closed on a $100 million purchase of 14,000 surface acres within our Stateline operations, which we expect will provide economic benefit through speed of development, facilitation of longer laterals, right of way access and revenue associated with infrastructure like roads, water and electricity.

100

WPX Energy, Inc.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2018	(Millions, except per-share amounts)
Product revenues	$	407	$	520	$	554	$	544
Net gain (loss) on derivatives	$	(69)	$	(154)	$	(139)	$	443
Commodity management	$	36	$	64	$	68	$	36
Total revenues	$	374	$	430	$	484	$	1,022
Operating costs and expenses	$	322	$	388	$	413	$	447
Operating income	$	52	$	42	$	71	$	575
Income (loss) from continuing operations	$	(26)	$	(79)	$	(6)	$	353
Loss from discontinued operations	(89)		(2)		(1)		1
Net income (loss)	$	(115)	$	(81)	$	(7)	$	354
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	(30)	$	(83)	$	(6)	$	353
Loss from discontinued operations	(89)		(2)		(1)		1
Net income (loss)	$	(119)	$	(85)	$	(7)	$	354
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.07)	$	(0.21)	$	(0.01)	$	0.84
Loss from discontinued operations	(0.23)		—		—		—
Net income (loss)	$	(0.30)	$	(0.21)	$	(0.01)	$	0.84
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.07)	$	(0.21)	$	(0.01)	$	0.83
Loss from discontinued operations	(0.23)		—		—		—
Net income (loss)	$	(0.30)	$	(0.21)	$	(0.01)	$	0.83
2017
Product revenues	$	187	$	226	$	247	$	356
Net gain (loss) on derivatives	$	203	$	116	$	(106)	$	(210)
Commodity management	$	5	$	8	$	4	$	8
Total revenues	$	395	$	350	$	145	$	155
Operating costs and expenses	$	208	$	231	$	223	$	265
Operating income (loss)	$	187	$	119	$	(78)	$	(110)
Income (loss) from continuing operations	$	95	$	327	$	(378)	$	(20)
Income (loss) from discontinued operations	(3)		(251)		232		(18)
Net income (loss)	$	92	$	76	$	(146)	$	(38)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	91	$	323	$	(381)	$	(24)
Income (loss) from discontinued operations	(3)		(251)		232		(18)
Net income (loss)	$	88	$	72	$	(149)	$	(42)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.24	$	0.81	$	(0.96)	$	(0.06)
Income (loss) from discontinued operations	(0.01)		(0.63)		0.58		(0.04)
Net income (loss)	$	0.23	$	0.18	$	(0.38)	$	(0.10)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.23	$	0.77	$	(0.96)	$	(0.06)
Income (loss) from discontinued operations	(0.01)		(0.60)		0.58		(0.04)
Net income (loss)	$	0.22	$	0.17	$	(0.38)	$	(0.10)

101

Net income or loss for each respective quarter include the following pre-tax items:

First-quarter 2018:

•$138 million loss included in discontinued operations for the sale of the San Juan Gallup and $9 million performance guarantee related to gathering and processing commitments (see Note 3).

Second-quarter 2018:

•$71 million loss on extinguishment of debt (see Note 9).

First-quarter 2017:

•$31 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5).

•$23 million loss on write-off of expired leases in the Permian Basin (see Note 5).

Third-quarter 2017:

•$111 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5).

•$60 million impairment on San Juan Legacy included in discontinued operations (see Note 3).

•$17 million loss on extinguishment of debt (see Note 9).

•$10 million severance tax refunds for prior years related to the Piceance Basin (see Note 3).

Fourth-quarter 2017:

•$11 million gain on leasehold exchanges (see Note 5).

•$5 million increase on future commitments under gathering, processing and transportation liability related to the Powder River Basin in discontinued operations (see Note 3).

•$92 million income tax benefit related to the impact of new income tax legislation (see Note 10).

102

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(Unaudited)

We have significant continuing oil and gas producing activities primarily in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota, all of which are located in the United States.

With the exception of Capitalized Costs, the following information includes activity through the completion of the respective asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan and Piceance Basins, both of which have been reported as discontinued operations in our consolidated financial statements. The San Juan Basin properties were sold in March 2018 and December 2017. The Piceance Basin properties were sold in April 2016. Capitalized Costs do not include amounts which are classified as assets held for sale on the Consolidated Balance Sheets.

Capitalized Costs

	As of December 31,
	2018		2017
	(Millions)
Proved Properties	$	7,612	$	6,113
Unproved properties	1,891		2,194
	9,503		8,307
Accumulated depreciation, depletion and amortization and valuation provisions	(2,542)		(1,860)
Net capitalized costs	$	6,961	$	6,447

__________

•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $276 million and $223 million, net, as of December 31, 2018 and 2017, 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,
	2018		2017		2016
	(Millions)
Acquisition	$	68	$	864	$	84
Exploration	7		5		5
Development	1,350		1,048		471
	$	1,425	$	1,917	$	560

__________

•Costs incurred include capitalized and expensed items.

•Acquisition costs are as follows: Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) in March 2017 that included $195 million and 23.8 MMboe of proved developed reserves and facilities. Costs in 2016 primarily relates to purchases of additional acreage in the Delaware Basin and included approximately 2.5 MMboe of proved reserves.

•Exploration costs include 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. Development costs associated with our San Juan Basin and Piceance Basin operations were $24 million, $168 million and $102 million for 2018, 2017 and 2016, respectively.

103

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(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 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.

104

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(Unaudited)

The following is a summary of changes in our proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations.

	Oil (MMbbls)	Natural Gas (Bcf)	NGLs (MMbbls)	All Products (MMboe)
Proved reserves at December 31, 2015	142.7	2,190.2	75.3	583.0
Revisions	(3.8)	(50.2)	(2.9)	(15.2)
Purchases	1.6	4.4	0.4	2.8
Divestitures	(5.5)	(1,505.9)	(38.3)	(294.8)
Extensions and discoveries	54.9	214.6	19.8	110.5
Production	(15.3)	(118.6)	(4.8)	(39.9)
Proved reserves at December 31, 2016	174.6	734.5	49.5	346.4
Revisions	4.7	(8.4)	(1.1)	2.3
Purchases	21.8	58.8	7.8	39.4
Divestitures	(1.7)	(312.5)	(0.8)	(54.6)
Extensions and discoveries	86.7	194.5	23.6	142.7
Production	(22.4)	(75.9)	(5.0)	(40.0)
Proved reserves at December 31, 2017	263.7	591.0	74.0	436.2
Revisions	—	(11.4)	5.3	3.4
Purchases	1.5	4.8	0.6	2.9
Divestitures	(27.6)	(79.8)	(10.4)	(51.3)
Extensions and discoveries	84.5	176.9	22.7	136.7
Production	(30.8)	(63.8)	(7.2)	(48.6)
Proved reserves at December 31, 2018	291.3	617.7	85.0	479.3
Proved developed reserves:
December 31, 2016	84.4	440.2	24.1	181.8
December 31, 2017	130.3	321.2	38.8	222.7
December 31, 2018	156.4	365.4	48.4	265.8
Proved undeveloped reserves:
December 31, 2016	90.2	294.2	25.4	164.6
December 31, 2017	133.4	269.8	35.2	213.5
December 31, 2018	134.9	252.3	36.6	213.5

__________

•Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.

•Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells. Revisions in 2016 primarily reflect 49 MMboe of negative revisions due to the decrease in the 12-month average price partially offset by 34 MMboe of positive revisions due to decreased costs and well improvements.

•Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed.

•Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves. Divestitures in 2016 relate to the sale of the Piceance Basin which included proved developed reserves and proved undeveloped reserves of 222 MMboe and 67 MMboe, respectively.

•Extensions and discoveries in 2018 reflect 52 MMboe added for proved developed locations and 85 MMboe of proved undeveloped locations. Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins. Extensions and discoveries in 2016 reflect 26 MMboe added for proved developed locations and 84 MMboe for proved undeveloped locations primarily in the Delaware Basin.

105

WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(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 were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. The average domestic oil price used in the estimates for the years ended December 31, 2018, 2017 and 2016 was $61.57, $46.39 and $35.91 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2018, 2017 and 2016 was $1.21, $1.67 and $1.74 per Mcf, respectively. The average NGL price per barrel was $26.76, $21.16 and $10.57 for the same periods. Future income tax expenses have been computed considering applicable taxable cash flows, including historical tax basis and carry forwards (i.e. future deductions for taxable income calculations), and appropriate statutory tax rates. The discount rate of 10 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,
	2018		2017
	(Millions)
Future cash inflows	$	20,963	$	14,785
Less:
Future production costs	7,615		6,112
Future development costs	2,345		2,070
Future income tax provisions	1,366		408
Future net cash flows	9,637		6,195
Less 10 percent annual discount for estimated timing of cash flows	4,446		3,034
Standardized measure of discounted future net cash inflows	$	5,191	$	3,161

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

	For the years ended December 31,
	2018		2017		2016
	(Millions)
Beginning of year	$	3,161	$	1,038	$	1,284
Sales of oil and gas produced, net of operating costs	(1,541)		(894)		(458)
Net change in prices and production costs	2,004		1,385		(261)
Extensions, discoveries and improved recovery, less estimated future costs	1,341		816		735
Development costs incurred during year	654		345		142
Changes in estimated future development costs	(35)		105		(211)
Purchase of reserves in place, less estimated future costs	27		305		20
Sale of reserves in place, less estimated future costs	(409)		20		(253)
Revisions of previous quantity estimates	75		30		(78)
Accretion of discount	324		104		136
Net change in income taxes	(396)		(83)		—
Other	(14)		(10)		(18)
Net changes	2,030		2,123		(246)
End of year	$	5,191	$	3,161	$	1,038

106

WPX Energy, Inc.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

	Beginning Balance		Charged (Credited) to Costs and Expenses		Other		Deductions		Ending Balance
2018:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	2	$	—	$	—	$	(2)	$	—
Deferred tax asset valuation(b)	195		18		—		—		213
Price-risk management credit reserves—liabilities(c)(d)	4		—		(4)		—		—
2017:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	3	$	—	$	—	$	(1)	$	2
Deferred tax asset valuation(b)(e)	151		44		—		—		195
Price-risk management credit reserves—liabilities(c)(d)	5		—		(1)		—		4
2016:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	6	$	—	$	—	$	(3)	$	3
Deferred tax asset valuation(b)	124		26		1		—		151
Price-risk management credit reserves—assets(a)(d)	1		—		(1)		—		—
Price-risk management credit reserves—liabilities(c)(d)	—		—		5		—		5

 __________

(a) Deducted from related assets.

(b) Deducted from related assets with a portion included in assets held for sale.

(c) Deducted from related liabilities.

(d) Included in revenues.

(e) Includes impact of the Tax Cuts and Jobs Act enacted rate reduction.

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.

107

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 2018 Changes in Internal Controls

There have been no changes during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

Item 9B. Other Information

None.

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 2019 Annual meeting of Stockholders, or our 2019 Proxy Statement, anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, under the heading “Independent Registered Public Accounting Firm.”

108

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 as of December 31, 2018 and 2017	65
Consolidated Statements of Operations for each year in the three-year period ended December 31, 2018	66
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2018	68
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2018	69
Notes to consolidated financial statements	70
Schedule for each year in the three-year period ended December 31, 2018:
II — Valuation and qualifying accounts	107
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)	101
Supplemental oil and gas disclosures (unaudited)	103

(a) 3 and (b). The exhibits listed below are filed as part of this annual report.

109

INDEX TO EXHIBITS

Exhibit No.	Description
2.1**	Agreement and Plan of Merger, dated as of July 13, 2015, by and among RKI Exploration & Production, LLC, WPX Energy, Inc. and Thunder Merger Sub LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
2.2**	Membership Interest Purchase Agreement by and Among WPX Energy Holdings, LLC, as Seller, WPX Energy, Inc., solely for purposes of Section 14.15, and Terra Energy Partners LLC, as Purchaser, dated February 8, 2016 (incorporated by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2016)
2.3**	Purchase and Sale Agreement, dated as of January 12, 2017, by and among RKI Exploration & Production, LLC, Panther Energy Company II, LLC and CP2 Operating, LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 13, 2017)
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	Certificate of Amendment of Amended and Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
3.3	Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 21, 2014)
3.4	Certificate of Designations for 6.25% Series A Mandatory Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
4.1	Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)
4.2	Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.3	First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.4	Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
10.1	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)
10.2	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K (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	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)
10.5	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)
10.6	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)
10.7	Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)

110

Exhibit No.	Description
10.8	Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.14 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.9	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015)(1)
10.10	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 Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)(1)
10.11	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)
10.12	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)
10.13	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)
10.14	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)
10.15	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)
10.16	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)
10.17	Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.18	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)
10.19	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)
10.20	Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)
10.21	First Amendment to the Amended and Restated Credit Agreement, dated as of July 16, 2015, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as existing Administrative Agent and existing Swingline Lender, and Wells Fargo Bank, National Association, as successor Administrative Agent and successor Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
10.22	Commitment Increase Agreement for Amended and Restated Credit Agreement, dated as of July 31, 2015, among WPX Energy, Inc., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, and the Issuing Banks thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on August 6, 2015)
10.23	Second Amendment to the Amended and Restated Credit Agreement, dated as of March 18, 2016, by and among WPX Energy, Inc., as the borrower thereunder, the financial institutions party thereto from time to time, as lenders, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 22, 2016)

111

Exhibit No.	Description
10.24	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
10.25	Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and CEO (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 16, 2016) (1)
10.26	Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 16, 2016) (1)
10.27	Amended and Restated 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 May 23, 2017) (1)
10.28	Purchase and Sale Agreement by and Among WPX Energy Production, LLC and Enduring Resources IV, LLC dated January 30, 2018 (incorporated by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 5, 2018)
10.29	WPX Energy, Inc. 2013 Incentive Plan, as amended (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
10.30	Form of Amended and Restated Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
10.31	Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
10.32	Amendment No. 3 to the WPX Energy, Inc. 2013 Incentive Plan (incorporated by reference to Appendix A to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A (File No. 001-35322) filed with the SEC on March 29, 2018)
10.33	Second Amendment to the Second Amended and Restated Credit Agreement and First Amendment to Guaranty and Collateral Agreement dated April 17, 2018, by and among the Company and certain of its wholly-owned subsidiaries signatory thereto, Wells Fargo Bank, National Association, as lender, Swingline Lender and Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on April 20, 2018)
10.34	Form of Amendment to Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.40 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)(1)
10.35*	Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (1)
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 – the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase

112

Exhibit No.	Description
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

* Filed herewith

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

(1) Management contract or compensatory plan or arrangement

113

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 21, 2019 

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	Chief Executive Officer and Chairman of the Board (Principal Executive Officer)	February 21, 2019
/s/ J. Kevin Vann	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 21, 2019
/s/ Stephen L. Faulkner	Controller (Principal Accounting Officer)	February 21, 2019
/s/ John A. Carrig*	Director	February 21, 2019
/s/ Robert K. Herdman*	Director	February 21, 2019
/s/ Kelt Kindick*	Director	February 21, 2019
/s/ Karl F. Kurz*	Director	February 21, 2019
/s/ Henry E. Lentz*	Director	February 21, 2019
/s/ William G. Lowrie*	Director	February 21, 2019
/s/ Kimberly S. Lubel*	Director	February 21, 2019
/s/ Valerie M. Williams*	Director	February 21, 2019
/s/ David F. Work*	Director	February 21, 2019

	/s/ Stephen E. Brilz
*By:	Attorney-in-Fact	February 21, 2019

114

EX-10.35

Exhibit 10.35

[Grant Date]

TO: [Participant Name]

FROM: Richard E. Muncrief

SUBJECT: 2019 Performance-Based Restricted Stock Unit Award

You have been selected to receive a performance-based restricted stock unit award to be paid if the Company exceeds the goal for Total Shareholder Return, as established by the Committee, over the Performance Period. This award, which is subject to adjustment under the 2019 Performance-Based 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. The number of shares earned at the end of the Performance Period may vary from the number of shares granted, based upon WPX’s performance over the thirty-six-month Performance Period. This award 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. You must accept the terms and conditions of the restricted stock unit award and the Agreement within 90 days of grant date. Failure to accept the award within 90 days of the grant date will result cancellation of the award.

Subject to all of the terms of the Agreement, you will become entitled to payment of the award if you are an active employee of the Company on March 2, 2022, and performance measures are certified for the Performance Period beginning January 1, 2019, and ending on December 31, 2021. 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.

2019 PERFORMANCE-BASED RESTRICTED STOCK UNIT AGREEMENT

THIS 2019 PERFORMANCE-BASED 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 2019 Performance-Based Restricted Stock Unit Award Letter delivered in hard copy or electronically to the 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 to the Participant a target award (the “Award”) of [Number of Awards Granted] RSUs effective [Grant Date] (the “Effective Date”). The Award, which is subject to adjustment under the terms of this Agreement and the Plan, gives the Participant the opportunity to earn the right to receive the number ofshares of Common Stock of the Company equal to the number of RSUs shown in the prior sentence if the Target Peer Group Ranking, as established by the Committee and described in Subparagraph 4(b) below, is achieved by the Company over the Performance Period (as defined in Subparagraph 5(b)(ii) below). These shares, together with any other shares that are payable under this Agreement, are referred to in this Agreement as the “Shares.” Until the Participant both becomes vested in the Shares under the terms of Paragraph 5 and is paid such Shares under the terms of Paragraph 6, 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 A 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 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; Committee Discretion. 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. Performance Measures; Number of Shares Payable to the Participant.

(a) Performance measures established by the Committee shall be based on targeted levels of relative Total Shareholder Return (“TSR”), as defined by the Committee. The Committee has established a designated percentage of the Target Number of Shares (as defined in Subparagraph 4(b) below) that may be received by the Participant based on the Company’s relative TSR for the Performance Period within the peer group established by the Committee, all as more fully described in Subparagraphs 4(b) and 4(c) below and in

2

Appendix B, and in all respects subject to the Committee’s discretion as described in Subparagraph 4(d) below.

(b) The RSUs awarded to the Participant and subject to this Agreement as reflected in Paragraph 1 above represent the Participant’s opportunity to earn the right to payment of an equal number of Shares (“Target Number of Shares”) upon (i) certification by the Committee that the Company has achieved the “Target Peer Group Ranking,” as specified in Appendix B, for TSR for the Performance Period, and (ii) satisfaction of all the other conditions set forth in Paragraph 5 below.

(c) Subject to the Committee’s discretion as set forth in Subparagraph 4(d) below and to the satisfaction of all other conditions set forth in Paragraph 5 below, the actual number of Shares earned by and payable to the Participant upon certification of TSR results and satisfaction of all other conditions set forth in Paragraph 5 below will be based upon the range set by the Committee from 30% (for relative TSR above the 25th percentile of the peer group established by the Committee) to 200% (for relative TSR at the first or second ranking within the peer group established by the Committee) of the Target Number of Shares depending on the level of relative TSR certified by the Committee at the end of the Performance Period, as set forth in Appendix B. Nothing in Appendix B or otherwise shall be construed to limit the Committee’s discretion to determine the number of Shares, if any, that are earned and payable under this Agreement.

(d) Notwithstanding (i) any other provision of this Agreement or the Plan or (ii) certification by the Committee that targets for TSR have been achieved during the Performance Period, the Committee may in its sole and absolute discretion reduce, but not below zero (0), the number of Shares payable to the Participant based on such factors as it deems appropriate, including but not limited to, the Company’s performance. Accordingly, any reference in this Agreement to Shares that (i) become payable, (ii) may be received by the Participant, or (iii) are earned by the Participant, and any similar reference, shall be understood to mean the number of Shares that are received, payable, or earned after any such reduction is made.

5. 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 such Participant obtains a legally binding right to such Shares and satisfies applicable vesting conditions for such payment.

(b) Except as otherwise provided in Subparagraphs 5(c) – 5(f) below and subject to the provisions of Subparagraph 4(d) above, the Participant shall vest in Shares under this Agreement only if and at the time that both of the following conditions are fully satisfied:

(i) The Participant remains an active employee of the Company or any of its Affiliates from the Effective Date through March 2, 2022, (the “Maturity Date”); and

3

(ii) The Committee certifies that the Company has met TSR targets as defined by the Committee for the thirty-six-month performance period beginning January 1, 2019, and ending December 31, 2021 (the “Performance Period”). Certification, if any, by the Committee for the Performance Period shall be made by the Maturity Date or as soon thereafter as is administratively practicable.

(c) (i) If the Participant dies, becomes Disabled, or qualifies for Retirement (as defined in Subparagraph 5(c)(iii) below) prior to the Maturity Date while an active employee of the Company or any of its Affiliates, at but not prior to the Maturity Date, and only to the extent and at the time that the Committee certifies that the performance measures for the Performance Period are satisfied under Subparagraph 5(b)(ii) above, upon such certification, the Participant shall vest in that number of Shares the Participant might otherwise have received for the Performance Period in accordance with Paragraph 4 above prorated in accordance with Subparagraph 5(c)(ii) to reflect that portion of the Performance Period prior to such Participant’s ceasing being an active employee of the Company and its Affiliates.

(ii) The pro rata number of Shares in which the Participant may become vested pursuant to Subparagraph 5(c)(i) shall equal that number determined by multiplying the number of Shares the Participant might otherwise have received for the Performance Period in accordance with Paragraph 4 above times a fraction, the numerator of which is the number of full and partial months in the period that begins the month following the month that contains the Effective Date and ends on (and includes) the date that the Participant ceases being an active employee of the Company and its Affiliates, and the denominator of which is thirty-six(36).

(iii) The Participant “qualifies for Retirement” only if the Participant experiences a Separation from Service and has attained age 55 and completed at least five years of continuous service with the Company or any of its Affiliates.

(d) (i) If the Participant experiences a Separation from Service prior to the Maturity Date 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 a number of Shares calculated based on the Company’s actual performance as of the date of the Change in Control, determined according to the provisions of this Section 5(d).

(ii) For purposes of this Subparagraph 5(d), actual performance shall be determined based on the Company’s relative TSR within the peer group established by the Committee at the time of grant for a performance period beginning on January 1, 2019 and ending on the date immediately preceding the Change in Control (the “CIC Performance Period”). The number of Shares earned and payable to the Participant will be based upon the range set by the Committee from 30% (for relative TSR above the 25th percentile of the peer group established by the Committee) to 200% (for relative TSR at the first or second ranking within the peer group established by the Committee) of the Target Number of Shares depending on the level of relative TSR on the date immediately preceding the Change in Control, as set forth in Appendix B.

4

(iii) For purposes of this Subparagraph 5(d) only, the Committee will not have the discretion to reduce the number of Shares payable to the Participant under Subparagraph 4(d) above.

(e) If the Participant experiences an involuntary Separation from Service prior to the 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, then at the time and to the extent the Committee certifies that the performance measures for the Performance Period are satisfied under Subparagraph 5(b)(ii) above, the Participant shall, on the date of such certification, become vested in that number of Shares the Participant might otherwise have received for the Performance Period in accordance with Paragraph 4 above prorated to reflect that portion of the Performance Period prior to the Participant’s ceasing being an active employee of the Company and its Affiliates. The pro rata number of Shares in which the Participant may become vested on, but not prior to, the Maturity Date in such case shall equal that number determined by multiplying (i) the number of Shares the Participant might otherwise have received for the Performance Period in accordance with Paragraph 4 above times (ii) a fraction, the numerator of which is the number of full and partial months in the period that begins the month following the month that includes the Effective Date and ends on (and includes) the date the Participant ceases being an active employee of the Company and its Affiliates, and the denominator of which is the total number of full and partial months in the period that begins the month following the month that contains the Effective Date and ends on (and includes) the Maturity Date.

(f) If (i) the Participant experiences an involuntary Separation from Service prior to the Maturity Date due to a sale of a business or the outsourcing of any portion of a business, and (ii) the Company or any of its Affiliates fails to make an offer of comparable employment, as defined in a severance plan or program maintained by the Company or any of its Affiliates, to the Participant, then at the time and to the extent the Committee certifies that the performance measures for the Performance Period are satisfied under Subparagraph 5(b)(ii) above, upon such certification, the Participant shall, on the date of such certification, become vested in that number of Shares the Participant might otherwise have received for the Performance Period in accordance with Paragraph 4 above prorated to reflect that portion of the Performance Period prior to the Participant’s ceasing being an active employee of the Company and its Affiliates. The pro rata number of Shares in which the Participant may become vested on, but not prior to, the Maturity Date in such case shall equal that number of Shares determined by multiplying (i) the number of Shares the Participant might otherwise have received for the Performance Period in accordance with Paragraph 4 above times (ii) a fraction, the numerator of which is the number of full and partial months in the period that begins the month following the month that contains the Effective Date and ends on (and includes) the date the Participant ceases being an active employee of the Company and its Affiliates, and the denominator of which is the total number of full and partial months in the period that begins the month following the month that contains the Effective Date and ends on (and includes) the Maturity Date.

5

For purposes of this Subparagraph 5(f), 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. Payment of Shares.

(a) Payment of all Shares in which the Participant becomes vested pursuant to Subparagraph 5(d) above shall occur within 30 days after the Participant’s Separation from Service.

(b) Payment of all Shares in which the Participant becomes vested pursuant to Paragraph 5 above, other than Subparagraph 5(d) (as to which the payment date is determined in accordance with Subparagraph 6(a) above), shall occur during the calendar year containing the Maturity Date.

(c) 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, 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 necessary for purposes of satisfying all of the Company’s or any Affiliate’s federal, state and local tax withholding requirements related thereto (the “Required Withholding”). The number of Shares included in the Required Withholding shall be determined in a manner consistent with the Plan and all such Shares shall be valued at their Fair Market Value on the date the withholding tax obligation arises.

7. 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 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 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.

(c) Except as provided in Subparagraphs 5(c) through 5(f) above, in the event that the Participant experiences a Separation from Service prior to the Maturity Date, RSUs subject to this Agreement and any right to Shares issuable hereunder shall be forfeited.

(d) 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

6

both (i) the Participant’s becoming vested in such Shares and (ii) payment of such Shares under this Agreement.

(e) 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 thereunder shall terminate upon forfeiture without payment of consideration.

(f) In consideration of the grant of RSUs described in Section 1 above, during the term of employment, and for a period of one (1) year immediately thereafter, the Participant agrees not to, directly or indirectly, solicit, recruit, induce, or attempt to recruit, solicit, or induce any employee or independent contractor of the Company on the Participant’s behalf or on behalf of or in conjunction with any person or legal entity to work for or contract with such an entity. Furthermore, other than in performance of assigned duties for the Company, the Participant agrees not to induce, directly or indirectly, any employee or independent contractor associated with the Company to terminate or breach an employment, contractual, or other relationship with the Company.

(g) The Committee shall determine whether an event has occurred resulting in the forfeiture of the RSUs and any Shares issuable thereunder 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 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 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. The 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 becomes a party to this Agreement by accepting the Award electronically or in writing, in accordance with procedures of the Committee, its delegates, or agents, within 90 days of grant date. Failure to accept the award within 90 days of the grant date will result cancellation of the award.

7

(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.

(n) Notwithstanding any other provision of this Agreement to the contrary, any Shares issued hereunder and/or any amount received with respect to any sale of any such Shares, shall be subject to potential cancellation, recoupment, rescission, payback, or other action in accordance with regulations promulgated by the Securities Exchange Commission, with stock exchange rules, and with the terms of the Company’s Recoupment Policy, as it may be amended from time to time (collectively, the “Recoupment Requirements”). The Participant agrees and consents to the Company’s application, implementation and enforcement of (a) the Recoupment Requirements or any similar policy established by the Company that may apply to the Participant and (b) any provision of applicable law relating to cancellation, rescission, payback, or recoupment of compensation, and expressly agrees that the Company may take such actions as are necessary to effectuate the Recoupment Requirements, any similar policy (as applicable to the Participant), or applicable law without further consent or action being required by the Participant. To the extent that the terms of this Agreement and the Recoupment Requirements or any similar policy conflict, then the terms of such Recoupment Requirements shall prevail.

8. 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.

9. 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

Chairman and CEO

Participant: [Participant Name]

8

APPDENDIX A

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 5(c)(i) 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.

9

APPENDIX B

DETERMINATION OF TSR RANKING

As of the Effective Date, the Committee has established a peer group of companies for the purpose of determining the Company’s relative TSR ranking for the Performance Period or the CIC period. The Committee retains the authority to determine the treatment of any company in the peer group that ceases to be a United States-domiciled publicly traded company on a national stock exchange or market system and to adjust the table below accordingly.

The table below reflects the Shares, expressed as a percentage of the Target Number of Shares, that may be payable to the Participant based upon the Company’s TSR ranking within the peer group for the Performance Period. Notwithstanding any provision in this Appendix B or in the Agreement to the contrary, other than Subparagraph 5(d), the Committee has the sole and absolute discretion to reduce the number of Shares payable to the Participant to zero (0) pursuant to Subparagraph 4(d) of the Agreement.

Company TSR Ranking Within the Peer Group	Percentage of the Target Number of Shares
1st	200%
2nd	200%
3rd	191.6%
4th	183.3%
5th	175%
6th	150%
7th	125%
Target Peer Group Ranking 8th	100%
9th	82.5%
10th	65%
11th	47.5%
12th	30%
13th	0%
14th	0%
15th	0%
16th	0%

10

EX-21.1

Exhibit 21.1

List of Subsidiaries of WPX Energy, Inc.

(all Delaware entities unless otherwise indicated)

1	Cardinal Oil and Gas Holdings, LLC
	DBA in New Mexico and Texas as: Cardinal Exploration & Production, LLC
2	Catalyst Midstream Partners, LLC
3	Delaware Basin Residue, LLC
4	Oryx Delaware Holdings, LLC
5	Stateline Crude, LLC - an Oklahoma LLC
6	Stateline Gathering, LLC - an Oklahoma LLC
7	Stateline Processing, LLC - an Oklahoma LLC
8	Stateline Storage, LLC
9	Stateline Water, LLC - an Oklahoma LLC
10	WPX Energy Gulf Coast, LP
11	WPX Energy Holdings, LLC
12	WPX Energy Keystone, LLC
13	WPX Energy Marketing, LLC
14	WPX Energy Mid-Continent Company, an Oklahoma corporation
15	WPX Energy Permian, LLC
16	WPX Energy Production, LLC
17	WPX Energy Services Company, LLC
18	WPX Energy Williston, LLC (Trade name in North Dakota: D3 E & P LLC)
19	WPX Energy Williston Nomination A, LLC
20	WPX Energy Williston Nomination B, LLC
21	WPX Energy Williston Nomination C, LLC
22	WPX Energy Williston Nomination D, LLC
23	WPX Energy Williston Nomination E, LLC
24	WPX Energy Williston Nomination F, LLC
25	WPX Energy Williston Nomination G, LLC
26	WPX Energy Williston Nomination H, LLC
27	WPX Energy Williston Nomination I, LLC
28	WPX Energy Williston Nomination J, LLC
29	WPX Energy Williston Nomination K, LLC
30	WPX Energy Williston Nomination L, LLC
31	WPX Energy Williston Nomination M, LLC
32	WPX Energy Williston Nomination N, LLC
33	WPX Energy Williston Nomination O, LLC
34	WPX Energy Williston Nomination P, LLC
35	WPX Energy Williston Nomination Q, LLC
36	WPX Energy Williston Nomination R, LLC
37	WPX Energy Williston Nomination S, LLC
38	WPX Energy Williston Nomination T, LLC
39	WPX Permian Midstream Crude Holdings, LLC
40	WPX Permian Midstream Holdings, LLC
41	WPX Permian Midstream Residue Holdings, 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 333-208552) of WPX Energy, Inc.,

(2)Registration Statement (Form S-8 No 333-225143) pertaining to the WPX Energy, Inc. 2013 Incentive Plan, as amended effective May 23, 2018,

(3)Registration Statement (Form S-3 No 333-221301) of WPX Energy, Inc.,

(4)Registration Statement (Form S-3 No 333-197905) of WPX Energy, Inc.,

(5)Registration Statement (Form S-8 No 333-188767) pertaining to the WPX Energy, Inc. 2013 Incentive Plan,

(6)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,

(7)Registration Statement (Form S-8 No 333-225141) pertaining to the WPX Energy, Inc. 2011 Employee Stock Purchase Plan, as amended effective May 23, 2018, and

(8)Registration Statement (Form S-8 No 333-204355) pertaining to the WPX Energy, Inc. 2013 Incentive Plan, as amended effective May 21, 2015;

of our reports dated February 21, 2019 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, 2018.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 21, 2019

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, 2018, included in or made part of the Annual Report on Form 10-K of WPX Energy, Inc. for the year ended December 31, 2018. 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, 2018, and references thereto, into WPX Energy, Inc.'s Registration Statements on Form S-8 (Nos. 333-204355,333-178388, 333-188767, 333-225143, and 333-225141 and Post-Effective Amendment No. 1 to Registration Statement No. 333-178388 on Form S-8) and Form S‑3 (Nos. 333-208552, 333-197905, and 333-221301).

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 21, 2019

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, 2018, 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 21^st day of February, 2019.

/s/ John A. Carrig	/s/ Robert K. Herdman
John A. Carrig	Robert K. Herdman
/s/ Kelt Kindick	/s/ Karl F. Kurz
Kelt Kindick	Karl F. Kurz
/s/ Henry E. Lentz	/s/ William G. Lowrie
Henry E. Lentz	William G. Lowrie
/s/ Kimberly S. Lubel	/s/ Valerie M. Williams
Kimberly S. Lubel	Valerie M. Williams
/s/ David F. Work
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 21, 2019

/s/ Richard E. Muncrief

Richard E. Muncrief

Chief Executive Officer

(Principal Executive Officer)

EX-31.2

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

1. 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 21, 2019

/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, 2018, 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 21, 2019

/s/ J. Kevin Vann

J. Kevin Vann

Executive Vice President and Chief Financial Officer

February 21, 2019

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 19, 2019

Manager, Corporate Reserves

WPX Energy, Inc.

One Williams Center, Suite 2600

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 Williston, LLC; WPX Energy Permian, LLC; and WPX Energy RM Company, LLC (collectively referred to herein as "WPX"), as of December 31, 2018, 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 estimates shown herein constitute over 99 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 and, as requested, the exclusion of per-well overhead expenses for the operated properties, 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, 2018, for the audited properties:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed	156,420	48,426	365,430	6,467,243	3,773,727
Proved Undeveloped	134,884	36,611	252,265	4,535,316	1,896,136
Total Proved	291,304	85,037	617,696	11,002,558	5,669,862

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 shown herein of WPX's reserves and future revenue are reasonable when aggregated at the proved developed, proved undeveloped, and total proved levels 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, 2018, 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.

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. 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.

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 2018. For oil and NGL volumes, the average West Texas Intermediate posted price of $62.04 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.100 per MMBTU is adjusted for energy content, transportation fees, and market differentials. 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 $61.57 per barrel of oil, $26.76 per barrel of NGL, and $1.21 per MCF of gas.

Operating costs used by WPX are based on historical operating expense records. For the nonoperated properties, 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 for the operated properties are limited to direct lease- and field-level costs and WPX's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. 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. Abandonment costs used are WPX's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Operating, capital, and abandonment costs are not escalated for inflation. Additionally, although we are aware of firm transportation contracts that are in place for these properties, the associated costs are considered by WPX to be corporate-level expenses; no adjustments have been made to estimates of future revenue to account for such contracts.

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. Benjamin W. Johnson, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2007 and has over 2 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/ Benjamin W. Johnson		/s/ John G. Hattner
By:		By:
	Benjamin W. Johnson, P.E. 124738		John G. Hattner, P.G. 559
	Vice President		Senior Vice President
Date Signed: February 19, 2019		Date Signed: February 19, 2019

BWJ: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.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 20, 2019	Jun. 30, 2018
Document Documentand Entity Information [Abstract]
Document type	10-K
Amendment flag	false
Document period end date	Dec. 31, 2018
Document fiscal year focus	2018
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 small business	false
Entity emerging growth company	false
Entity Shell Company	false
Entity common stock, shares outstanding		420,465,218
Entity public float			$ 7,172,269,200

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents		$ 3	$ 189
Accounts receivable, net of allowance		405	307
Derivative asset, current		174	36
Inventories		48	30
Assets classified as held for sale, current		79	811
Other		30	28
Total current assets		739	1,401
Long-term investments		167	70
Properties and equipment, net (successful efforts method of accounting)		7,266	6,691
Derivative asset, noncurrent		4	23
Other noncurrent assets		27	22
Total assets		8,203	8,207
Current liabilities:
Accounts payable		514	446
Accrued liabilities and other liabilities		178	209
Liabilities associated with assets held for sale, current		0	20
Derivative liabilities		23	171
Total current liabilities		715	846
Deferred income taxes		201	117
Long-term debt and capital lease obligations	[1]	2,485	2,575
Derivative liabilities		14	65
Other noncurrent liabilities		487	477
Contingent liabilities and commitments (Note 11)
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding at December 31, 2018 and 4.8 million shares outstanding at December 31, 2017)		0	232
Common stock (2 billion shares authorized at $0.01 par value; 420.6 million and 398.3 million shares issued and outstanding at December 31, 2018 and 2017)		4	4
Additional paid-in-capital		7,734	7,479
Accumulated deficit		(3,437)	(3,588)
Total equity		4,301	4,127
Total liabilities and equity		$ 8,203	$ 8,207

[1] Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares outstanding	0	4,800,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued and outstanding	420,600,000	398,300,000

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Net gain (loss) on derivatives		$ 443	$ (139)	$ (154)	$ (69)	$ (210)	$ (106)	$ 116	$ 203	$ 81	$ 3	$ (207)
Other										0	1	1
Total revenues		1,022	484	430	374	155	145	350	395	2,310	1,045	478
Costs and expenses:
Depreciation, depletion and amortization										777	542	441
Lease and facility operating										272	168	118
Taxes other than income										157	79	43
Exploration										75	87	26
General and administrative (including equity-based compensation)	[1]									182	166	202
Net (gain) loss on sales of assets and divestment of transportation contracts										(3)	(161)	239
Other—net										7	15	15
Total costs and expenses		447	413	388	322	265	223	231	208	1,756	947	1,304
Operating income (loss)		575	71	42	52	(110)	(78)	119	187	554	98	(826)
Interest expense										(163)	(188)	(207)
Gain (Loss) on Extinguishment of Debt				(71)			(17)			(71)	(17)	(1)
Investment income (loss) and other										(4)	3	2
Income (loss) from continuing operations before income taxes										316	(104)	(1,032)
Provision (benefit) for income taxes										74	(128)	(360)
Income (loss) from continuing operations		353	(6)	(79)	(26)	(20)	(378)	327	95	242	24	(672)
Income (loss) from discontinued operations		1	(1)	(2)	(89)	(18)	232	(251)	(3)	(91)	(40)	71
Net Income (Loss)		354	(7)	(81)	(115)					151	(16)	(601)
Preferred stock dividends, income statement impact										8	15	18
Preferred stock conversions, inducements										0	0	22
Net income (loss) available to common stockholders,		354	(7)	(85)	(119)	(42)	(149)	72	88	143	(31)	(641)
Amounts available to WPX Energy, Inc. common stockholders
Income (loss) from continuing operations attributable to WPX		353	(6)	(83)	(30)	(24)	(381)	323	91	234	9	(712)
Income (loss) from discontinued operations attributable to WPX		$ 1	$ (1)	$ (2)	$ (89)	$ (18)	$ 232	$ (251)	$ (3)	$ (91)	$ (40)	$ 71
Income (loss) from continuing operations, per basic share		$ 0.84	$ (0.01)	$ (0.21)	$ (0.07)	$ (0.06)	$ (0.96)	$ 0.81	$ 0.24	$ 0.57	$ 0.02	$ (2.28)
Discontinued operation, income (loss) from discontinued operation, net of tax, per basic share		0	0	0	(0.23)	(0.04)	0.58	(0.63)	(0.01)	(0.22)	(0.10)	0.23
Earnings per share, basic		0.84	(0.01)	(0.21)	(0.30)	(0.10)	(0.38)	0.18	0.23	0.35	(0.08)	(2.05)
Income (loss) from continuing operations, per diluted share		0.83	(0.01)	(0.21)	(0.07)	(0.06)	(0.96)	0.77	0.23	$ 0.57	$ 0.02	$ (2.28)
Basic weighted-average shares										408.4	395.1	313.3
Discontinued operation, income (loss) from discontinued operation, net of tax, per diluted share		0	0	0	(0.23)	(0.04)	0.58	(0.60)	(0.01)	$ (0.22)	$ (0.10)	$ 0.23
Earnings per share, diluted		$ 0.83	$ (0.01)	$ (0.21)	$ (0.30)	$ (0.10)	$ (0.38)	$ 0.17	$ 0.22	$ 0.35	$ (0.08)	$ (2.05)
Diluted weighted-average shares(a)	[2]									411.7	397.4	313.3
Oil and Condensate [Member]
Revenues:
Revenue from contract with customer, including assessed tax										$ 1,790	$ 879	$ 451
Natural Gas, Production [Member]
Revenues:
Revenue from contract with customer, including assessed tax										87	67	35
Natural Gas Liquids [Member]
Revenues:
Revenue from contract with customer, including assessed tax										148	70	21
Oil and Gas [Member]
Revenues:
Revenue from contract with customer, including assessed tax		$ 544	$ 554	$ 520	$ 407	$ 356	$ 247	$ 226	$ 187	2,025	1,016	507
Oil and Gas, Refining and Marketing [Member]
Revenues:
Revenue from contract with customer, including assessed tax		$ 36	$ 68	$ 64	$ 36	$ 8	$ 4	$ 8	$ 5	204	25	177
Costs and expenses:
Cost of Goods and Services Sold										182	27	208
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Costs and expenses:
Cost of Goods and Services Sold										$ 107	$ 24	$ 12

[1] General and administrative (including non-cash equity-based compensation of $32 million, $28 million and $31 million for the respective periods)

[2] Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:   Years Ended December 31,201820172016(Millions)Weighted-average nonvested restricted stock units and awards — — 2.2 Weighted-average stock options— — 0.01  Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14) 11.4 19.8 23.8  Nonvested restricted stock units antidilutive under the treasury stock method 0.7 0.6 — 

XML

Consolidated Statements of Operations Consolidated Statements of Operations - Parentheticals - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Benefits and Share-based Compensation, Noncash [Abstract]
Non-cash equity-based compensation expense	$ 32	$ 28	$ 31

XML

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Total Stockholders’ Equity	Preferred Stock	Common Stock	Capital in Excess of Par Value	Accumulated Deficit
Balance At Beginning Of Period at Dec. 31, 2015		$ 3,535	$ 339	$ 3	$ 6,164	$ (2,971)
Comprehensive income:
Net income (loss) attributable to WPX Energy, Inc.	$ (601)	(601)				(601)
Stock based compensation, net of tax impact		23			23
Stock issued during period, value, new issues		538			538
Conversion of stock, amount issued		11	(107)		118
Adjustments to additional paid in capital, dividends in excess of retained earnings		(18)			(18)
Preferred stock conversions, inducements	(22)	(22)			(22)
Balance At End Of Period at Dec. 31, 2016		3,466	232	3	6,803	(3,572)
Comprehensive income:
Net income (loss) attributable to WPX Energy, Inc.	(16)	(16)				(16)
Stock based compensation, net of tax impact		22			22
Stock issued during period, value, new issues		670		1	669
Adjustments to additional paid in capital, dividends in excess of retained earnings		(15)			(15)
Preferred stock conversions, inducements	0
Balance At End Of Period at Dec. 31, 2017		4,127	232	4	7,479	(3,588)
Comprehensive income:
Net income (loss) attributable to WPX Energy, Inc.	151	151				151
Stock based compensation, net of tax impact		31			31
Conversion of stock, amount issued		0	(232)		232
Adjustments to additional paid in capital, dividends in excess of retained earnings		(8)			(8)
Preferred stock conversions, inducements	$ 0
Balance At End Of Period at Dec. 31, 2018		$ 4,301	$ 0	$ 4	$ 7,734	$ (3,437)

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Activities
Net income (loss)		$ 151	$ (16)	$ (601)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		785	673	631
Deferred income tax provision (benefit)		84	(134)	(281)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments		73	158	38
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		81	3	(207)
Derivative, Cost of Hedge Net of Cash Received		(237)	4	302
Unrealized Loss on Derivatives, including Discontinued Operations		0	0	46
Amortization of stock-based awards		34	32	36
Loss on extinguishment of debt and acquisition bridge financing fees		71	17	1
Net (gains) losses on sales of assets and divestment of transportation contracts		145	(170)	(29)
Cash provided by (used in) operating assets and liabilities:
Accounts receivable		(59)	(153)	126
Inventories		(15)	(8)	10
Other current assets		2	(8)	5
Accounts payable		17	158	(72)
Federal Income Taxes receivable and payable		(38)	12	(19)
Accrued and other current liabilities		(22)	(31)	(45)
Increase (Decrease) in Other Accrued Liabilities		(47)	(53)	(53)
Other, including changes in other noncurrent assets and liabilities		20	29	(34)
Net cash provided by operating activities(a)	[1]	883	507	268
Investing Activities(a)
Payments to Acquire Productive Assets		1,476	1,161	578
Proceeds from sales of assets		682	193	1,127
Proceeds (payments) related to divestment of transportation contracts		0	0	(238)
Payments to Acquire Businesses, Gross		0	799	0
Proceeds from joint venture formation		0	338	0
Purchases of or contributions to investments		(102)	(8)	0
Other		0	1	0
Net cash provided by (used in) investing activities(a)	[1]	(896)	(1,436)	311
Financing Activities
Proceeds from common stock		10	672	540
Dividends paid on preferred stock		(11)	(15)	(18)
Payments related to induced conversion of preferred stock to common stock		0	0	(10)
Borrowings on credit facility		1,453	661	380
Payments on credit facility		(1,123)	(661)	(645)
Proceeds from long-term debt, net of discount		494	148	0
Payments for retirement of long-term debt, including premium		(986)	(165)	(356)
Taxes paid for shares withheld		14	12	6
Payments for debt issuance costs and credit facility amendment fees		(10)	(2)	(5)
Other		17	(2)	0
Net cash provided by (used in) financing activities		(170)	624	(120)
Net increase (decrease) in cash and cash equivalents and restricted cash		(183)	(305)	459
Cash and cash equivalents and restricted cash at beginning of period		201	506	47
Cash and cash equivalents and restricted cash at end of period		18	201	506
Increase to properties and equipment		(1,510)	(1,232)	(584)
Changes In Related Accounts Payable And Accounts Receivable		$ (34)	$ (71)	$ (6)

[1] (a) Amounts reflect continuing and discontinued operations unless otherwise noted.

XML

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase to properties and equipment	$ 1,510	$ 1,232	$ 584
Changes in related accounts payable and accounts receivable	34	71	6
Payments to Acquire Productive Assets	$ 1,476	$ 1,161	$ 578

XML

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]

Description of Business, Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3).

We had operations in the San Juan Basin which were sold in 2017 and 2018 that are reported in discontinued operations as discussed below. We also had other operations sold in 2016 which are reported as discontinued operations, as discussed below.

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

Basis of Presentation and 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. The Company has no other elements of comprehensive income (loss) other than net income (loss).

Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.

Discontinued Operations 

On January 30, 2018, we signed an agreement to sell our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC for $700 million (subject to closing and post-closing adjustments). This sale closed in March 2018. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million, a portion of which closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. The assets and liabilities were reclassified as held for sale on the Consolidated Balance Sheet as of December 31, 2017 and the results of operations of the San Juan Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3).

Our discontinued operations also include the results of previously owned properties in the Piceance Basin.

See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

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;

•valuation of deferred tax assets and liabilities;

•valuations of derivatives;

•estimation of oil and natural gas reserves; and

•assessments of litigation-related contingencies.

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 was approximately $15 million and $12 million as of December 31, 2018 and 2017, respectively, and is included in other current assets on the Consolidated Balance Sheets.

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. The following table presents a summary of inventories.

	Years ended December 31,
	2018		2017
	(Millions)
Material, supplies and other	$	46	$	29
Commodity production in storage	2		1
	$	48	$	30

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. 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 on the Consolidated Statements of Operations. 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 as unproved properties.

From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange in which commercial substance is established, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.

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.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. 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.

Certain gains and losses on derivative instruments included on 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 commodity management and for which we have not elected the normal purchases and normal sales exception;

•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 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 and commodity management revenues

Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.

Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.

Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Significant judgments related to revenue recognition include principal versus agent considerations.

We record revenue on a gross basis when we control a promised good or service before transferring it to a customer. We record

revenue on a net basis when we arrange for another company to provide the good or service. Determining the point and time when control of a product transfers to a customer requires significant judgment. Payment is typically due 30 to 45 days following delivery of product to our customers. 

Revenues from production 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 revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2018 and 2017 was insignificant.

Commodity management expenses

Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million in 2016.

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. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.

Employee stock-based compensation

Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Performance-based awards are tied to shareholder return over time relative to our peer group and are valued using a Monte Carlo method using measures of total shareholder return.

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 and awards (see Note 4).

Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $35 million and $32 million as of December 31, 2018 and 2017, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets. 

Recently Adopted Accounting Standards

The Company adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is 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. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at December 31, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are

wholly unsatisfied at the reporting period end. In addition, see Note 16 for receivables related to sales of oil, natural gas and related products and services.

We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $15 million, $12 million and $10 million as of December 31, 2018, 2017 and 2016, respectively.

We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.

We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.

Accounting Standards Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on review of the guidance and the Company’s current commitments, the Company believes it will be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and other arrangements. In 2018, we began the process of evaluating our contracts with components that may be subject to ASU 2016-02 and engaged a third party to assist with implementing the standard. In 2018 and 2019, we have implemented appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company is finalizing the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We believe the amounts recorded as right to use assets and lease payment liabilities will be less than $100 million.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to exclude from evaluation any land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. The amendments affect trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with and expected loss model for instruments measured at amortized cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.

XML

Acquisitions	12 Months Ended
	Dec. 31, 2018
Acquisition [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	AcquisitionOn January 12, 2017, we signed an agreement to acquire certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”) for $775 million, subject to post-closing adjustments. The transaction closed in March 2017 for $798 million including estimated closing adjustments. The assets, as of the closing date, included 25 producing wells (18 horizontals), three drilled but uncompleted horizontal laterals, approximately 18,000 net acres and more than 900 gross undeveloped locations in the Delaware Basin. We estimated that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved developed properties and facilities. This estimate is based on discounted cash flow models, which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. These assumptions represent Level 3 inputs. At the time of the acquisition closing, production was approximately 10,000 Boe per day. The impact of this acquisition to prior periods is not material to our results of operations for those periods.

XML

Discontinued Operations

12 Months Ended

Dec. 31, 2018

Discontinued operations [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Discontinued Operations

On January 30, 2018, we signed an agreement to sell our operations in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC (“Enduring”) for $700 million (subject to closing and post-closing adjustments). The transaction closed on March 28, 2018 and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. We believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and Enduring and the declining size of the obligations subject to the guarantee over time. Although we believe the probability of performance by WPX is low, we must determine the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018. The operations in the San Juan Gallup represented 12 percent of our total proved reserves at December 31, 2017 and 16 percent of our total production for 2017.

In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million and recorded a gain of approximately $2 million. A portion of the San Juan Legacy sale closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin.

Significant transactions for the San Juan Basin operations reflected in the tables below are as follows:

•In the third quarter of 2017, we began a process to market our San Juan Legacy properties and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value at September 30, 2017 which resulted in an impairment of $60 million recorded in third-quarter 2017. At the close of the sale, we recorded a gain of $2 million.

•On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million. The consideration reflected $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX’s development in the Gallup oil play. We were obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and additional gains of $18 million in the subsequent quarters of 2016 as certain in-progress construction was completed. As of December 31, 2017, the remaining deferred gain was approximately $3 million.

On February 8, 2016, we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations for $910 million. The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million, subject to post-closing adjustments, resulting in a gain of $52 million. We performed certain transition services for the buyer which concluded during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in commodity management revenue and expenses.

We sold our Powder River Basin properties in 2015; however, we retained certain firm gathering and treating obligations that continue through 2020 related to the Powder River properties sold. These commitments had been in excess of the production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company that continue through 2021. We recorded liabilities related to these commitments in 2015. In 2017, we increased the liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 11 for additional information related to these liabilities.

Summarized Results of Discontinued Operations

The following table presents the results of discontinued operations for the years presented.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Total revenues	$	75	$	291	$	279
Costs and expenses:
Depreciation, depletion and amortization	$	8	$	131	$	191
Lease and facility operating	7		50		63
Gathering, processing and transportation	12		70		113
Taxes other than income	5		23		19
Exploration	3		14		16
General and administrative	1		8		21
Accrual for contract obligations retained	—		5		—
Net (gain) loss—sales of assets and impairments	—		50		(217)
Accretion of liabilities related to contract obligations retained	6		6		2
Other—net(a)	5		(3)		7
Total costs and expenses	47		354		215
Operating income (loss)	28		(63)		64
Gain (loss) on sales of domestic assets	(148)		—		51
Income (loss) from discontinued operations before income taxes	(120)		(63)		115
Provision (benefit) for income taxes	(29)		(23)		44
Income (loss) from discontinued operations	$	(91)	$	(40)	$	71

 __________

(a) Includes severance tax refund received in 2017.

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

	December 31,
	2017
	(Millions)
Assets classified as held for sale
Inventories	$	14
Properties and equipment, net (successful efforts method of accounting)	797
Total assets classified as held for sale on the Consolidated Balance Sheets	$	811
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	1
Accrued and other current liabilities	1
Total current liabilities	2
Asset retirement obligations	15
Other noncurrent liabilities	3
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	20

Cash Flows Attributable to Discontinued Operations

In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Cash provided by operating activities(a)	$	44	$	143	$	102
Cash capital expenditures within investing activities	$	29	$	175	$	135

 __________

(a) Excluding income taxes and changes to working capital.

XML

Earnings (Loss) Per Common Share from Continuing Operations

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

Earnings (Loss) Per Common Share from Continuing Operations

 The following table summarizes the calculation of earnings per share.

	Years Ended December 31,
	2018		2017		2016
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	242	$	24	$	(672)
Less: Dividends on preferred stock	8		15		18
Less: Loss on induced conversion of preferred stock	—		—		22
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income (loss) per common share	$	234	$	9	$	(712)
Basic weighted-average shares	408.4		395.1		313.3
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	3.1		2.1		—
Stock options	0.2		0.2		—
Diluted weighted-average shares(a)	411.7		397.4		313.3
Income (loss) per common share from continuing operations:
Basic	$	0.57	$	0.02	$	(2.28)
Diluted	$	0.57	$	0.02	$	(2.28)

 __________

(a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:  

	Years Ended December 31,
	2018	2017	2016
	(Millions)
Weighted-average nonvested restricted stock units and awards	—	—	2.2
Weighted-average stock options	—	—	0.01
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)	11.4	19.8	23.8
Nonvested restricted stock units antidilutive under the treasury stock method	0.7	0.6	—

The table below includes information related to stock options that were outstanding at December 31, 2018, 2017 and 2016 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.

	December 31,
	2018		2017		2016
Options excluded (millions)	0.7		1.5		2.0
Weighted-average exercise price of options excluded	$	18.05	$	17.80	$	17.42
Exercise price range of options excluded	$16.46 - $21.81		$14.41 - $21.81		$14.41 - $21.81
Fourth quarter weighted-average market price	$	15.16	$	12.10	$	13.23

XML

Asset Sales, Impairments and Exploration Expenses

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Asset Sales,Other Expenses and Exploration Expenses

Asset Sales and Exploration Expenses

Asset Sales

2017

Net gain on sales of assets for the year ended December 31, 2017 primarily reflect total gains of $103 million from exchanges of leasehold acreage in the Permian Basin, $48 million from the recognition of deferred gains related to the completion of commitments from the sale in 2015 of a North Dakota gathering system and $8 million recognized on the sales of certain Green River Basin and Appalachian Basin assets.

In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs.

2016

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

Exploration Expenses

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Unproved leasehold property impairments, amortization and expiration	$	69	$	84	$	22
Geologic and geophysical costs	6		$	3	3
Impairments of exploratory area well costs and dry hole costs	—		—		1
Total exploration expenses	$	75	$	87	$	26

Unproved leasehold property impairment, amortization and expiration for 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Permian Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.

XML

Investments

12 Months Ended

Dec. 31, 2018

Schedule of Equity Method Investments [Line Items]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Investments

In June 2017, we signed an agreement with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the agreement, WPX and Howard each have a 50 percent voting interest in the newly formed joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity will serve as operator. In addition to a $300 million cash contribution, Howard is obligated to fund the first $263 million of joint venture capital expenditures. At closing in October 2017, WPX contributed subsidiaries holding crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $53 million. WPX also paid $11 million for advisory services and legal fees on the transaction. Howard contributed $439 million in cash at closing, $139 million of which applies to the $263 million carry obligation of Howard including $49 million for capital expenditures from January 1, 2017 to closing. Concurrently, WPX received a $300 million special distribution plus the $49 million for capital expenditures from Catalyst. We will account for our investment in Catalyst as an equity method investment. In connection with the joint venture, a consolidated subsidiary of WPX dedicated production from its current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to 20 year fixed-fee oil gathering and natural gas processing agreements with subsidiaries of Catalyst. The agreements do not include any minimum volume commitments. Our investment in Catalyst totaled $58 million and $64 million as of December 31, 2018 and 2017, respectively. In 2017, we deferred recognition of the $349 million and will recognize it over the 20 years based on production volumes as a deduction to gathering, processing and transportation expense. As of December 31, 2018, the deferred amount was $346 million of which $336 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.

During 2018, we contributed an additional $93 million to our equity method investment in the Oryx II pipeline project, of which $23 million increased our ownership from 12.5 percent to 25 percent.

XML

Properties and Equipment

12 Months Ended

Dec. 31, 2018

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,
		2018		2017
		(Millions)
Proved properties	(b)	$	7,289	$	5,815
Unproved properties	(c)	1,891		2,194
Gathering, processing and other facilities	15-25	294		242
Construction in progress	(c)	350		305
Other	3-40	125		118
Total properties and equipment, at cost		9,949		8,674
Accumulated depreciation, depletion and amortization		(2,683)		(1,983)
Properties and equipment—net		$	7,266	$	6,691

__________

(a) Estimated useful lives are presented as of December 31, 2018.

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

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

Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.

In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 17).

Asset Retirement Obligations 

Our asset retirement obligations relate to producing wells, 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. Asset retirement obligations are reported in other noncurrent liabilities on the Consolidated Balance Sheets.

A rollforward of our asset retirement obligations for the years ended 2018 and 2017 is presented below.

	2018		2017
	(Millions)
Balance, January 1	$	39	$	40
Liabilities incurred	8		5
Liabilities settled	(7)		(11)
Estimate revisions	30		3
Accretion expense(a)	2		2
Balance, December 31	$	72	$	39
Amount reflected as current	$	5	$	7

__________

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

XML

Accounts Payable and Accrued and Other Current Liabilities

12 Months Ended

Dec. 31, 2018

Payables and Accruals [Abstract]

Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable

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

	December 31,
	2018		2017
	(Millions)
Trade	$	130	$	120
Accrual for capital expenditures	190		151
Royalties	170		150
Cash overdrafts	17		—
Other	7		25
	$	514	$	446

Accrued and other current liabilities

The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.

	December 31,
	2018		2017
	(Millions)
Taxes other than income taxes	$	19	$	14
Accrued interest	45		69
Compensation and benefit related accruals	39		39
Gathering and transportation	7		11
Gathering and transportation related to exited areas	30		53
Other, including other loss contingencies	38		23
	$	178	$	209

XML

Debt and Banking Arrangements

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt and Banking Arrangements

Debt and Banking Arrangements

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

	December 31,
	2018 (a)		2017 (a)
	(Millions)
Credit facility agreement	$	330	$	—
7.500% Senior Notes due 2020	—		350
6.000% Senior Notes due 2022	529		1,100
8.250% Senior Notes due 2023	500		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		—
Total debt	$	2,509	$	2,600
Less: Current portion of long-term debt	—		—
Total long-term debt	$	2,509	$	2,600
Less: Debt issuance costs(b)	24		25
Total long-term debt, net(b)	$	2,485	$	2,575

__________

(a) Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.

(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

Credit Facility

On April 17, 2018, the Company entered into a Second Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, increases total commitments to $1.5 billion, increases the Borrowing Base to $1.8 billion, and extends the maturity date to April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2018, WPX had $330 million borrowings outstanding, had $52 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement.

Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. In October 2018, the Borrowing Base was increased to $2.0 billion and will remain in effect until the next Redetermination Date as set forth in the Credit Facility. At this time, the Credit Facility Agreement is limited by the total commitments on the Credit Facility which remained at $1.5 billion. The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.

Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.

The Collateral Trigger Termination Date is the first date following the Second Amendment Effective Date and the first date following any Collateral Trigger Date, as applicable, on which:

1.(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or

2.in the case of a Voluntary Collateral Trigger Period, WPX elects to cause a Collateral Trigger Termination Date to occur.

Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings.

Significant Financial Covenants.

Currently, the Company is required to maintain:

• ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 4.25 to 1.00 as of the last day of the Rolling Period; and

•a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.

If a Collateral Trigger Termination Date occurs, other financial covenants would apply.

Covenants. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit,

among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties.

Events of Default. The Credit Facility includes customary events of default, including events of default relating to:

•non-payment of principal, interest or fees;

•inaccuracy of representations and warranties in any material respect when made or when deemed made;

•violation of covenants;

•cross payment-defaults;

•cross acceleration;

•bankruptcy and insolvency events;

•certain unsatisfied judgments;

•a change of control; and

•during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.

If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2018.  

Senior Note	Face Value (Millions)		Maturity Date	Interest Payment Dates	Optional Redemption Period(a)
6.000% Senior Notes due 2022 (the “2022 Notes”)	$	529	January 15, 2022	January 15, July 15	October 15, 2021
8.250% Senior Notes due 2023 (the “2023 Notes”)	$	500	August 1, 2023	February 1, August 1	June 1, 2023
5.250% Senior Notes due 2024 (the “2024 Notes”)	$	650	September 15, 2024	March 15, September 15	June 15, 2024
5.750% Senior Notes due 2026 (the “2026 Notes”)	$	500	June 1, 2026	June 1, December 1	June 1, 2021

 __________

(a) At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the 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 as more fully described in the indenture.

In the second quarter of 2018, we used proceeds from our San Juan Gallup disposition and the issuance of new senior notes discussed below to retire $921 million aggregate principal amount of our senior notes ($350 million due 2020 and $571 million due 2022) through a series of cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $71 million, which includes approximately $63 million of premium and approximately $6 million write-off of previously capitalized costs.

On May 23, 2018, we completed a debt offering of $500 million of 5.750% Senior Notes due in 2026 (the “2026 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on June 1 and December 1 of each year commencing on December 1, 2018. The 2026 Notes will mature on June 1, 2026 with the option, prior to June 1, 2021, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, after June 1, 2021, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2026 Notes was approximately $494 million and approximately $1 million of debt issuance costs were capitalized.

During third-quarter 2017, we issued an additional $150 million of our 5.250% senior notes due 2024. The proceeds were used to fund the tender offer of $150 million of our 7.500% senior notes due 2020. As a result, we recorded a loss on extinguishment of debt of $17 million.

The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes and 2026 Notes are substantially identical.

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.

XML

Provision (Benefit) for Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes

Provision (Benefit) for Income Taxes

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

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Provision (benefit):
Current:
Federal	$	(38)	$	(18)	$	(26)
State	1		1		(7)
	(37)		(17)		(33)
Deferred:
Federal	107		(100)		(333)
State	4		(11)		6
	111		(111)		(327)
Total provision (benefit)	$	74	$	(128)	$	(360)

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Act”). The income tax effects of changes in tax laws are recognized in the period when enacted. The Act repealed the corporate alternative minimum tax (“AMT”) and amended Section 53 of the Internal Revenue Code to allow for refunds of AMT credit carryforwards. Under Section 53(e), taxpayers receive 50 percent of their uncredited balance in years 2018–2020. Taxpayers receive 100 percent of the remaining balance in 2021. Accordingly, the Company recorded a current receivable of $38 million as of December 31, 2018 related to AMT credit refunds expected to be collected in 2019. However, our AMT credit carryforwards are subject to change based on the results of the 2011 Williams audit discussed below and may impact future refunds.

The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.

	Years Ended December 31,
	2018			2017			2016
	(Millions)
Federal Statutory Rate	21		%	35		%	35		%
Provision (benefit) at statutory rate	$	66		$	(36)		$	(361)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	(8)			(12)			(42)
Valuation allowance on current year state income taxes (net of federal   benefit)	17			17			18
Valuation allowance on state income taxes resulting from sale (net of   federal benefit)	—			—			8
Effective state income tax rate change (net of federal benefit)	(5)			(12)			15
Provisional impact of Tax Cuts and Jobs Act	—			(92)			—
Other	4			7			2
Provision (benefit) for income taxes	$	74		$	(128)		$	(360)

As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years. As a result of the sale of our Piceance Basin operations in Colorado in the second quarter of 2016, we recorded $8 million of valuation allowances against Colorado NOL and credit carryovers generated in prior years.

Significant changes to our operations during 2018, 2017 and 2016 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we recorded an additional $5 million and $12 million deferred tax benefit in 2018 and 2017, respectively. We also accrued an additional $15 million of deferred tax expense in 2016.

Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allowed us to provide a provisional estimate of the impacts of the Act in our earnings for the year ending December 31, 2017. Additional impacts from the enactment of the Act were allowed to be recorded as they were identified during the one-year measurement period as provided for in SAB 118. Accordingly, the Company did not have any adjustments to its provisional amounts.

The following table includes significant components of deferred tax liabilities and deferred tax assets.

	December 31,
	2018		2017
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	797	$	792
Derivatives, net	33		—
Other, net	—		1
Total deferred tax liabilities	830		793
Deferred tax assets:
Accrued liabilities and other	137		79
Alternative minimum tax credits	40		78
Loss carryovers	665		672
Derivatives, net	—		42
Total deferred tax assets	842		871
Less: valuation allowance	213		195
Total net deferred tax assets	629		676
Net deferred tax liabilities	$	201	$	117

Net cash payments (refunds) for income taxes were $2 million, $(39) million and $21 million in 2018, 2017 and 2016, respectively.

The Company has federal NOL carryovers of approximately $2,021 million at December 31, 2018, including a $353 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, we have $48 million of federal capital loss carryovers at December 31, 2018, that will begin to expire in 2020. 

The Company has state NOL carryovers of approximately $4.1 billion and $3.8 billion at 2018 and 2017, respectively, of which more than 99 percent expire after 2029.

We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. As of December 31, 2018, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss may result in the need for a valuation allowance on our deferred tax assets.

The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of December 31, 2018, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI NOL that arose prior to the acquisition.

Pursuant to our tax sharing agreement with The Williams Companies ("Williams"), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. The IRS has proposed an adjustment related to our business for which a payment to Williams could be required. We have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not 

expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS.

The Company files a consolidated federal income tax return and several state income tax returns. The Company’s federal income tax returns for tax years 2014 through 2016 remain open for examination. The statute of limitations for most states expires one year after expiration of the IRS statute. During the year ended December 31, 2017, the IRS began an examination of the Company’s 2014, 2015 and 2016 federal income tax returns. In addition, the IRS began an examination of RKI’s 2014 and short-period 2015 federal income tax returns. These examinations remain ongoing and no additional taxes or refunds have been recorded at this time.

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 less than $1 million for 2018 and 2017. The impact of this accrual is included within Other in our reconciliation of the provision (benefit) at statutory rate to recorded provision (benefit) for income taxes.

As of December 31, 2018, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. 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.

XML

Contingent Liabilities and Commitments

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

Contingent Liabilities and Commitments

Contingent Liabilities

Royalty litigation

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and on September 21, 2018 the Tenth Circuit dismissed the appeal for lack of jurisdiction. On January 22, 2019, plaintiffs’ filed a petition for certiorari to the United States Supreme Court. At this time, we believe that our royalty calculations were 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 many of 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. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.

Environmental matters

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

Matters related to Williams’ former power business

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

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. On October 23, 2018, a settlement in principle with the Kansas and Missouri class claimants was reached. Final documents have not been finalized and approved by the Court. In the Wisconsin class action, defendants’ motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs’ motion to remand the case to the originally filed district court.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.

Other Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements.

The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.

As of December 31, 2018, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

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

indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.

Summary

As of December 31, 2018 and December 31, 2017, the Company had accrued approximately $11 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 

We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our oil and natural gas production and third-party purchases of oil and natural gas to other locations in an attempt to obtain more favorable pricing differentials. During 2017 and 2018, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. As of December 31, 2018, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:

	Midstream Services		Transportation		Total
	(Millions)
2019	$	55	$	115	$	170
2020	58		95		153
2021	48		68		116
2022	43		59		102
2023	40		47		87
Thereafter	68		352		420
Total commitments	$	312	$	736	$	1,048
Accrued liabilities	$	24	$	40	$	64

Our midstream service commitments will be settled over approximately seven years.

Future minimum annual rentals under noncancelable operating leases as of December 31, 2018, are payable as follows:

	(Millions)
2019	$	38
2020	37
2021	12
2022	3
2023	—
Thereafter	—
Total	$	90

Total rent expense, excluding amounts capitalized, was $25 million, $19 million and $23 million in 2018, 2017 and 2016, 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.

XML

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2018
Postemployment Benefits [Abstract]
Employee Benefit Plans	Employee Benefit PlansWPX 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 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 $10 million, $11 million and $13 million for 2018, 2017 and 2016, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2018, and 2017 related to the non-matching annual employer contribution.

XML

Stock-Based Compensation

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Stock-Based Compensation

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 (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units and awards for purposes of this footnote). During 2018, the 2013 Incentive Plan was amended to authorize an additional 7.4 million shares for issuance under the plan. At December 31, 2018, 18 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 12 million shares were available for future grants. 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.

Total stock-based compensation expense was $32 million, $28 million and $31 million for of the years ended December 31, 2018, 2017 and 2016, respectively, and is reflected in general and administrative expense. Measured but unrecognized stock-based compensation expense related to restricted stock units and awards at December 31, 2018 was $40 million and is expected to be recognized over a weighted-average period of 2.6 years. There was no unrecognized stock-based compensation expense related to stock options at December 31, 2018.

The ESPP allows 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. During 2018, the ESPP was amended to replenish the number of shares of our common stock that may be issued under the ESPP by 750 thousand. Offering periods are from January through June and from July through December. Employees purchased 97 thousand shares at an average price of $10.74 per share during 2018.

Nonvested Restricted Stock Units and Awards

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2018.

Restricted Stock Units	Shares	Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2017	5.7	$	12.06
Granted	2.4	$	16.74
Forfeited	(0.1)	$	12.63
Vested	(2.6)	$	10.18
Nonvested at December 31, 2018	5.4	$	15.01

__________

(a) Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.

Other restricted stock unit information

	2018		2017		2016
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	16.74	$	13.76	$	10.99
Total fair value of restricted stock units vested during the year (millions)	$	26	$	33	$	37

Performance-based shares granted represent 36 percent of nonvested restricted stock units outstanding at December 31, 2018. 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 to 200 percent of the original grant amount.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2018.

Stock Options	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value
	(Millions)			(Years)	(Millions)
Outstanding at December 31, 2017	2.2	$	15.35		$	3
Granted	—	$	—
Exercised	(0.8)	$	12.35
Forfeited	(0.3)	$	20.19
Outstanding at December 31, 2018	1.1	$	16.00	2.2	$	0.3
Exercisable at December 31, 2018	1.1	$	16.00	2.2	$	0.3

The total intrinsic value of options exercised was $4.3 million, $224 thousand and $160 thousand for the years ended December 31, 2018, 2017 and 2016, respectively.

Cash received from stock option exercises was $9.2 million, $0.4 million and $0.4 million during 2018, 2017 and 2016, respectively.

The Company did not grant stock options during the years ended 2018, 2017 and 2016.

XML

Stockholders' Equity

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Stockholders' Equity

Stockholders’ Equity

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.

Series A Mandatory Convertible Preferred Stock

On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our Preferred Stock at $50 per share, for gross proceeds of approximately $350 million, before underwriting discounts and commissions. Dividends on our Preferred Stock were paid in cash on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018. 

On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our Preferred Stock, pursuant to which each of the Preferred Holders agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders agreed to convert an aggregate of approximately 2.2 million shares of Preferred Stock into approximately 10.2 million shares of our common stock in the Conversion, and we made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million in 2016. 

On July 30, 2018, all of the outstanding shares, approximately 4.8 million, of our preferred stock converted into approximately 19.8 million shares of our common stock pursuant to the mandatory conversion provisions of the preferred stock offering.

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 on our common stock were declared or paid for 2018, 2017 or 2016. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.

Subject to certain exceptions, so long as any share of our Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Preferred Stock.

On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

On January 12, 2017, we completed an underwritten public offering of 51.675 million shares of our common stock, which included 6.675 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $12.97 per share and we received proceeds of approximately $670 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. We used these proceeds, and cash on hand, to close the Panther Acquisition (see Note 2).

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

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, calls 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 approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

	December 31, 2018								December 31, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	175	$	3	$	178	$	—	$	59	$	—	$	59
Energy derivative liabilities	$	—	$	37	$	—	$	37	$	—	$	236	$	—	$	236
Total debt(a)	$	—	$	2,414	$	—	$	2,414	$	—	$	2,746	$	—	$	2,746

__________

(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,509 million and $2,600 million as of December 31, 2018 and 2017, respectively.

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

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

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

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

Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, calls or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil and natural gas swaps entered into, we granted swaptions and calls to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions and calls 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 extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling $3 million included in Level 3 as of December 31, 2018. There were no instruments included in Level 3 as of December 31, 2017.

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, Level 2 and Level 3 occurred during the years ended December 31, 2018 or 2017.

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

Other

In addition to the items discussed below, we performed other nonrecurring fair value assessments as discussed in Note 2.

2017

In conjunction with the $103 million of gains from exchanges of leasehold during 2017, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs. The total fair value of leasehold exchanges in 2017 approximated $200 million. See Note 5 for additional discussion related to leasehold exchanges.

In addition, during the third quarter of 2017, we began a process to market our natural gas-producing properties in the San Juan Basin and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value which resulted in an impairment of $60 million recorded in the third-quarter of 2017. See Note 3 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin reported as discontinued operations.

XML

Derivatives and Concentration of Credit Risk

12 Months Ended

Dec. 31, 2018

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 crude oil, natural gas and natural gas liquids attributable to commodity price risk.

We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaptions.

Derivatives related to production

The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2018.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	2019	Fixed Price Swaps	WTI	(38,000)	$	53.49
Crude Oil	2019	Basis Swaps	Midland/Cushing	(21,008)	$	(1.16)
Crude Oil	2019	Basis Swaps	Nymex CMA Roll	(20,000)	$	0.11
Crude Oil	2019	Basis Swaps	Magellan East Houston/Midland	(1,841)	$	8.12
Crude Oil	2019	Basis Swaps	Argus LLS/Midland	(838)	$	8.60
Crude Oil	2019	Fixed Price Calls	WTI	(5,000)	$	54.08
Crude Oil	2020	Basis Swaps	Midland/Cushing	(7,486)	$	(1.31)
Crude Oil	2020	Basis Swaps	Brent/WTI Spread	(5,000)	$	8.36
Crude Oil	2021	Basis Swaps	Brent/WTI Spread	(1,000)	$	8.00
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75
Natural Gas
Natural Gas	2019	Fixed Price Swaps	Henry Hub	(108)	$	3.07
Natural Gas	2019	Basis Swaps	Permian	(25)	$	(0.39)
Natural Gas	2019	Basis Swaps	Waha	(15)	$	2.94
Natural Gas	2019	Basis Swaps	Houston Ship Channel	(30)	$	(0.09)
Natural Gas	2020	Basis Swaps	Waha	(60)	$	(0.79)
Natural Gas	2021	Basis Swaps	Waha	(70)	$	(0.59)
Natural Gas	2022	Basis Swaps	Waha	(70)	$	(0.57)
Natural Gas	2023	Basis Swaps	Waha	(70)	$	(0.51)

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread.

(b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.

(c) The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.

Fair values and gains (losses)

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, our derivatives do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Gain (loss) from derivatives related to production(a)	$	78	$	3	$	(207)
Gain (loss) from derivatives related to physical marketing agreements(b)	3		—		—
Net gain (loss) on derivatives	$	81	$	3	$	(207)

__________

(a) Includes payments totaling $237 million for the year ended December 31, 2018 and settlements totaling $4 million and $301 million for the years ended December 31, 2017 and 2016, respectively.

(b) Includes payments totaling less than $1 million for the years ended December 31, 2018 and 2017 and settlements totaling  $1 million for the year ended December 31, 2016.

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

Offsetting of derivative assets and liabilities

The following table presents our gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet		Netting Adjustments (a)		Net Amount
December 31, 2018	(Millions)
Derivative assets with right of offset or master netting agreements	$	178	$	(37)	$	141
Derivative liabilities with right of offset or master netting agreements	$	(37)	$	37	$	—
December 31, 2017
Derivative assets with right of offset or master netting agreements	$	59	$	(42)	$	17
Derivative liabilities with right of offset or master netting agreements	$	(236)	$	42	$	(194)

__________

(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional

collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

As of December 31, 2018, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net less than $1 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. As of December 31, 2017, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $194 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $4 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 and $194 million at December 31, 2018 and 2017, respectively.

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 dates indicated below. 

	December 31,
	2018		2017
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	269	$	251
Joint interest owners	98		54
Income tax receivable	38		—
Other	—		2
Total	$	405	$	307

Oil and natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the southwestern United States 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 creditworthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2018, 2017 and 2016, 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.

Our gross and net credit exposure from our derivative contracts were $178 million and $141 million, respectively, as of December 31, 2018. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We consider counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.

Our six largest net counterparty positions represent approximately 91 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

Other

At December 31, 2018, we held collateral support of $10 million, either in the form of cash, letters of credit or surety bond, related to our commodity management agreements.

Collateral support for our commodity agreements could include margin deposits, letters of credit, and guarantees of payment by credit worthy parties.

Revenues

The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. 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.

	Year ended December 31,
	2018	2017	2016
United Energy Trading LLC	23%	(a)	(a)
Occidental Energy Marketing	16%	(a)	(a)
Crestwood Midstream Partners LP	(a)	21%	(a)
St. Paul Refining	(a)	16%	13%
NGL Crude Logistics	14%	13%	(a)
Delek Refining, Ltd	(a)	10%	(a)
Plains Marketing	(a)	(a)	15%

__________

(a) Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives.

One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course

of business, we sell crude oil to NGL Energy. For the year ended 2018, sales to NGL Energy were approximately 14 percent of our total consolidated revenues adjusted for gain (loss) on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 1 percent of operating expenses.

XML

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Event [Line Items]
Subsequent events [Text Block]	Subsequent EventsWe have signed agreements to divest certain holdings for aggregate proceeds in excess of $200 million. The agreements consist of separate sales transactions for our 20 percent equity interest in the Whitewater natural gas pipeline which we expect to close in first-quarter 2019 and roughly 5,600 net acres in the Delaware Basin which has closed in 2019. We have also closed on a $100 million purchase of 14,000 surface acres within our Stateline operations, which we expect will provide economic benefit through speed of development, facilitation of longer laterals, right of way access and revenue associated with infrastructure like roads, water and electricity.

XML

Quarterly Financial Data

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL DATA

WPX Energy, Inc.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2018	(Millions, except per-share amounts)
Product revenues	$	407	$	520	$	554	$	544
Net gain (loss) on derivatives	$	(69)	$	(154)	$	(139)	$	443
Commodity management	$	36	$	64	$	68	$	36
Total revenues	$	374	$	430	$	484	$	1,022
Operating costs and expenses	$	322	$	388	$	413	$	447
Operating income	$	52	$	42	$	71	$	575
Income (loss) from continuing operations	$	(26)	$	(79)	$	(6)	$	353
Loss from discontinued operations	(89)		(2)		(1)		1
Net income (loss)	$	(115)	$	(81)	$	(7)	$	354
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	(30)	$	(83)	$	(6)	$	353
Loss from discontinued operations	(89)		(2)		(1)		1
Net income (loss)	$	(119)	$	(85)	$	(7)	$	354
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.07)	$	(0.21)	$	(0.01)	$	0.84
Loss from discontinued operations	(0.23)		—		—		—
Net income (loss)	$	(0.30)	$	(0.21)	$	(0.01)	$	0.84
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.07)	$	(0.21)	$	(0.01)	$	0.83
Loss from discontinued operations	(0.23)		—		—		—
Net income (loss)	$	(0.30)	$	(0.21)	$	(0.01)	$	0.83
2017
Product revenues	$	187	$	226	$	247	$	356
Net gain (loss) on derivatives	$	203	$	116	$	(106)	$	(210)
Commodity management	$	5	$	8	$	4	$	8
Total revenues	$	395	$	350	$	145	$	155
Operating costs and expenses	$	208	$	231	$	223	$	265
Operating income (loss)	$	187	$	119	$	(78)	$	(110)
Income (loss) from continuing operations	$	95	$	327	$	(378)	$	(20)
Income (loss) from discontinued operations	(3)		(251)		232		(18)
Net income (loss)	$	92	$	76	$	(146)	$	(38)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	91	$	323	$	(381)	$	(24)
Income (loss) from discontinued operations	(3)		(251)		232		(18)
Net income (loss)	$	88	$	72	$	(149)	$	(42)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.24	$	0.81	$	(0.96)	$	(0.06)
Income (loss) from discontinued operations	(0.01)		(0.63)		0.58		(0.04)
Net income (loss)	$	0.23	$	0.18	$	(0.38)	$	(0.10)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.23	$	0.77	$	(0.96)	$	(0.06)
Income (loss) from discontinued operations	(0.01)		(0.60)		0.58		(0.04)
Net income (loss)	$	0.22	$	0.17	$	(0.38)	$	(0.10)

Net income or loss for each respective quarter include the following pre-tax items:

First-quarter 2018:

•$138 million loss included in discontinued operations for the sale of the San Juan Gallup and $9 million performance guarantee related to gathering and processing commitments (see Note 3).

Second-quarter 2018:

•$71 million loss on extinguishment of debt (see Note 9).

First-quarter 2017:

•$31 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5).

•$23 million loss on write-off of expired leases in the Permian Basin (see Note 5).

Third-quarter 2017:

•$111 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5).

•$60 million impairment on San Juan Legacy included in discontinued operations (see Note 3).

•$17 million loss on extinguishment of debt (see Note 9).

•$10 million severance tax refunds for prior years related to the Piceance Basin (see Note 3).

Fourth-quarter 2017:

•$11 million gain on leasehold exchanges (see Note 5).

•$5 million increase on future commitments under gathering, processing and transportation liability related to the Powder River Basin in discontinued operations (see Note 3).

•$92 million income tax benefit related to the impact of new income tax legislation (see Note 10).

XML

Supplemental Oil and Gas Disclosures

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Supplemental Oil and Gas Disclosures

We have significant continuing oil and gas producing activities primarily in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota, all of which are located in the United States.

With the exception of Capitalized Costs, the following information includes activity through the completion of the respective asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan and Piceance Basins, both of which have been reported as discontinued operations in our consolidated financial statements. The San Juan Basin properties were sold in March 2018 and December 2017. The Piceance Basin properties were sold in April 2016. Capitalized Costs do not include amounts which are classified as assets held for sale on the Consolidated Balance Sheets.

Capitalized Costs

	As of December 31,
	2018		2017
	(Millions)
Proved Properties	$	7,612	$	6,113
Unproved properties	1,891		2,194
	9,503		8,307
Accumulated depreciation, depletion and amortization and valuation provisions	(2,542)		(1,860)
Net capitalized costs	$	6,961	$	6,447

__________

•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $276 million and $223 million, net, as of December 31, 2018 and 2017, 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,
	2018		2017		2016
	(Millions)
Acquisition	$	68	$	864	$	84
Exploration	7		5		5
Development	1,350		1,048		471
	$	1,425	$	1,917	$	560

__________

•Costs incurred include capitalized and expensed items.

•Acquisition costs are as follows: Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) in March 2017 that included $195 million and 23.8 MMboe of proved developed reserves and facilities. Costs in 2016 primarily relates to purchases of additional acreage in the Delaware Basin and included approximately 2.5 MMboe of proved reserves.

•Exploration costs include 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. Development costs associated with our San Juan Basin and Piceance Basin operations were $24 million, $168 million and $102 million for 2018, 2017 and 2016, respectively.

 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 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 proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations.

	Oil (MMbbls)	Natural Gas (Bcf)	NGLs (MMbbls)	All Products (MMboe)
Proved reserves at December 31, 2015	142.7	2,190.2	75.3	583.0
Revisions	(3.8)	(50.2)	(2.9)	(15.2)
Purchases	1.6	4.4	0.4	2.8
Divestitures	(5.5)	(1,505.9)	(38.3)	(294.8)
Extensions and discoveries	54.9	214.6	19.8	110.5
Production	(15.3)	(118.6)	(4.8)	(39.9)
Proved reserves at December 31, 2016	174.6	734.5	49.5	346.4
Revisions	4.7	(8.4)	(1.1)	2.3
Purchases	21.8	58.8	7.8	39.4
Divestitures	(1.7)	(312.5)	(0.8)	(54.6)
Extensions and discoveries	86.7	194.5	23.6	142.7
Production	(22.4)	(75.9)	(5.0)	(40.0)
Proved reserves at December 31, 2017	263.7	591.0	74.0	436.2
Revisions	—	(11.4)	5.3	3.4
Purchases	1.5	4.8	0.6	2.9
Divestitures	(27.6)	(79.8)	(10.4)	(51.3)
Extensions and discoveries	84.5	176.9	22.7	136.7
Production	(30.8)	(63.8)	(7.2)	(48.6)
Proved reserves at December 31, 2018	291.3	617.7	85.0	479.3
Proved developed reserves:
December 31, 2016	84.4	440.2	24.1	181.8
December 31, 2017	130.3	321.2	38.8	222.7
December 31, 2018	156.4	365.4	48.4	265.8
Proved undeveloped reserves:
December 31, 2016	90.2	294.2	25.4	164.6
December 31, 2017	133.4	269.8	35.2	213.5
December 31, 2018	134.9	252.3	36.6	213.5

__________

•Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.

•Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells. Revisions in 2016 primarily reflect 49 MMboe of negative revisions due to the decrease in the 12-month average price partially offset by 34 MMboe of positive revisions due to decreased costs and well improvements.

•Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed.

•Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves. Divestitures in 2016 relate to the sale of the Piceance Basin which included proved developed reserves and proved undeveloped reserves of 222 MMboe and 67 MMboe, respectively.

•Extensions and discoveries in 2018 reflect 52 MMboe added for proved developed locations and 85 MMboe of proved undeveloped locations. Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins. Extensions and discoveries in 2016 reflect 26 MMboe added for proved developed locations and 84 MMboe for proved undeveloped locations primarily in the Delaware 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 were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. The average domestic oil price used in the estimates for the years ended December 31, 2018, 2017 and 2016 was $61.57, $46.39 and $35.91 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2018, 2017 and 2016 was $1.21, $1.67 and $1.74 per Mcf, respectively. The average NGL price per barrel was $26.76, $21.16 and $10.57 for the same periods. Future income tax expenses have been computed considering applicable taxable cash flows, including historical tax basis and carry forwards (i.e. future deductions for taxable income calculations), and appropriate statutory tax rates. The discount rate of 10 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,
	2018		2017
	(Millions)
Future cash inflows	$	20,963	$	14,785
Less:
Future production costs	7,615		6,112
Future development costs	2,345		2,070
Future income tax provisions	1,366		408
Future net cash flows	9,637		6,195
Less 10 percent annual discount for estimated timing of cash flows	4,446		3,034
Standardized measure of discounted future net cash inflows	$	5,191	$	3,161

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

	For the years ended December 31,
	2018		2017		2016
	(Millions)
Beginning of year	$	3,161	$	1,038	$	1,284
Sales of oil and gas produced, net of operating costs	(1,541)		(894)		(458)
Net change in prices and production costs	2,004		1,385		(261)
Extensions, discoveries and improved recovery, less estimated future costs	1,341		816		735
Development costs incurred during year	654		345		142
Changes in estimated future development costs	(35)		105		(211)
Purchase of reserves in place, less estimated future costs	27		305		20
Sale of reserves in place, less estimated future costs	(409)		20		(253)
Revisions of previous quantity estimates	75		30		(78)
Accretion of discount	324		104		136
Net change in income taxes	(396)		(83)		—
Other	(14)		(10)		(18)
Net changes	2,030		2,123		(246)
End of year	$	5,191	$	3,161	$	1,038

XML

II-Valuation and Qualifying Accounts (Notes)

12 Months Ended

Dec. 31, 2018

II-Valuation and Qualifying Accounts [Abstract]

SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

	Beginning Balance		Charged (Credited) to Costs and Expenses		Other		Deductions		Ending Balance
2018:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	2	$	—	$	—	$	(2)	$	—
Deferred tax asset valuation(b)	195		18		—		—		213
Price-risk management credit reserves—liabilities(c)(d)	4		—		(4)		—		—
2017:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	3	$	—	$	—	$	(1)	$	2
Deferred tax asset valuation(b)(e)	151		44		—		—		195
Price-risk management credit reserves—liabilities(c)(d)	5		—		(1)		—		4
2016:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	6	$	—	$	—	$	(3)	$	3
Deferred tax asset valuation(b)	124		26		1		—		151
Price-risk management credit reserves—assets(a)(d)	1		—		(1)		—		—
Price-risk management credit reserves—liabilities(c)(d)	—		—		5		—		5

 __________

(a) Deducted from related assets.

(b) Deducted from related assets with a portion included in assets held for sale.

(c) Deducted from related liabilities.

(d) Included in revenues.

(e) Includes impact of the Tax Cuts and Jobs Act enacted rate reduction.

XML

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Description of Business and Basis of Presentation

Description of Business

Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3).

We had operations in the San Juan Basin which were sold in 2017 and 2018 that are reported in discontinued operations as discussed below. We also had other operations sold in 2016 which are reported as discontinued operations, as discussed below.

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

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. The Company has no other elements of comprehensive income (loss) other than net income (loss).

Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.

Discontinued operations

Discontinued Operations 

On January 30, 2018, we signed an agreement to sell our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC for $700 million (subject to closing and post-closing adjustments). This sale closed in March 2018. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million, a portion of which closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. The assets and liabilities were reclassified as held for sale on the Consolidated Balance Sheet as of December 31, 2017 and the results of operations of the San Juan Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3).

Our discontinued operations also include the results of previously owned properties in the Piceance Basin.

See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

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;

•valuation of deferred tax assets and liabilities;

•valuations of derivatives;

•estimation of oil and natural gas reserves; and

•assessments of litigation-related contingencies.

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 cashRestricted cash was approximately $15 million and $12 million as of December 31, 2018 and 2017, respectively, and is included in other current assets on the Consolidated Balance Sheets.

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. The following table presents a summary of inventories.

	Years ended December 31,
	2018		2017
	(Millions)
Material, supplies and other	$	46	$	29
Commodity production in storage	2		1
	$	48	$	30

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. 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 on the Consolidated Statements of Operations. 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 as unproved properties.

From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange in which commercial substance is established, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.

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.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. 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.

Certain gains and losses on derivative instruments included on 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 commodity management and for which we have not elected the normal purchases and normal sales exception;

•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 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.

Revenue Recognition

Product and commodity management revenues

Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.

Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.

Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Significant judgments related to revenue recognition include principal versus agent considerations.

We record revenue on a gross basis when we control a promised good or service before transferring it to a customer. We record

revenue on a net basis when we arrange for another company to provide the good or service. Determining the point and time when control of a product transfers to a customer requires significant judgment. Payment is typically due 30 to 45 days following delivery of product to our customers. Revenues from production 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 revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2018 and 2017 was insignificant.

Commodity management expenses

Commodity management expenses

Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million in 2016.

Income taxes

Income taxesWe 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. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.

Employee stock-based compensation

Employee stock-based compensation

Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Performance-based awards are tied to shareholder return over time relative to our peer group and are valued using a Monte Carlo method using measures of total shareholder return.

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 and awards (see Note 4).

Debt issuance costs

Debt issuance costsDebt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $35 million and $32 million as of December 31, 2018 and 2017, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets.

New Accounting Pronouncements and Changes in Accounting Principles

Recently Adopted Accounting Standards

The Company adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is 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. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at December 31, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are

wholly unsatisfied at the reporting period end. In addition, see Note 16 for receivables related to sales of oil, natural gas and related products and services.

We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $15 million, $12 million and $10 million as of December 31, 2018, 2017 and 2016, respectively.

We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.

We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.

New Accounting Pronouncements Not yet Adopted

Accounting Standards Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on review of the guidance and the Company’s current commitments, the Company believes it will be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and other arrangements. In 2018, we began the process of evaluating our contracts with components that may be subject to ASU 2016-02 and engaged a third party to assist with implementing the standard. In 2018 and 2019, we have implemented appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company is finalizing the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We believe the amounts recorded as right to use assets and lease payment liabilities will be less than $100 million.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to exclude from evaluation any land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. The amendments affect trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with and expected loss model for instruments measured at amortized cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.

XML

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Tables)

12 Months Ended

Dec. 31, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

The following table presents a summary of inventories.

	Years ended December 31,
	2018		2017
	(Millions)
Material, supplies and other	$	46	$	29
Commodity production in storage	2		1
	$	48	$	30

XML

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Discontinued operations [Abstract]

Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]

Summarized Results of Discontinued Operations

The following table presents the results of discontinued operations for the years presented.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Total revenues	$	75	$	291	$	279
Costs and expenses:
Depreciation, depletion and amortization	$	8	$	131	$	191
Lease and facility operating	7		50		63
Gathering, processing and transportation	12		70		113
Taxes other than income	5		23		19
Exploration	3		14		16
General and administrative	1		8		21
Accrual for contract obligations retained	—		5		—
Net (gain) loss—sales of assets and impairments	—		50		(217)
Accretion of liabilities related to contract obligations retained	6		6		2
Other—net(a)	5		(3)		7
Total costs and expenses	47		354		215
Operating income (loss)	28		(63)		64
Gain (loss) on sales of domestic assets	(148)		—		51
Income (loss) from discontinued operations before income taxes	(120)		(63)		115
Provision (benefit) for income taxes	(29)		(23)		44
Income (loss) from discontinued operations	$	(91)	$	(40)	$	71

 __________

(a) Includes severance tax refund received in 2017.

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,
	2017
	(Millions)
Assets classified as held for sale
Inventories	$	14
Properties and equipment, net (successful efforts method of accounting)	797
Total assets classified as held for sale on the Consolidated Balance Sheets	$	811
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	1
Accrued and other current liabilities	1
Total current liabilities	2
Asset retirement obligations	15
Other noncurrent liabilities	3
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	20

Schedule of Disposal Groups Including Discontinued Operations Cash Flows [Table Text Block]

Cash Flows Attributable to Discontinued Operations

In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Cash provided by operating activities(a)	$	44	$	143	$	102
Cash capital expenditures within investing activities	$	29	$	175	$	135

 __________

(a) Excluding income taxes and changes to working capital.

Cash Flows Attributable to Discontinued Operations

In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Cash provided by operating activities(a)	$	44	$	143	$	102
Cash capital expenditures within investing activities	$	29	$	175	$	135

 __________

(a) Excluding income taxes and changes to working capital.

XML

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

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

The following table summarizes the calculation of earnings per share.

	Years Ended December 31,
	2018		2017		2016
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	242	$	24	$	(672)
Less: Dividends on preferred stock	8		15		18
Less: Loss on induced conversion of preferred stock	—		—		22
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income (loss) per common share	$	234	$	9	$	(712)
Basic weighted-average shares	408.4		395.1		313.3
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	3.1		2.1		—
Stock options	0.2		0.2		—
Diluted weighted-average shares(a)	411.7		397.4		313.3
Income (loss) per common share from continuing operations:
Basic	$	0.57	$	0.02	$	(2.28)
Diluted	$	0.57	$	0.02	$	(2.28)

 __________

(a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:  

	Years Ended December 31,
	2018	2017	2016
	(Millions)
Weighted-average nonvested restricted stock units and awards	—	—	2.2
Weighted-average stock options	—	—	0.01
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)	11.4	19.8	23.8
Nonvested restricted stock units antidilutive under the treasury stock method	0.7	0.6	—

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, 2018, 2017 and 2016 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.

	December 31,
	2018		2017		2016
Options excluded (millions)	0.7		1.5		2.0
Weighted-average exercise price of options excluded	$	18.05	$	17.80	$	17.42
Exercise price range of options excluded	$16.46 - $21.81		$14.41 - $21.81		$14.41 - $21.81
Fourth quarter weighted-average market price	$	15.16	$	12.10	$	13.23

XML

Asset Sales, Impairments and Exploration Expenses (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Summary of exploration expenses

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Unproved leasehold property impairments, amortization and expiration	$	69	$	84	$	22
Geologic and geophysical costs	6		$	3	3
Impairments of exploratory area well costs and dry hole costs	—		—		1
Total exploration expenses	$	75	$	87	$	26

XML

Properties and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

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,
		2018		2017
		(Millions)
Proved properties	(b)	$	7,289	$	5,815
Unproved properties	(c)	1,891		2,194
Gathering, processing and other facilities	15-25	294		242
Construction in progress	(c)	350		305
Other	3-40	125		118
Total properties and equipment, at cost		9,949		8,674
Accumulated depreciation, depletion and amortization		(2,683)		(1,983)
Properties and equipment—net		$	7,266	$	6,691

__________

(a) Estimated useful lives are presented as of December 31, 2018.

(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 2018 and 2017 is presented below.

	2018		2017
	(Millions)
Balance, January 1	$	39	$	40
Liabilities incurred	8		5
Liabilities settled	(7)		(11)
Estimate revisions	30		3
Accretion expense(a)	2		2
Balance, December 31	$	72	$	39
Amount reflected as current	$	5	$	7

__________

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

XML

Accounts Payable and Accrued and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Payables and Accruals [Abstract]

Accounts Payable

Accounts Payable

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

	December 31,
	2018		2017
	(Millions)
Trade	$	130	$	120
Accrual for capital expenditures	190		151
Royalties	170		150
Cash overdrafts	17		—
Other	7		25
	$	514	$	446

Accrued and Other Current Liabilities

Accrued and other current liabilities

The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.

	December 31,
	2018		2017
	(Millions)
Taxes other than income taxes	$	19	$	14
Accrued interest	45		69
Compensation and benefit related accruals	39		39
Gathering and transportation	7		11
Gathering and transportation related to exited areas	30		53
Other, including other loss contingencies	38		23
	$	178	$	209

XML

Debt and Banking Arrangements Schedule of Long-term Debt Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt Instrument Redemption [Table Text Block]

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2018.  

Senior Note	Face Value (Millions)		Maturity Date	Interest Payment Dates	Optional Redemption Period(a)
6.000% Senior Notes due 2022 (the “2022 Notes”)	$	529	January 15, 2022	January 15, July 15	October 15, 2021
8.250% Senior Notes due 2023 (the “2023 Notes”)	$	500	August 1, 2023	February 1, August 1	June 1, 2023
5.250% Senior Notes due 2024 (the “2024 Notes”)	$	650	September 15, 2024	March 15, September 15	June 15, 2024
5.750% Senior Notes due 2026 (the “2026 Notes”)	$	500	June 1, 2026	June 1, December 1	June 1, 2021

 __________

(a) At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the 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 as more fully described in the indenture.

Schedule of Debt [Table Text Block]

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

	December 31,
	2018 (a)		2017 (a)
	(Millions)
Credit facility agreement	$	330	$	—
7.500% Senior Notes due 2020	—		350
6.000% Senior Notes due 2022	529		1,100
8.250% Senior Notes due 2023	500		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		—
Total debt	$	2,509	$	2,600
Less: Current portion of long-term debt	—		—
Total long-term debt	$	2,509	$	2,600
Less: Debt issuance costs(b)	24		25
Total long-term debt, net(b)	$	2,485	$	2,575

__________

(a) Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.

(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

XML

Provision (Benefit) for Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes from Continuing Operations

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

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Provision (benefit):
Current:
Federal	$	(38)	$	(18)	$	(26)
State	1		1		(7)
	(37)		(17)		(33)
Deferred:
Federal	107		(100)		(333)
State	4		(11)		6
	111		(111)		(327)
Total provision (benefit)	$	74	$	(128)	$	(360)

Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate

The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.

	Years Ended December 31,
	2018			2017			2016
	(Millions)
Federal Statutory Rate	21		%	35		%	35		%
Provision (benefit) at statutory rate	$	66		$	(36)		$	(361)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	(8)			(12)			(42)
Valuation allowance on current year state income taxes (net of federal   benefit)	17			17			18
Valuation allowance on state income taxes resulting from sale (net of   federal benefit)	—			—			8
Effective state income tax rate change (net of federal benefit)	(5)			(12)			15
Provisional impact of Tax Cuts and Jobs Act	—			(92)			—
Other	4			7			2
Provision (benefit) for income taxes	$	74		$	(128)		$	(360)

Significant Components of Deferred Tax Liabilities and Deferred Tax Assets

The following table includes significant components of deferred tax liabilities and deferred tax assets.

	December 31,
	2018		2017
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	797	$	792
Derivatives, net	33		—
Other, net	—		1
Total deferred tax liabilities	830		793
Deferred tax assets:
Accrued liabilities and other	137		79
Alternative minimum tax credits	40		78
Loss carryovers	665		672
Derivatives, net	—		42
Total deferred tax assets	842		871
Less: valuation allowance	213		195
Total net deferred tax assets	629		676
Net deferred tax liabilities	$	201	$	117

XML

Contingent Liabilities and Commitments (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitment Under Contracts

We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our oil and natural gas production and third-party purchases of oil and natural gas to other locations in an attempt to obtain more favorable pricing differentials. During 2017 and 2018, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. As of December 31, 2018, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:

	Midstream Services		Transportation		Total
	(Millions)
2019	$	55	$	115	$	170
2020	58		95		153
2021	48		68		116
2022	43		59		102
2023	40		47		87
Thereafter	68		352		420
Total commitments	$	312	$	736	$	1,048
Accrued liabilities	$	24	$	40	$	64

Future Minimum Annual Rentals Under Noncancelable Operating Leases

Future minimum annual rentals under noncancelable operating leases as of December 31, 2018, are payable as follows:

	(Millions)
2019	$	38
2020	37
2021	12
2022	3
2023	—
Thereafter	—
Total	$	90

XML

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Nonvested Restricted Stock Unit Activity and Related Information

Nonvested Restricted Stock Units and Awards

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2018.

Restricted Stock Units	Shares	Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2017	5.7	$	12.06
Granted	2.4	$	16.74
Forfeited	(0.1)	$	12.63
Vested	(2.6)	$	10.18
Nonvested at December 31, 2018	5.4	$	15.01

__________

(a) Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.

Share-based Compensation, Activity

Other restricted stock unit information

	2018		2017		2016
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	16.74	$	13.76	$	10.99
Total fair value of restricted stock units vested during the year (millions)	$	26	$	33	$	37

Summary of Stock Option Activity and Related Information

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2018.

Stock Options	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value
	(Millions)			(Years)	(Millions)
Outstanding at December 31, 2017	2.2	$	15.35		$	3
Granted	—	$	—
Exercised	(0.8)	$	12.35
Forfeited	(0.3)	$	20.19
Outstanding at December 31, 2018	1.1	$	16.00	2.2	$	0.3
Exercisable at December 31, 2018	1.1	$	16.00	2.2	$	0.3

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

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 approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

	December 31, 2018								December 31, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	175	$	3	$	178	$	—	$	59	$	—	$	59
Energy derivative liabilities	$	—	$	37	$	—	$	37	$	—	$	236	$	—	$	236
Total debt(a)	$	—	$	2,414	$	—	$	2,414	$	—	$	2,746	$	—	$	2,746

__________

(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,509 million and $2,600 million as of December 31, 2018 and 2017, respectively.

XML

Derivatives and Concentration of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives Related to 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, 2018.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	2019	Fixed Price Swaps	WTI	(38,000)	$	53.49
Crude Oil	2019	Basis Swaps	Midland/Cushing	(21,008)	$	(1.16)
Crude Oil	2019	Basis Swaps	Nymex CMA Roll	(20,000)	$	0.11
Crude Oil	2019	Basis Swaps	Magellan East Houston/Midland	(1,841)	$	8.12
Crude Oil	2019	Basis Swaps	Argus LLS/Midland	(838)	$	8.60
Crude Oil	2019	Fixed Price Calls	WTI	(5,000)	$	54.08
Crude Oil	2020	Basis Swaps	Midland/Cushing	(7,486)	$	(1.31)
Crude Oil	2020	Basis Swaps	Brent/WTI Spread	(5,000)	$	8.36
Crude Oil	2021	Basis Swaps	Brent/WTI Spread	(1,000)	$	8.00
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75
Natural Gas
Natural Gas	2019	Fixed Price Swaps	Henry Hub	(108)	$	3.07
Natural Gas	2019	Basis Swaps	Permian	(25)	$	(0.39)
Natural Gas	2019	Basis Swaps	Waha	(15)	$	2.94
Natural Gas	2019	Basis Swaps	Houston Ship Channel	(30)	$	(0.09)
Natural Gas	2020	Basis Swaps	Waha	(60)	$	(0.79)
Natural Gas	2021	Basis Swaps	Waha	(70)	$	(0.59)
Natural Gas	2022	Basis Swaps	Waha	(70)	$	(0.57)
Natural Gas	2023	Basis Swaps	Waha	(70)	$	(0.51)

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread.

(b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.

(c) The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.

DerivativeGainLoss [Table Text Block]

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

	Years Ended December 31,
	2018		2017		2016
	(Millions)
Gain (loss) from derivatives related to production(a)	$	78	$	3	$	(207)
Gain (loss) from derivatives related to physical marketing agreements(b)	3		—		—
Net gain (loss) on derivatives	$	81	$	3	$	(207)

__________

(a) Includes payments totaling $237 million for the year ended December 31, 2018 and settlements totaling $4 million and $301 million for the years ended December 31, 2017 and 2016, respectively.

(b) Includes payments totaling less than $1 million for the years ended December 31, 2018 and 2017 and settlements totaling  $1 million for the year ended December 31, 2016.

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)		Net Amount
December 31, 2018	(Millions)
Derivative assets with right of offset or master netting agreements	$	178	$	(37)	$	141
Derivative liabilities with right of offset or master netting agreements	$	(37)	$	37	$	—
December 31, 2017
Derivative assets with right of offset or master netting agreements	$	59	$	(42)	$	17
Derivative liabilities with right of offset or master netting agreements	$	(236)	$	42	$	(194)

__________

(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 dates indicated below. 

	December 31,
	2018		2017
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	269	$	251
Joint interest owners	98		54
Income tax receivable	38		—
Other	—		2
Total	$	405	$	307

Schedules of Concentration of Risk, by Risk Factor

The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. 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.

	Year ended December 31,
	2018	2017	2016
United Energy Trading LLC	23%	(a)	(a)
Occidental Energy Marketing	16%	(a)	(a)
Crestwood Midstream Partners LP	(a)	21%	(a)
St. Paul Refining	(a)	16%	13%
NGL Crude Logistics	14%	13%	(a)
Delek Refining, Ltd	(a)	10%	(a)
Plains Marketing	(a)	(a)	15%

__________

(a) Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives.

XML

Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data

Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2018	(Millions, except per-share amounts)
Product revenues	$	407	$	520	$	554	$	544
Net gain (loss) on derivatives	$	(69)	$	(154)	$	(139)	$	443
Commodity management	$	36	$	64	$	68	$	36
Total revenues	$	374	$	430	$	484	$	1,022
Operating costs and expenses	$	322	$	388	$	413	$	447
Operating income	$	52	$	42	$	71	$	575
Income (loss) from continuing operations	$	(26)	$	(79)	$	(6)	$	353
Loss from discontinued operations	(89)		(2)		(1)		1
Net income (loss)	$	(115)	$	(81)	$	(7)	$	354
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	(30)	$	(83)	$	(6)	$	353
Loss from discontinued operations	(89)		(2)		(1)		1
Net income (loss)	$	(119)	$	(85)	$	(7)	$	354
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.07)	$	(0.21)	$	(0.01)	$	0.84
Loss from discontinued operations	(0.23)		—		—		—
Net income (loss)	$	(0.30)	$	(0.21)	$	(0.01)	$	0.84
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.07)	$	(0.21)	$	(0.01)	$	0.83
Loss from discontinued operations	(0.23)		—		—		—
Net income (loss)	$	(0.30)	$	(0.21)	$	(0.01)	$	0.83
2017
Product revenues	$	187	$	226	$	247	$	356
Net gain (loss) on derivatives	$	203	$	116	$	(106)	$	(210)
Commodity management	$	5	$	8	$	4	$	8
Total revenues	$	395	$	350	$	145	$	155
Operating costs and expenses	$	208	$	231	$	223	$	265
Operating income (loss)	$	187	$	119	$	(78)	$	(110)
Income (loss) from continuing operations	$	95	$	327	$	(378)	$	(20)
Income (loss) from discontinued operations	(3)		(251)		232		(18)
Net income (loss)	$	92	$	76	$	(146)	$	(38)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	91	$	323	$	(381)	$	(24)
Income (loss) from discontinued operations	(3)		(251)		232		(18)
Net income (loss)	$	88	$	72	$	(149)	$	(42)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.24	$	0.81	$	(0.96)	$	(0.06)
Income (loss) from discontinued operations	(0.01)		(0.63)		0.58		(0.04)
Net income (loss)	$	0.23	$	0.18	$	(0.38)	$	(0.10)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.23	$	0.77	$	(0.96)	$	(0.06)
Income (loss) from discontinued operations	(0.01)		(0.60)		0.58		(0.04)
Net income (loss)	$	0.22	$	0.17	$	(0.38)	$	(0.10)

XML

Supplemental Oil and Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Capitalized Costs

Capitalized Costs

	As of December 31,
	2018		2017
	(Millions)
Proved Properties	$	7,612	$	6,113
Unproved properties	1,891		2,194
	9,503		8,307
Accumulated depreciation, depletion and amortization and valuation provisions	(2,542)		(1,860)
Net capitalized costs	$	6,961	$	6,447

__________

•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $276 million and $223 million, net, as of December 31, 2018 and 2017, 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

Cost Incurred

	For the years ended December 31,
	2018		2017		2016
	(Millions)
Acquisition	$	68	$	864	$	84
Exploration	7		5		5
Development	1,350		1,048		471
	$	1,425	$	1,917	$	560

__________

•Costs incurred include capitalized and expensed items.

•Acquisition costs are as follows: Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) in March 2017 that included $195 million and 23.8 MMboe of proved developed reserves and facilities. Costs in 2016 primarily relates to purchases of additional acreage in the Delaware Basin and included approximately 2.5 MMboe of proved reserves.

•Exploration costs include 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. Development costs associated with our San Juan Basin and Piceance Basin operations were $24 million, $168 million and $102 million for 2018, 2017 and 2016, respectively.

Proved Reserves

The following is a summary of changes in our proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations.

	Oil (MMbbls)	Natural Gas (Bcf)	NGLs (MMbbls)	All Products (MMboe)
Proved reserves at December 31, 2015	142.7	2,190.2	75.3	583.0
Revisions	(3.8)	(50.2)	(2.9)	(15.2)
Purchases	1.6	4.4	0.4	2.8
Divestitures	(5.5)	(1,505.9)	(38.3)	(294.8)
Extensions and discoveries	54.9	214.6	19.8	110.5
Production	(15.3)	(118.6)	(4.8)	(39.9)
Proved reserves at December 31, 2016	174.6	734.5	49.5	346.4
Revisions	4.7	(8.4)	(1.1)	2.3
Purchases	21.8	58.8	7.8	39.4
Divestitures	(1.7)	(312.5)	(0.8)	(54.6)
Extensions and discoveries	86.7	194.5	23.6	142.7
Production	(22.4)	(75.9)	(5.0)	(40.0)
Proved reserves at December 31, 2017	263.7	591.0	74.0	436.2
Revisions	—	(11.4)	5.3	3.4
Purchases	1.5	4.8	0.6	2.9
Divestitures	(27.6)	(79.8)	(10.4)	(51.3)
Extensions and discoveries	84.5	176.9	22.7	136.7
Production	(30.8)	(63.8)	(7.2)	(48.6)
Proved reserves at December 31, 2018	291.3	617.7	85.0	479.3
Proved developed reserves:
December 31, 2016	84.4	440.2	24.1	181.8
December 31, 2017	130.3	321.2	38.8	222.7
December 31, 2018	156.4	365.4	48.4	265.8
Proved undeveloped reserves:
December 31, 2016	90.2	294.2	25.4	164.6
December 31, 2017	133.4	269.8	35.2	213.5
December 31, 2018	134.9	252.3	36.6	213.5

__________

•Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.

•Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells. Revisions in 2016 primarily reflect 49 MMboe of negative revisions due to the decrease in the 12-month average price partially offset by 34 MMboe of positive revisions due to decreased costs and well improvements.

•Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed.

•Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves. Divestitures in 2016 relate to the sale of the Piceance Basin which included proved developed reserves and proved undeveloped reserves of 222 MMboe and 67 MMboe, respectively.

•Extensions and discoveries in 2018 reflect 52 MMboe added for proved developed locations and 85 MMboe of proved undeveloped locations. Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins. Extensions and discoveries in 2016 reflect 26 MMboe added for proved developed locations and 84 MMboe for proved undeveloped locations primarily in the Delaware Basin.

Standardized Measure of Discounted Future Net Cash Flows

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2018		2017
	(Millions)
Future cash inflows	$	20,963	$	14,785
Less:
Future production costs	7,615		6,112
Future development costs	2,345		2,070
Future income tax provisions	1,366		408
Future net cash flows	9,637		6,195
Less 10 percent annual discount for estimated timing of cash flows	4,446		3,034
Standardized measure of discounted future net cash inflows	$	5,191	$	3,161

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,
	2018		2017		2016
	(Millions)
Beginning of year	$	3,161	$	1,038	$	1,284
Sales of oil and gas produced, net of operating costs	(1,541)		(894)		(458)
Net change in prices and production costs	2,004		1,385		(261)
Extensions, discoveries and improved recovery, less estimated future costs	1,341		816		735
Development costs incurred during year	654		345		142
Changes in estimated future development costs	(35)		105		(211)
Purchase of reserves in place, less estimated future costs	27		305		20
Sale of reserves in place, less estimated future costs	(409)		20		(253)
Revisions of previous quantity estimates	75		30		(78)
Accretion of discount	324		104		136
Net change in income taxes	(396)		(83)		—
Other	(14)		(10)		(18)
Net changes	2,030		2,123		(246)
End of year	$	5,191	$	3,161	$	1,038

XML

Schedule II - valuation and qualifying accounts schedule II (Tables)

12 Months Ended

Dec. 31, 2018

SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]

Summary of Valuation Allowance [Table Text Block]

	Beginning Balance		Charged (Credited) to Costs and Expenses		Other		Deductions		Ending Balance
2018:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	2	$	—	$	—	$	(2)	$	—
Deferred tax asset valuation(b)	195		18		—		—		213
Price-risk management credit reserves—liabilities(c)(d)	4		—		(4)		—		—
2017:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	3	$	—	$	—	$	(1)	$	2
Deferred tax asset valuation(b)(e)	151		44		—		—		195
Price-risk management credit reserves—liabilities(c)(d)	5		—		(1)		—		4
2016:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	6	$	—	$	—	$	(3)	$	3
Deferred tax asset valuation(b)	124		26		1		—		151
Price-risk management credit reserves—assets(a)(d)	1		—		(1)		—		—
Price-risk management credit reserves—liabilities(c)(d)	—		—		5		—		5

 __________

(a) Deducted from related assets.

(b) Deducted from related assets with a portion included in assets held for sale.

(c) Deducted from related liabilities.

(d) Included in revenues.

(e) Includes impact of the Tax Cuts and Jobs Act enacted rate reduction.

XML

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2016	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2017
Description of business [Line Items]
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%
Restricted Cash	$ 15	$ 10			$ 12
Charges for unutilized transportation capacity included in gas management expenses		$ 27
Debt Issuance Costs, Noncurrent, Net	$ 35				$ 32
Restricted Stock Units
Description of business [Line Items]
Award vesting period	3 years
San Juan Gallup [Member]
Description of business [Line Items]
Disposal Group, Including Discontinued Operation, Consideration				$ 700
San Juan Legacy [Member]
Description of business [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	$ 169
Subsequent Event [Member]
Description of business [Line Items]
Right of use assets and lease payment liabilities expected after adoption of lease standard			$ 100

XML

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Inventory [Line Items]
Materials, Supplies, and Other	$ 46	$ 29
Other Inventory, in Transit, Gross	2	1
Inventories	$ 48	$ 30

XML

Acquisition (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017 USD ($) a Boe Well	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Costs incurred, oil and gas property acquisition, exploration, and development activities		$ 1,425	$ 1,917	$ 560
Panther [Member]
Business Acquisition [Line Items]
Costs incurred, oil and gas property acquisition, exploration, and development activities	$ 775		798
Productive Oil Wells, Number of Wells, Gross | Well	25
Productive Oil Wells, Number of Wells with Multiple Completions, Gross	18
Wells in Process of Drilling	3
Gas and Oil Area, Developed, Net | a	18,000
Gas and Oil Area, Undeveloped, Gross | a	900
Costs Incurred, Acquisition of Unproved Oil and Gas Properties			599
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves			$ 200
Production, Barrels of Oil Equivalents | Boe	10,000

XML

Discontinued Operations - Additional Information (Detail) - USD ($) $ in Millions		3 Months Ended				12 Months Ended
		Mar. 31, 2018	Sep. 30, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation						$ 1,048
Impairment of Oil and Gas Properties			$ 60
Disposal group contract obligation expense						0	$ 5	$ 0
Derivatives, Determination of Fair Value	[1]					37	42
Increase (Decrease) in Other Accrued Liabilities						(47)	(53)	(53)
San Juan [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration				$ 309				309
Gain (Loss) on Disposition of Proved Property				18	$ 199
Deferred Gain on Sale of Property							3
San Juan Legacy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Proved Property							$ 2
San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved Reserves Percentage							12.00%
Gain (Loss) on Disposition of Proved Property		$ 138
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax		147
Piceance Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses								862
Disposal Group, Including Discontinued Operation, Consideration				910				910
Disposal group contract obligation expense								104
Derivatives, Determination of Fair Value				48				48
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax								(52)
DisposalGroupOperatingTaxRefund			$ 10				$ 10
Gathering and Treating [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation		309
Guarantee Type, Other [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation		9
San Juan Legacy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration						$ 169
San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		700
Percentage of Production by product							16.00%
Cash [Member] | San Juan [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration				285				285
Cash [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration		$ 667
Commitments [Member] | San Juan [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration				$ 24				$ 24

[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.

XML

Discontinued Operations - Summarized Results of Discontinued Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue									$ 75	$ 291		$ 279
Disposal Group, Including Discontinued Operation, Depreciation and Amortization									8	131		191
Disposal Group, Including Discontinued Operation, Lease Operating Expense									7	50		63
Disposal Group Including Discontinued Operation Gathering and Transportation Expense									12	70		113
Disposal Group, Including Discontinued Operation Taxes other than income									5	23		19
Disposal Group Including Discontinued Operation Exploration Expense									3	14		16
Disposal Group, Including Discontinued Operation, General and Administrative Expense									1	8		21
Disposal group contract obligation expense									0	5		0
Disposal Group (gain) loss on sale of Assets and Impairment charges									0	50		(217)
Accretion Expense									6	6		2
Disposal Group, Including Discontinued Operation, Other Expense									5	(3)	[1]	7
Disposal Group, Including Discontinued Operation, Operating Expense									47	354		215
Disposal Group, Including Discontinued Operation, Operating Income (Loss)									28	(63)		64
Disposal Group Including Discontinued Operation Income before Tax									(120)	(63)		115
Discontinued Operation, Tax Effect of Discontinued Operation									(29)	(23)		44
Income (loss) from discontinued operations	$ 1	$ (1)	$ (2)	$ (89)	$ (18)	$ 232	$ (251)	$ (3)	(91)	(40)		71
Domestic
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax									$ (148)	$ 0		$ 51

[1] Includes severance tax refund received in 2017.

XML

Discontinued Operations Discontinued Operations - Balance Sheet (Details) $ in Millions	Dec. 31, 2017 USD ($)
Discontinued Operations and Disposal Groups [Abstract]
Disposal Group, Including Discontinued Operation, Inventory	$ 14
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	797
Disposal Group, Including Discontinued Operation, Assets	811
Disposal Group, Including Discontinued Operation, Accounts Payable	1
Disposal Group, Including Discontinued Operation, Accrued Liabilities	1
Disposal Group, Including Discontinued Operation, Accounts Payable and Accrued Liabilities, Current	2
Disposal Group Asset Retirement Obligation Noncurrent	15
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent	3
Liabilities associated with assets held for sale, Current	$ 20

XML

Discontinued Operations Discontinued Operations Cash Flow (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash Provided by (Used in) Operating Activities, Discontinued Operations	[1]	$ 44	$ 143	$ 102
Capital Expenditure, Discontinued Operations		$ 29	$ 175	$ 135

[1] (a) Excluding income taxes and changes to working capital.

XML

Earnings (Loss) Per Common Share from Continuing Operations (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (loss) from continuing operations attributable to parent including preferred dividends										$ 242	$ 24	$ (672)
Preferred stock dividends, income statement impact										8	15	18
Preferred stock conversions, inducements										0	0	22
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income (loss) per common share		$ 353	$ (6)	$ (83)	$ (30)	$ (24)	$ (381)	$ 323	$ 91	$ 234	$ 9	$ (712)
Basic weighted-average shares										408.4	395.1	313.3
Diluted weighted-average shares(a)	[1]									411.7	397.4	313.3
Income (loss) per common share from continuing operations:
Basic (in dollars per share)		$ 0.84	$ (0.01)	$ (0.21)	$ (0.07)	$ (0.06)	$ (0.96)	$ 0.81	$ 0.24	$ 0.57	$ 0.02	$ (2.28)
Diluted (in dollars per share)		$ 0.83	$ (0.01)	$ (0.21)	$ (0.07)	$ (0.06)	$ (0.96)	$ 0.77	$ 0.23	$ 0.57	$ 0.02	$ (2.28)
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										3.1	2.1
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										0.2	0.2

[1] Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:   Years Ended December 31,201820172016(Millions)Weighted-average nonvested restricted stock units and awards — — 2.2 Weighted-average stock options— — 0.01  Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14) 11.4 19.8 23.8  Nonvested restricted stock units antidilutive under the treasury stock method 0.7 0.6 — 

XML

Earnings (Loss) Per Common Share from Continuing Operations - (Details1) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average exercise price of options excluded	$ 18.05	$ 17.80	$ 17.42
Exercise price range of options excluded, upper limit	21.81	21.81	21.81
Exercise price range of options excluded, lower limit	16.46	14.41	11.46
Fourth quarter weighted-average market price	$ 15.16	$ 12.10	$ 13.23
Restricted Stock Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements			2,200
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	700	600	0
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements			10
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	700	1,500	2,000
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock	11,400	19,800	23,800

XML

Asset Sales, Impairments and Exploration Expenses - Significant Adjustments (Detail) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Payments for (Proceeds from) Investments				$ 0	$ 0	$ 238
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax						$ (238)
Permian [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Gain (Loss) on Disposition of Proved Property	$ 11	$ 111	$ 31		103
Other Property
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Gain (Loss) on Disposition of Proved Property					8
Type of Arrangement [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Gain (Loss) on Disposition of Proved Property					$ 48

XML

Asset Sales, Impairments and Exploration Expenses - Summary of Exploration Expenses (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations for Oil and Gas Producing Activities [Line Items]
Unproved leasehold property impairments, amortization and expiration	$ 69	$ 84	$ 22
Geologic And Geophysical Costs	6	3	3
Results of Operations, Dry Hole Costs	0	0	1
Exploration Expense	$ 75	$ 87	$ 26

XML

Investments (Details) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2017 USD ($)	Dec. 31, 2018 USD ($) a	Dec. 31, 2017 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Liabilities		$ 346	$ 349
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities		$ 336
Catalyst
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Cash Contribution From Partner In Joint Venture	$ 300
Capital Expenditures To Be Paid By Joint Venture Partner	$ 263
Legal Fees			11
Property Contributed To Joint Venture			53
Cash Contribution From Partner In Joint Venture At Closing			439
Capital Expenditure Carry From Partner In Joint Venture			139
Capital Expenditure Reimbursement Received From Joint Venture			49
Distribution Received From Joint Venture			300
Oil and Gas Acreage Dedication For Joint Venture | a		50,000
Equity Method Investments		$ 58	$ 64
Oryxx II Pipeline
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments		$ 93
Minimum
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		12.50%
Minimum | Oryxx II Pipeline
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments		$ 23
Maximum
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		25.00%

XML

Properties and Equipment - Carried at Cost (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost		$ 9,949	$ 8,674
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		2,683	1,983
Properties and equipment-net		7,266	6,691
Proved properties
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1],[2]	7,289	5,815
Unproved Properties
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1],[3]	1,891	2,194
Gathering, Processing and Other Facilities
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1]	$ 294	242
Gathering, Processing and Other Facilities | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	15 years
Gathering, Processing and Other Facilities | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	25 years
Construction in Progress
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1],[3]	$ 350	305
Other
Property, Plant and Equipment [Line Items]
Properties and equipment-net, at cost	[1]	$ 125	$ 118
Other | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	3 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful life (years)	[1]	40 years

[1] Estimated useful lives are presented as of December 31, 2018.

[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.

XML

Properties and Equipment - Rollforward Asset Retirement Obligation (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance		$ 39	$ 40
Liabilities incurred during the period		8	5
Liabilities settled during the period		(7)	(11)
Estimate revisions		30	3
Accretion expense	[1]	2	2
Ending Balance		72	39
Amount reflected as current		$ 5	$ 7

[1] Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

XML

Accounts Payable and Accrued and Other Current Liabilities - Accounts Payable (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Trade	$ 130	$ 120
Accrual for capital expenditures	190	151
Royalty Payable	170	150
Cash Overdrafts	17	0
Other	7	25
Accounts payable	$ 514	$ 446

XML

Accounts Payable and Accrued and Other Current Liabilities - Accrued and Other Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Accrual for Taxes Other than Income Taxes, Current	$ 19	$ 14
Interest Payable, Current	45	69
Accrued Compensation And Related Liabilities Current	39	39
Gathering and transportation	7	11
Gathering and transportation related to exited areas	30	53
Other Accrued Liabilities, Current	38	23
Accrued liabilities and other liabilities	$ 178	$ 209

XML

Debt and Banking Arrangements - Debt (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total debt		$ 2,509	$ 2,600
Debt and Capital Lease Obligations	[1]	2,509	2,600
Debt, Current		0	0
Long-term Debt, Excluding Current Maturities		2,509	2,600
Debt Issuance Costs, Net		24	25
Long-term debt and capital lease obligations	[2]	2,485	2,575
Interest Paid, Including Capitalized Interest, Operating and Investing Activities		157	178	$ 194
Credit Facility Agreement
Debt Instrument [Line Items]
Total debt	[1]	330	0
7.500% Senior Notes due 2020
Debt Instrument [Line Items]
Total debt	[1]	0	350
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Total debt	[1]	529	1,100
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Total debt	[1]	500	500
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Total debt	[1]	650	650
5.750% Senior Notes Due 2026
Debt Instrument [Line Items]
Total debt	[1]	$ 500	$ 0

[1] Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.

[2] Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.

XML

Debt and Banking Arrangements - Debt - Additional Information (Detail) $ in Millions		3 Months Ended		12 Months Ended
		Jun. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
Write off of Deferred Debt Issuance Cost		$ 6.0
Gain (Loss) on Extinguishment of Debt, before Write off of Debt Issuance Cost		(63.0)
Debt Instrument, Repurchase Amount		921.0
Maximum Limit On Consolidated Secure Indebtedness to Consolidated EBITDAX				4.25
Minimum Current Ratio				1.0
Gain (Loss) on Extinguishment of Debt		(71.0)	$ (17.0)	$ (71.0)	$ (17.0)	$ (1.0)
Debt redemption price as percentage of principal amount				100.00%
Percentage of repurchase of notes on principal amount of notes				101.00%
Total debt				$ 2,509.0	$ 2,600.0
Letters of credit issued				$ 52.0
7.500% Senior Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount		350.0	$ 150.0
Debt instrument stated interest rate			7.50%	7.50%	7.50%
Total debt	[1]			$ 0.0	$ 350.0
Credit Facility Agreement
Debt Instrument [Line Items]
Total debt	[1]			330.0	$ 0.0
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount		571.0
Debt Instrument, Face Amount				$ 529.0
Debt instrument stated interest rate				6.00%	6.00%
Total debt	[1]			$ 529.0	$ 1,100.0
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 500.0
Debt instrument stated interest rate				8.25%	8.25%
Total debt	[1]			$ 500.0	$ 500.0
5.250 % Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 150.0	$ 650.0
Debt instrument stated interest rate			5.25%	5.25%	5.25%
Total debt	[1]			$ 650.0	$ 650.0
5.750% Senior Notes Due 2026
Debt Instrument [Line Items]
Debt Issuance Costs, Gross		1.0
Proceeds from Issuance of Debt		494.0
Debt Instrument, Face Amount		$ 500.0		$ 500.0
Debt instrument stated interest rate		5.75%		5.75%	5.75%
Total debt	[1]			$ 500.0	$ 0.0
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Subjective Acceleration Clause				subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,500.0
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases		$ 1,800.0		$ 2,000.0

[1] Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.

XML

Provision (Benefit) for Income Taxes - Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal	$ (38)	$ (18)	$ (26)
State	1	1	(7)
Total current	(37)	(17)	(33)
Deferred:
Federal	107	(100)	(333)
State	4	(11)	6
Total Deferred	111	(111)	(327)
Total provision (benefit)	$ 74	$ (128)	$ (360)

XML

Provision (Benefit) for Income Taxes - Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Provision (benefit) at statutory rate		$ 66	$ (36)	$ (361)
Increases (decreases) in taxes resulting from:
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%	35.00%
State income taxes (net of federal benefit)		$ (8)	$ (12)	$ (42)
Valuation allowance on current year state income taxes (net of federal benefit)		17	17	18
Valuation allowance on state income taxes resulting from sale (net of federal benefit)		0	0	8
Effective state income tax rate change (net of federal benefit)		(5)	(12)	15
IncomeTaxReconciliationChangeInStatutoryTaxRate	$ (92)	0	(92)	0
Other		4	7	2
Total provision (benefit)		$ 74	$ (128)	$ (360)

XML

Provision (Benefit) for Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Provision For Income Taxes [Line Items]
Income Taxes Receivable	$ 38	$ 0
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount			$ 8
Proceeds from Income Tax Refunds		39
Income Taxes Paid	2		21
Deferred Other Tax Expense (Benefit)	(5)	(12)	$ 15
Deferred Tax Assets, Capital Loss Carryforwards	$ 48
Operating Loss Carryforwards, Limitations on Use	50 percent
Income Tax Examination, Penalties and Interest Accrued	$ 1
Unrecognized Tax Benefits	8
Deferred Tax Assets, Tax Credit Carryforwards, Other	$ 7
Uncertain tax position expiration period	12 months
Domestic Tax Authority [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards	$ 2,021
State and Local Jurisdiction [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards	$ 4,100	$ 3,800
Percentage Deferred Tax Assets Operating Loss Carryforwards State That Expire	99.00%
RKI [Member] | Domestic Tax Authority [Member]
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards	$ 353
Maximum
Provision For Income Taxes [Line Items]
Operating Loss Carryforwards, Limitations on Use	three

XML

Provision (Benefit) for Income Taxes - Significant Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred tax liabilities:
Properties and equipment	$ 797	$ 792
Deferred tax liabilities, Derivatives, net	33	0
Other, net	0	1
Deferred Tax Liabilities, Gross	830	793
Deferred tax assets:
Accrued liabilities and other	137	79
Alternative minimum tax credits	40	78
Loss carryovers	665	672
Deferred tax assets, Derivatives, net	0	42
Total deferred tax assets	842	871
Less: valuation allowance	213	195
Total net deferred tax assets	629	676
Deferred Tax Liabilities, Net	$ 201	$ 117

XML

Contingent Liabilities and Commitments - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Service commitment period	7 years
Total rent expenses	$ 25	$ 19	$ 23
Royalty Litigation
Loss Contingencies [Line Items]
Loss contingencies associated with royalty litigation	$ 11	$ 11

XML

Contingent Liabilities and Commitments - Commitments Under Contracts (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Long-term Purchase Commitment [Line Items]
2019	$ 170
2020	153
2021	116
2022	102
2023	87
Thereafter	420
Total	1,048
Other Liabilities	64
Gas Transportation and Storage [Member]
Long-term Purchase Commitment [Line Items]
2019	115
2020	95
2021	68
2022	59
2023	47
Thereafter	352
Total	736
Other Liabilities	40
Midstream Services [Member]
Long-term Purchase Commitment [Line Items]
2019	55
2020	58
2021	48
2022	43
2023	40
Thereafter	68
Total	312
Other Liabilities	$ 24

XML

Contingent Liabilities and Commitments - Future Minimum Annual Rentals Under Noncancelable Operating Leases (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 38
2020	37
2021	12
2022	3
2023	0
Thereafter	0
Total	$ 90

XML

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer contribution	$ 10	$ 11	$ 13
Postretirement Defined Benefit Plans, Liabilities	$ 7	$ 7
Maximum
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer matching percentage	6.00%
If employees are under age 40 [Member]
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer matching percentage	6.00%
If employees are 40 years or older [Member]
Employee Benefit And Retirement Plans [Line Items]
Defined contribution plan, employer matching percentage	8.00%

XML

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized stock based compensation	$ 40,000
Unrecognized stock based compensation, weighted average period of recognition	2 years 7 months 6 days
Value of stock option exercised during year	$ 4,300	$ 224	$ 160
Cash received from stock option exercises	9,200	400	400
Administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock based compensation expense	$ 32,000	$ 28,000	$ 31,000
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance based share granted, percent of nonvested restricted stock units outstanding	36.00%
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized	7,400
Shares reserved for issuance	18,000
Shares available for future grants	12,000
Employee stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized	750
Discount allowed on employee stock purchase plan	15.00%
Number of share purchased under stock option plan	97
Stock option plan, average purchase price	$ 10.74
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of vested shares of original grant amount	0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of vested shares of original grant amount	200.00%
Maximum | Employee stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	1,000

XML

Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Detail) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) $ / shares shares
Weighted Average Exercise Price
Average remaining contractual life exercisable	2 years 2 months 12 days
Average remaining contractual life outstanding	2 years 2 months 12 days
Beginning balance (in dollars per share) | $ / shares	$ 15.35
Granted (in dollars per share) | $ / shares	0
Exercised (in dollars per share) | $ / shares	12.35
Forfeited (in dollars per share) | $ / shares	20.19
Ending balance (in dollars per share) | $ / shares	16.00
Exercisable at end of period (in dollars per share) | $ / shares	$ 16.00
Option Outstanding
Beginning balance (in shares) | shares	2.2
Granted (in shares) | shares	0.0
Exercised (in shares) | shares	0.8
Forfeited (in shares) | shares	0.3
Ending balance (in shares) | shares	1.1
Exercisable at end of period (in shares) | shares	1.1
Aggregate Intrinsic Value
Beginning balance | $	$ 3.0
Ending balance | $	0.3
Exercisable at end of period | $	$ 0.3

XML

Stock-Based Compensation - Summary of Nonvested Restricted Stock Unit Activity and Related Information (Detail) shares in Millions	12 Months Ended
	Dec. 31, 2018 $ / shares shares
Nonvested Shares
Beginning Balance | shares	5.7
Granted | shares	2.4
Forfeited | shares	(0.1)
Vested | shares	(2.6)
Ending balance | shares	5.4
Weighted-Average Fair Value
Beginning Balance | $ / shares	$ 12.06	[1]
Granted | $ / shares	16.74	[1]
Forfeited | $ / shares	12.63	[1]
Vested | $ / shares	10.18	[1]
Ending Balance | $ / shares	$ 15.01	[1]

[1] Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.

XML

Stock-Based Compensation - Other Restricted Stock Unit (Detail) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	[1]	$ 16.74
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		$ 16.74	$ 13.76	$ 10.99
Total fair value of restricted stock units vested during the year (millions)		$ 26	$ 33	$ 37

[1] Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.

XML

Stockholders' Equity - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 06, 2016
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Preferred stock, shares issued				7,000,000
Preferred stock, par value	$ 0.01	$ 0.01		$ 0.01
Proceeds from common stock	$ 10,000,000	$ 672,000,000	$ 540,000,000
Preferred Stock, Liquidation Preference, Value				$ 50
Common stock, par value	$ 0.01	$ 0.01
Preferred stock conversions, inducements	$ 0	$ 0	22,000,000
Payments for Repurchase of Redeemable Convertible Preferred Stock	$ 0	$ 0	$ 10,000,000
Preferred stock, shares outstanding	0	4,800,000	4,800,000
Preferred Stock
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Proceeds from preferred stock				$ 350,000,000
Conversion of Stock, Shares Converted	4,800,000		2,200,000
Common Stock
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Stock Issued During Period, Shares, New Issues		51,675,000	56,925,000
Proceeds from common stock		$ 670,000,000	$ 538,000,000
Sale of Stock, Price Per Share		$ 12.97			$ 9.47
Conversion of Stock, Shares Issued	19,800,000		10,200,000
Over-Allotment Option [Member] | Common Stock
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
Stock Issued During Period, Shares, New Issues		6,675,000	7,425,000

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	$ 2,414	$ 2,746
Long-term Debt		2,509	2,600
Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		178	59
Energy derivative liabilities		37	236
Level 1 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		0	0
Energy derivative liabilities		0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	2,414	2,746
Level 2 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		175	59
Energy derivative liabilities		37	236
Level 3 | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets		3	0
Energy derivative liabilities		$ 0	$ 0

[1] The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,509 million and $2,600 million as of December 31, 2018 and 2017, respectively.

XML

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	3 Months Ended			12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties		$ 60
Permian [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain (Loss) on Disposition of Proved Property	$ 11	$ 111	$ 31		$ 103
Fair Value of Leasehold Exchanges				$ 200
Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets	59			178	59
Energy Related Derivative | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Energy derivative assets	$ 0			$ 3	$ 0

XML

Derivatives and Concentration of Credit Risk - Derivatives related to production (Detail) - Derivatives related to production - Short Position [Member] BTU / d in Thousands	12 Months Ended
	Dec. 31, 2018 BTU / d bbl / d $ / MMBtu $ / bbl
Price Risk Derivative [Member] | 2019 [Member] | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(38,000)
Underlying, Derivative Energy Measure | $ / bbl	53.49
Price Risk Derivative [Member] | 2019 [Member] | Natural Gas | Henry Hub
Derivative [Line Items]
Notional Volume | BTU / d	(108)
Underlying, Derivative Energy Measure | $ / MMBtu	3.07
Basis Swap [Member] | 2019 [Member] | Crude Oil [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(21,008)
Underlying, Derivative | $ / bbl	(1.16)
Basis Swap [Member] | 2019 [Member] | Crude Oil [Member] | Nymex [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(20,000)
Underlying, Derivative Energy Measure | $ / bbl	0.11
Basis Swap [Member] | 2019 [Member] | Crude Oil [Member] | Magellan East Houston/Midland [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,841)
Underlying, Derivative Energy Measure | $ / bbl	8.12
Basis Swap [Member] | 2019 [Member] | Crude Oil [Member] | Argus LLS/Midland [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(838)
Underlying, Derivative Energy Measure | $ / bbl	8.60
Basis Swap [Member] | 2019 [Member] | Natural Gas | Permian [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(25)
Underlying, Derivative | $ / MMBtu	(0.39)
Basis Swap [Member] | 2019 [Member] | Natural Gas | Houston Ship [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(30)
Underlying, Derivative | $ / MMBtu	(0.09)
Basis Swap [Member] | 2019 [Member] | Natural Gas | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(15)
Underlying, Derivative Energy Measure | $ / MMBtu	2.94
Basis Swap [Member] | 2020 [Member] | Crude Oil [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(7,486)
Underlying, Derivative | $ / bbl	(1.31)
Basis Swap [Member] | 2020 [Member] | Crude Oil [Member] | Brent/WTI [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)
Underlying, Derivative Energy Measure | $ / bbl	8.36
Basis Swap [Member] | 2020 [Member] | Natural Gas | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(60)
Underlying, Derivative | $ / MMBtu	(0.79)
Basis Swap [Member] | 2021 [Member] | Crude Oil [Member] | Brent/WTI [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,000)
Underlying, Derivative Energy Measure | $ / bbl	8.00
Basis Swap [Member] | 2021 [Member] | Natural Gas | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(70)
Underlying, Derivative | $ / MMBtu	(0.59)
Basis Swap [Member] | 2022 [Member] | Crude Oil [Member] | Brent/WTI [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,000)
Underlying, Derivative Energy Measure | $ / bbl	7.75
Basis Swap [Member] | 2022 [Member] | Natural Gas | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(70)
Underlying, Derivative | $ / MMBtu	(0.57)
Basis Swap [Member] | 2023 [Member] | Natural Gas | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(70)
Underlying, Derivative | $ / MMBtu	(0.51)
Call Option [Member] | 2019 [Member] | Crude Oil [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)
Underlying, Derivative Energy Measure | $ / bbl	54.08

XML

Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk - Fair Values and Gains (Losses) (Detail) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
DerivativeGainLoss [Line Items]
Net gain (loss) on derivatives		$ 443	$ (139)	$ (154)	$ (69)	$ (210)	$ (106)	$ 116	$ 203	$ 81	$ 3	$ (207)
Energy Related Derivative
DerivativeGainLoss [Line Items]
Net gain (loss) on derivatives	[1]									78	3	(207)
Derivative, Cost of Hedge										237
Derivative, Cash Received on Hedge											4	301
Derivatives Related to Physical Marketing Agreements
DerivativeGainLoss [Line Items]
Net gain (loss) on derivatives	[2]									3	0	0
Derivative, Cost of Hedge										$ 1	$ 1
Derivative, Cash Received on Hedge												$ 1

[1] Includes payments totaling $237 million for the year ended December 31, 2018 and settlements totaling $4 million and $301 million for the years ended December 31, 2017 and

[2] Includes payments totaling less than $1 million for the years ended December 31, 2018 and 2017 and settlements totaling  $1 million for the year ended December 31, 2016.

XML

Derivatives and Concentration of Credit Risk - Offsetting of derivative assets and liabilities (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Derivative Asset [Abstract]
Gross Amount Presented on Balance Sheet		$ 178	$ 59
Netting Adjustment	[1]	(37)	(42)
Net Amount		141	17
Derivative Liability [Abstract]
Gross Amount Presented on Balance Sheet		(37)	(236)
Netting adjustment	[1]	37	42
Net Amount		$ 0	$ (194)

[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.

XML

Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk - Credit risk related features (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Credit Derivatives [Line Items]
Increase (Decrease) in Derivative Liabilities		$ (4)
Derivative, Net Liability Position, Aggregate Fair Value		194
Additional Collateral, Aggregate Fair Value		$ 194
Maximum
Credit Derivatives [Line Items]
Increase (Decrease) in Derivative Liabilities	$ (1)
Derivative, Net Liability Position, Aggregate Fair Value	1
Additional Collateral, Aggregate Fair Value	$ 1

XML

Derivatives and Concentration of Credit Risk - Concentration of Credit Risk (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016
Concentration Risk [Line Items]
Accounts Receivable, Net	$ 405	$ 307
Income Taxes Receivable	38	0
Maximum Potential Future Exposure On Credit Risk Derivatives Gross	178
Maximum Potential Future Exposure On Credit Risk Derivatives Net	$ 141
Number of largest net counter party positions investment grade	6
Percentage of net credit exposure from derivatives	91.00%
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 10
Other Products And Services [Member]
Concentration Risk [Line Items]
Accounts Receivable, Net	269	251
Other Ownership Interest [Member]
Concentration Risk [Line Items]
Accounts Receivable, Net	98	54
Other Receivables [Member]
Concentration Risk [Line Items]
Accounts Receivable, Net	$ 0	$ 2
United Energy Trading [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	23.00%
Occidental [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%
Crestwood [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		21.00%
St. Paul Refining [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		16.00%	13.00%
NGL Crude Logistics [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%	13.00%
Delek Refining [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
Plains Marketing [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			15.00%
Standard & Poor's
Concentration Risk [Line Items]
Debt Instrument, Credit Rating	BBB-
Moody's Investors Service
Concentration Risk [Line Items]
Debt Instrument, Credit Rating	Baa3
NGL Energy Partners [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%
NGL Energy Partners [Member] | Minimum | Operating Expense [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	1.00%

XML

Subsequent Events (Detail) - Subsequent Event [Member] $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) a
Subsequent Event [Line Items]
Proceeds from Sale of Other Assets | $	$ 200
Equity Method Investment, Ownership Percentage	20.00%
Acreage purchased or sold | a	5,600
Payments to Acquire Land Held-for-use | $	$ 100
Acreage purchased | a	14,000

XML

Quarterly Financial Data Quarterly Financial Data-Summarized Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Data [Line Items]
Net gain (loss) on derivatives	$ 443	$ (139)	$ (154)	$ (69)	$ (210)	$ (106)	$ 116	$ 203	$ 81	$ 3	$ (207)
Total revenues	1,022	484	430	374	155	145	350	395	2,310	1,045	478
Total costs and expenses	447	413	388	322	265	223	231	208	1,756	947	1,304
Operating Income (Loss)	575	71	42	52	(110)	(78)	119	187	554	98	(826)
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	353	(6)	(79)	(26)	(20)	(378)	327	95	242	24	(672)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	1	(1)	(2)	(89)	(18)	232	(251)	(3)	(91)	(40)	71
Net income (loss)					(38)	(146)	76	92	151	(16)	(601)
Income (loss) from continuing operations attributable to WPX	353	(6)	(83)	(30)	(24)	(381)	323	91	234	9	(712)
Income (loss) from discontinued operations attributable to WPX	1	(1)	(2)	(89)	$ (18)	$ 232	$ (251)	$ (3)	(91)	(40)	71
Net loss attributable to WPX Energy, Inc.	$ 354	$ (7)	$ (81)	$ (115)					$ 151	$ (16)	$ (601)
Income (loss) from continuing operations, per basic share	$ 0.84	$ (0.01)	$ (0.21)	$ (0.07)	$ (0.06)	$ (0.96)	$ 0.81	$ 0.24	$ 0.57	$ 0.02	$ (2.28)
Discontinued operation, income (loss) from discontinued operation, net of tax, per basic share	0	0	0	(0.23)	(0.04)	0.58	(0.63)	(0.01)	(0.22)	(0.10)	0.23
Earnings per share, basic	0.84	(0.01)	(0.21)	(0.30)	(0.10)	(0.38)	0.18	0.23	0.35	(0.08)	(2.05)
Income (loss) from continuing operations, per diluted share	0.83	(0.01)	(0.21)	(0.07)	(0.06)	(0.96)	0.77	0.23	0.57	0.02	(2.28)
Discontinued operation, income (loss) from discontinued operation, net of tax, per diluted share	0	0	0	(0.23)	(0.04)	0.58	(0.60)	(0.01)	(0.22)	(0.10)	0.23
Earnings per share, diluted	$ 0.83	$ (0.01)	$ (0.21)	$ (0.30)	$ (0.10)	$ (0.38)	$ 0.17	$ 0.22	$ 0.35	$ (0.08)	$ (2.05)
Oil and Gas [Member]
Quarterly Financial Data [Line Items]
Revenue from contract with customer, including assessed tax	$ 544	$ 554	$ 520	$ 407	$ 356	$ 247	$ 226	$ 187	$ 2,025	$ 1,016	$ 507
Oil and Gas, Refining and Marketing [Member]
Quarterly Financial Data [Line Items]
Revenue from contract with customer, including assessed tax	$ 36	$ 68	$ 64	$ 36	$ 8	$ 4	$ 8	$ 5	$ 204	$ 25	$ 177

XML

Quarterly Financial Data - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended					12 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Data [Line Items]
Contractual Obligation						$ 1,048
Gain (Loss) on Termination of Lease					$ 23
Impairment of Oil and Gas Properties				$ (60)
Loss on extinguishment of debt	$ (71)			(17)
Disposal group contract obligation expense						0	$ 5	$ 0
IncomeTaxReconciliationChangeInStatutoryTaxRate			$ 92			$ 0	92	0
Permian [Member]
Quarterly Financial Data [Line Items]
Gain (Loss) on Disposition of Proved Property			11	111	$ 31		103
San Juan Gallup [Member]
Quarterly Financial Data [Line Items]
Gain (Loss) on Disposition of Proved Property		$ 138
Piceance Basin [Member]
Quarterly Financial Data [Line Items]
DisposalGroupOperatingTaxRefund				$ 10			$ 10
Disposal group contract obligation expense								$ 104
Powder River Basin
Quarterly Financial Data [Line Items]
Disposal group contract obligation expense			$ 5
Guarantee Type, Other [Member] | San Juan Gallup [Member]
Quarterly Financial Data [Line Items]
Contractual Obligation		$ 9

XML

Supplemental Oil and Gas Disclosures - Capitalization Cost (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	$ 7,612	$ 6,113
Unproved properties	1,891	2,194
Total property costs	9,503	8,307
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities	2,542	1,860
Net capitalized costs	6,961	6,447
Equipment and facilities in support of oil and gas production excluded from capitalization	$ 276	$ 223

XML

Supplemental Oil and Gas Disclosures - Cost Incurred (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) MMBoe	Dec. 31, 2017 USD ($) MMBoe	Dec. 31, 2016 USD ($) MMBoe
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	$ 68	$ 864	$ 84
Exploration	7	5	5
Development	1,350	1,048	471
Total costs incurred	1,425	1,917	560
Permian [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves	13	195
San Juan [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development	$ 24	$ 168
Piceance Basin [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development			$ 102
Oil [Member] | Permian [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved Developed Reserves (Energy) | MMBoe	0.6	23.8	2.5

XML

Supplemental Oil and Gas Disclosures - Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2018 MMBoe MMBbls MMcf	Dec. 31, 2017 MMBoe MMcf MMBbls	Dec. 31, 2016 MMBoe MMcf MMBbls	Dec. 31, 2015 MMBoe MMBbls MMcf
Reserve Quantities [Line Items]
Computation Of Oil Natural Gas And Ngl Reserves	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMBbls	0	4.7	(3.8)
Proved Developed and Undeveloped Reserves, Net | MMBbls	291.3	263.7	174.6	142.7
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MMBbls	(27.6)	(1.7)	(5.5)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | MMBbls	84.5	86.7	54.9
Proved Developed and Undeveloped Reserves, Production | MMBbls	(30.8)	(22.4)	(15.3)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | MMBbls	1.5	21.8	1.6
Proved Undeveloped Reserve (Volume) | MMBbls	134.9	133.4	90.2
Proved Developed Reserves (Volume) | MMBbls	156.4	130.3	84.4
Natural Gas
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMcf	(11,400)	(8,400)	(50,200)
Proved Developed and Undeveloped Reserves, Net | MMcf	617,700	591,000.0	734,500	2,190,200
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MMcf	(79,800)	(312,500)	(1,505,900)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | MMcf	176,900	194,500	214,600
Proved Developed and Undeveloped Reserves, Production | MMcf	(63,800)	(75,900)	(118,600)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | MMcf	4,800	58,800	4,400
Proved Undeveloped Reserve (Volume) | MMcf	252,300	269,800	294,200
Proved Developed Reserves (Volume) | MMcf	365,400	321,200	440,200
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMBbls	5.3	(1.1)	(2.9)
Proved Developed and Undeveloped Reserves, Net | MMBbls	85.0	74.0	49.5	75.3
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MMBbls	(10.4)	(0.8)	(38.3)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | MMBbls	22.7	23.6	19.8
Proved Developed and Undeveloped Reserves, Production | MMBbls	(7.2)	(5.0)	(4.8)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | MMBbls	0.6	7.8	0.4
Proved Undeveloped Reserve (Volume) | MMBbls	36.6	35.2	25.4
Proved Developed Reserves (Volume) | MMBbls	48.4	38.8	24.1
All products
Reserve Quantities [Line Items]
Beginning Balance	479.3	436.2	346.4	583.0
Revisions	3.4	2.3	(15.2)
Purchases	2.9	39.4	2.8
Divestitures	(51.3)	(54.6)	(294.8)
Extensions and discoveries	136.7	142.7	110.5
Production	(48.6)	(40.0)	(39.9)
Proved Developed Reserves (Energy)	265.8	222.7	181.8
Proved Undeveloped Reserves (Energy)	213.5	213.5	164.6
Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Purchases		23.8
Extensions and discoveries	52	46	26
Proved Undeveloped Reserves [Member] [Member]
Reserve Quantities [Line Items]
Extensions and discoveries	85	97	84
San Juan [Member] | Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Divestitures	(40)	(28.7)
San Juan [Member] | Proved Undeveloped Reserves [Member] [Member]
Reserve Quantities [Line Items]
Divestitures	(11)	(16.6)
Piceance Basin [Member] | Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Divestitures			(222)
Piceance Basin [Member] | Proved Undeveloped Reserves [Member] [Member]
Reserve Quantities [Line Items]
Divestitures			(67)
Negative [Member]
Reserve Quantities [Line Items]
Revisions	(5)	(22)	(49)
Positive [Member]
Reserve Quantities [Line Items]
Revisions	9	24	34

XML

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 20,963	$ 14,785
Future production costs	7,615	6,112
Future development costs	2,345	2,070
Future income tax provisions	1,366	408
Future net cash flows	9,637	6,195
Less 10 percent annual discount for estimated timing of cash flows	(4,446)	(3,034)
Standardized measure of discounted future net cash inflows	$ 5,191	$ 3,161	$ 1,038	$ 1,284

XML

Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 3,161	$ 1,038	$ 1,284
Sales of oil and gas produced, net of operating costs	(1,541)	(894)	(458)
Net change in prices and production costs	2,004	1,385	(261)
Extensions, discoveries and improved recovery, less estimated future costs	1,341	816	735
Development costs incurred during year	654	345	142
Changes in estimated future development costs	(35)	105	(211)
Purchase of reserves in place, less estimated future costs	27	305	20
Sale of reserves in place, loss estimated future costs	(409)	20	(253)
Revisions of previous quantity estimates	75	30	(78)
Accretion of discount	324	104	136
Net change in income taxes	(396)	(83)	0
Other	(14)	(10)	(18)
Net changes	2,030	2,123	(246)
Standardized measure of discounted future net cash flows end of period	$ 5,191	$ 3,161	$ 1,038

XML

Supplemental Oil and Gas Disclosures - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 $ / bbl $ / Mcfe	Dec. 31, 2017 $ / bbl $ / Mcfe	Dec. 31, 2016 $ / bbl $ / Mcfe
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Weighted average natural gas price | $ / Mcfe	1.21	1.67	1.74
Average NGL price	26.76	21.16	10.57
Weighted Average Oil Per Barrel Price	61.57	46.39	35.91
Discount Rate	10.00%

XML

II-Valuation and Qualifying Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Price-risk management credit reserves-assets [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount			$ 0	$ 1
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense			0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease)			(1)
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction			0
Price-risk management credit reserves-liabilities [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0	$ 4	5	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease)	(4)	(1)	5
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	0	0	0
SEC Schedule, 12-09, Allowance, Notes Receivable
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	0	2	3	6
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease)	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	2	1	3
SEC Schedule, 12-09, Valuation Allowance, Deferred Tax Asset [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	213	195	151	$ 124
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense	18	44	26
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease)	0	0	1
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	$ 0	$ 0	$ 0