wpx-20191231

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


Form			10-K

(Mark One)


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

For the fiscal year ended December 31, 2019


☐			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

Trading Symbol

Name of Each Exchange on Which Registered

Common Stock, $0.01 par value

WPX

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 ☑ 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 ☑

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 ☑ 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 ☑ 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. ☐

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

☑

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 ☑

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $4,310,692,615.

The number of shares outstanding of the registrant’s common stock outstanding at February 26, 2020 was 417,011,573.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement to be delivered to stockholders in connection with its 2020 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
	WPX Energy, Inc.	3
	Business Overview and Properties	4
	Regulatory Matters	14
	Environmental Matters	16
	Competition	22
	Employees	22
	Financial Information about Segments	22
	Website Access to Reports and Other Information	22

Item 1A.	Risk Factors	23

Item 1B.	Unresolved Staff Comments	41

Item 2.	Properties	41

Item 3.	Legal Proceedings	41

Item 4.	Mine Safety Disclosures	41

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	42

Item 6.	Selected Financial Data	44

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60

Item 8.	Financial Statements and Supplementary Data	61

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	106

Item 9A.	Controls and Procedures	106

Item 9B.	Other Information	107

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	107
		107
Item 11.	Executive Compensation	107

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	107

Item 13.	Certain Relationships and Related Transactions, and Director Independence	107

Item 14.	Principal Accountant Fees and Services	107

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	108

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.

BLM—means the Bureau of Land Management.

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.

EPA—means the Environmental Protection Agency.

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.

NEPA—means the National Environmental Policy Act.

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.

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, 2019 were 528 MMboe. Our reserves reflect a mix of 56 percent crude oil, 23 percent natural gas and 21 percent NGLs. During 2019, we replaced our total commodity production at a rate of 190 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.

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 cost reductions. 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 or grow 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.

Pending Felix Acquisition

Pursuant to the Purchase Agreement, Felix Parent will receive our common stock as consideration and Felix Parent (and/or certain of Felix Parent's direct or indirect equity holders) will have registration rights with respect to such common stock. Following the Felix Acquisition, Felix will be our wholly-owned subsidiary.

Felix is engaged in the acquisition, development and production of oil and gas properties in the Permian Basin, and more specifically in the Delaware Basin sub-area. All of Felix's Permian properties are located in the Delaware Basin, where it has accumulated approximately 58,500 net acres with six productive benches, with core operations located in Loving, Reeves, Ward and Winkler counties in Texas.

Felix operates 191 gross producing oil wells as of December 31, 2019 in the Delaware Basin with an average working interest of approximately 88%. Felix's average net daily production from its Delaware Basin properties for the year ended December 31, 2019 was 45.3 Mboe/d, 72% of which was oil, 15% NGLs and 13% natural gas. As of December 31, 2019, Felix had proved developed reserves of 135 MMboe, 70% of which was oil, 17% NGLs and 13% natural gas. As of December 31,

2019, Felix had 334 proved undeveloped locations representing 336 MMboe based on a five development drilling rig plan in place at such time. The proved undeveloped reserves of Felix are based on Felix's development plans and may not necessarily reflect our development plans for these properties. Therefore, upon closing of the Felix Acquisition, the proved undeveloped reserves booked by us may differ, although we plan to continue to maintain Felix's five rig drilling program following the consummation of the Felix Acquisition. Felix has assembled a multi-year inventory of approximately 1,500 gross drillable locations. We believe the Felix assets will further strengthen our inventory in the Permian Basin.

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 688 wells in the Delaware Basin and also own interests in 787 wells operated by others. We hold approximately 122,000 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 80 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 2019, we operated an average of 5.1 drilling rigs in the Delaware Basin and have had an average of 96 Mboe per day of net production. We expect to operate 7 rigs in the Delaware Basin in 2020. In addition, we plan to continue Felix's 5 rig program in the Delaware Basin following the closing of the Felix Acquisition. Capital expenditures in 2019, including land purchases and infrastructure, were approximately $811 million. During 2019, we completed 89 gross (75 net) wells and we have another 17 gross operated wells awaiting completion as of December 31, 2019.

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 122,000 net acres.

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 the BLM. These particular leases are subject to federal authority, including the NEPA, and require governmental agencies to evaluate the potential environmental impacts of proposed projects 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. We operate 404 wells in the Williston Basin and also own interest in 104 wells operated by others. We hold approximately 87,000 net acres in the Williston Basin.

During 2019, we operated an average of 3 rigs on our Williston Basin properties and we had an average of 70.9 Mboe per day of net production from our Williston Basin wells. We expect to operate 2.5 rigs in the Williston Basin in 2020. Capital expenditures in 2019 for drilling and completions were approximately $478 million. During 2019, we completed 88 gross (68 net) wells and we have another 14 gross operated well awaiting completion as of December 31, 2019.

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.

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 proposed projects 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.

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.

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, 2019, 2018 and 2017.


	As of December 31, 2019
	Oil (Mbbls)	Gas (MMcf)	NGL (Mbbls)	Equivalent (Mboe)	%
Proved Developed	184,307	456,510	65,482	325,874	62%
Proved Undeveloped	111,499	284,141	42,830	201,685	38%
Total Proved	295,806	740,651	108,312	527,559


	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(a)	27,950	83,627	10,718	52,604
Total Proved less discontinued operations	235,720	507,389	63,293	383,580

__________

(a) Represents total proved reserves related to our San Juan Basin assets, which were sold in 2018.

The following table sets forth our estimated net proved reserves for our areas of activity expressed by product and on an oil equivalent basis as of December 31, 2019.


	As of December 31, 2019
		Oil (Mbbls)		Gas (MMcf)		NGL (Mbbls)		Equivalent (Mboe)
Delaware Basin	178,535		657,034		92,792		380,832
Williston Basin	117,271		83,617		15,520		146,727




Total Proved	295,806		740,651		108,312		527,559

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 2019 year-end estimated proved reserves reflect an average oil price of $53.62 per barrel, an average natural gas price of $0.97 per Mcf and average NGL price of $13.23 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 2019, we added 111 MMboe of extensions and discoveries to our proved reserves. During 2019, we incurred $1,092 million in development expenditures, which included the drilling of 208 gross (169 net) wells.

Proved reserves reconciliation

The 111 MMboe of extensions and discoveries reflects 42 MMboe added for drilled locations, and 69 MMboe added for new proved undeveloped locations. Of the extensions and discoveries, 93 percent were in the Delaware Basin. The overall net positive revisions of 5 MMboe reflect 21 MMboe net positive technical revisions offset by 16 MMboe of net negative price revisions due to the decrease in the 12-month average prices.

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 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 2019 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, 2019 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 19 years of relevant experience in Reservoir and Evaluation Engineering, a B.S. in Petroleum Engineering, 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, 2019 and 2018, our proved undeveloped reserves were 202 MMboe and 214 MMboe, respectively. Proved undeveloped reserves represents 38 percent and 45 percent, respectively, of our total proved reserves as of December 31, 2019 and 2018. Below is a reconciliation of our proved undeveloped reserves for 2019:


		% of	% of
	MMboe	December 31, 2018	December 31, 2019
Proved Undeveloped Reserves at December 31, 2018	214
Converted to Proved Developed Reserves	(69)	(32)%	(34)%
Extensions and Discoveries	68	32%	34%
Revisions	(9)	(4)%	(4)%

Divestitures	(2)	(1)%	(1)%
Proved Undeveloped Reserves at December 31, 2019	202

During 2019, 69 MMboe of our December 31, 2018 proved undeveloped reserves were converted to proved developed reserves at a cost of $706 million of which $185 million was incurred in prior years. This represents a proved undeveloped conversion rate of 34 percent. Of the converted proved undeveloped reserves, 59 percent were in the Delaware Basin in the Bone Springs and Wolfcamp formations, and 41 percent were in the Williston Basin in the Bakken and Three Forks formations.

Of the 68 MMboe of proved undeveloped extensions and discoveries, 100 percent are in the Delaware Basin, primarily in the Wolfcamp formation.

In 2019, net negative revisions for our proved undeveloped reserves were 9 MMboe, which reflects downward technical revisions of 5 MMboe and a downward revision of 4 MMboe based on the 12-month trailing prices.

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,
	2019	2018	2017	2019	2018	2017
Oil	(Mbbls)					(Mbbls/d)

Delaware Basin	16,950	14,976	8,013	46.4	41.0	22.0
Williston Basin	20,872	14,793	10,951	57.2	40.6	30.0



Total continuing operations	37,822	29,769	18,964	103.6	81.6	52.0
Discontinued operations(a)	—	1,029	3,398	—	2.8	9.3
Total continuing and discontinued operations	37,822	30,798	22,362	103.6	84.4	61.3

Natural Gas	(MMcf)					(MMcf/d)

Delaware Basin	63,153	50,275	28,554	173.0	137.7	78.2
Williston Basin	15,201	9,090	5,054	41.7	24.9	13.8


Other	—	—	1,703	—	—	4.7
Total continuing operations	78,354	59,365	35,311	214.7	162.6	96.7
Discontinued operations(a)	—	4,433	40,791	—	12.2	111.8
Total continuing and discontinued operations	78,354	63,798	76,102	214.7	174.8	208.5

NGLs	(Mbbls)					(Mbbls/d)

Delaware Basin	7,575	5,204	2,748	20.7	14.2	7.5
Williston Basin	2,468	1,529	896	6.8	4.2	2.5


Other	—	—	12	—	—	—
Total continuing operations	10,043	6,733	3,656	27.5	18.4	10.0
Discontinued operations(a)	—	433	1,381	—	1.2	3.8
Total continuing and discontinued operations	10,043	7,166	5,037	27.5	19.6	13.8



Combined Equivalent Volumes	(Mboe)					(Mboe/d)

Delaware Basin	35,050	28,559	15,520	96.0	78.2	42.5
Williston Basin	25,874	17,837	12,689	70.9	48.9	34.8


Other	—	—	296	—	—	0.8
Total continuing operations	60,924	46,396	28,505	166.9	127.1	78.1
Discontinued operations(a)	—	2,201	11,578	—	6.0	31.7
Total continuing and discontinued operations	60,924	48,597	40,083	166.9	133.1	109.8

__________

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

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,
	2019		2018		2017		2019		2018		2017
Oil(b):
Oil excluding all derivative settlements (per barrel)	$	54.20	$	60.14	$	46.36	$	54.20	$	59.98	$	46.02
Impact of net cash received (paid) related to settlement of derivatives (per barrel)	(1.14)		(8.56)		(0.33)		(1.14)		(8.27)		(0.27)
Oil net price including all derivative settlements (per barrel)	$	53.06	$	51.58	$	46.03	$	53.06	$	51.71	$	45.75
Natural gas(b):
Natural gas excluding all derivative settlements (per Mcf)	$	0.96	$	1.46	$	1.89	$	0.96	$	1.46	$	2.14
Impact of net cash received related to settlement of derivatives (per Mcf)	0.70		0.51		0.28		0.70		0.47		0.13
Natural gas net price including all derivative settlements (per Mcf)	$	1.66	$	1.97	$	2.17	$	1.66	$	1.93	$	2.27
NGL(b):
NGL excluding all derivative settlements (per barrel)	$	12.17	$	21.97	$	19.26	$	12.17	$	22.24	$	22.91
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)	$	12.17	$	19.99	$	19.26	$	12.17	$	20.39	$	22.91






Combined commodity price per boe, including all derivative settlements	$	37.08	$	38.52	$	35.78	$	37.08	$	38.32	$	32.71

__________

(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, and in certain circumstances, 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,
	2019		2018		2017		2019		2018		2017
Production costs:
Lifting costs and workovers(b)	$	5.60	$	5.25	$	5.42	$	5.60	$	5.16	$	4.92
Facilities operating expense	0.43		0.52		0.37		0.43		0.49		0.34
Accretion expense	0.07		0.06		0.07		0.07		0.06		0.15
Other operating and maintenance	0.03		0.02		0.04		0.03		0.02		0.03
Total lease and facility operating	$	6.13	$	5.85	$	5.90	$	6.13	$	5.73	$	5.44
Gathering, processing and transportation charges	3.01		2.30		0.83		3.01		2.43		2.46
Taxes other than income	2.92		3.39		2.78		2.92		3.33		2.55
Total production cost	$	12.06	$	11.54	$	9.51	$	12.06	$	11.49	$	10.45
General and administrative	$	3.40	$	3.92	$	5.80	$	3.40	$	3.78	$	4.37
Depreciation, depletion and amortization	$	15.23	$	16.75	$	19.03	$	15.23	$	16.15	$	16.79

__________

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

(b) Workover costs related to continuing operations were $0.85, $0.66, and $0.52 for the respective periods.

Productive Oil and Gas Wells

The table below summarizes 2019 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	1,253	613	222	118
Williston Basin	508	340	—	—



Total	1,761	953	222	118

Developed and Undeveloped Acreage

The following table summarizes our leased acreage as of December 31, 2019.


	Developed			Undeveloped			Total
	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres
Delaware Basin(a)	131,547	78,278	73,220	44,041	204,767	122,319
Williston Basin	78,280	66,103	61,538	20,787	139,818	86,890


Other(b)	1,644	513	12,876	3,911	14,520	4,424
Total	211,471	144,894	147,634	68,739	359,105	213,633

__________

(a) Includes 17,886 gross and net undeveloped natural gas prone acres in Culberson County with continuous drilling clauses or penalties that we allowed to expire in January 2020.

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

At December 31, 2019, we also owned mineral interests in 22,831 gross and 1,507 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 2019, 2018 and 2017. Our combined development and exploration success rate was 100 percent in 2019, 2018 and 2017.

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


	2019			2018			2017
	Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells
Development wells:
Delaware Basin	89	75	128	87	94	76
Williston Basin	88	68	60	52	44	34



Development well total	177	143	188	139	138	110





Exploration well total	—	—	—	—	—	—
Total Drilled	177	143	188	139	138	110

Total gross operated wells drilled were 164, 148 and 118 in 2019, 2018 and 2017, respectively.

Present Activities

At December 31, 2019, we had 23 gross (21 net) wells in the process of being drilled.

Scheduled Lease Expirations

The table below sets forth, as of December 31, 2019, 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.


	2020	2021	2022	2023+	Total
Delaware Basin(a)	21,561	241	97	3,206	25,105
Williston Basin	160	120	—	—	280



Total (Gross Acres)	21,721	361	97	3,206	25,385


	2020	2021	2022	2023+	Total
Delaware Basin(a)	20,525	215	44	3,198	23,982
Williston Basin	160	120	—	—	280



Total (Net Acres)	20,685	335	44	3,198	24,262

__________

(a) Expirations for 2020 include 17,886 gross and net natural gas prone acres in Culberson County with an original expiration date of 2022 that was subject to continuous drilling clauses or penalties that we allowed to expire in January 2020.

Seasonality

Generally, demand for oil increases during the summer months and decreases during the winter months while 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 that range from one to seven years for the physical delivery of oil in both the Delaware and Williston Basins. The minimum aggregate volume for these sales commitments ranges from 50 to 71 Mbbls per day for years 2020 through 2022 and 30 to 32 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 2019, we had four 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.

REGULATORY MATTERS

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

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

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

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 EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment contractor preferences and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or

conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members or use tribal owned service businesses and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators 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 has merged its former 2011 – 2013, 2014 – 2016, and 2016 – 2019 National Enforcement Initiative of “Ensuring Energy Extraction Activities Comply with Environmental Laws” into the new National Compliance Initiative (NCI) for FY 2020-2023 titled “Creating Cleaner Air for Communities by Reducing Excess Emissions of Harmful Pollutants” that will focus on reducing emissions of both volatile organic compounds (VOCs) and hazardous air pollutants (HAPs). According to the EPA’s website, “for VOC emissions, the NCI will focus on significant sources of VOCs that have a substantial impact on air quality” that may adversely affect the area’s ability to reach attainment with the National Ambient Air Quality Standards (NAAQS), or may adversely affect vulnerable populations. For HAPs, the NCI will focus on sources that have a significant impact on air quality and health in communities. To address these concerns, the EPA has settled a number of high-impact cases under the prior initiative resulting in significant air emissions reductions, and will continue to target and reduce the emissions of HAPs and VOCs. 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

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 provides coverage for a five-year period and took 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 on September 24, 2019 EPA published in the federal register its proposed additional amendments to the 2012 and 2016 NSPS to remove sources in the transmission and storage segment from the oil and natural gas source categories and for the production and processing segments of the oil and natural gas source categories. EPA proposes to rescind emissions limits for methane but keep emissions limits for VOCs. EPA also proposed an alternative proposal to rescind the methane requirements in the NSPS for oil and natural gas sources without removing any sources from the source category. EPA has taken comments but has not yet issued the final revised regulations. In addition, EPA is anticipated to issue technical amendments and clarifications to the NSPS Subpart OOOOa 2016 regulations that may address definitions, administrative requirements, and inspection frequencies.

Oil Pollution Act. The Oil Pollution Act of 1990, as amended (“OPA”), and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills

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

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the 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-nine to fifty 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.

•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 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, 2019, we have loaded data on more than 2,500 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, 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.

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. 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 is 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 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.

EMPLOYEES

At December 31, 2019, we had approximately 590 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, Governance, Environmental and Public Policy Committee

•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.

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.”

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:

•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 2019, 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 $5.9 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.

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

Approximately 38 percent of our total estimated proved reserves at December 31, 2019 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 or has continuous drilling clauses. 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;

•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, 2019, we were not the operator of approximately 6 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.

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.

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. 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, 2019, the high sales price per share of our common stock on the NYSE was $15.33 and the low sales price per share was $8.79. 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.

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, 2019, our revolving credit facility is subject to a borrowing base of $2.1 billion, which is currently limited by total commitments of $1.5 billion. The borrowing base is subject to scheduled annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2019, we had no outstanding borrowings and $28 million of letters of credit issued under our revolving credit facility, resulting in unused borrowing capacity of approximately $1.5 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.

We are subject to risks associated with 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.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damage or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

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;

•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.

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 2019, which included Energy Extraction and “Ensuring Energy Extraction Activities Comply with Environmental Laws.” For FY 2020-2023 EPA has merged that initiative into its new National Compliance Initiative titled “Creating Cleaner Air for Communities by Reducing Excess Emissions of Harmful Pollutants” focused on reducing emissions of both volatile organic compounds (VOCs) and hazardous air pollutants (HAPs). The EPA has settled a number of high-impact cases under the prior initiative resulting in significant air emissions reductions, and will continue to target and reduce emissions under the new compliance initiative. 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 may generally be 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, in August 2015, the EPA issued a suite of proposed regulations to cut methane emissions from the oil and gas sector

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.

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 oil and 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 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 in recent years. 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.

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 or rates, 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.

We may not be successful in completing the Felix Acquisition.

The consummation of the Felix Acquisition is subject to certain conditions, including the receipt of stockholder and regulatory approval which may or may not be obtained. If the conditions to the consummation of the Felix Acquisition are not satisfied, or if the Purchase Agreement is terminated prior to closing, the Felix Acquisition will not be consummated.

We will incur significant transaction and acquisition-related costs in connection with the Felix Acquisition.

We expect to incur significant costs associated with the Felix Acquisition and combining the operations of the two companies, including costs to achieve targeted cost-savings. The substantial majority of the expenses resulting from the Felix Acquisition will be composed of transaction costs related to the Felix Acquisition, systems consolidation costs, and business integration related costs. We may also incur transaction fees and costs related to formulating integration plans. Additional unanticipated costs may be incurred in the integration of the two companies' businesses. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow us to offset incremental transaction and acquisition-related costs over time, this net benefit may not be achieved in the near term, or at all.

Completion of the Felix Acquisition may trigger change in control or other provisions in certain agreements to which Felix is a party, which may have an adverse impact on the combined company's business and results of operations.

The completion of the Felix Acquisition may trigger change in control and other provisions in certain agreements to which Felix is a party. For those agreements for which we and Felix are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. The foregoing or similar developments may have an adverse impact on the combined company's business and results of operations.

The integration of Felix may not be as successful as anticipated, and we may not achieve the intended benefits or do so within the intended timeframe.

The Felix Acquisition involves numerous operational, strategic, financial, accounting, legal, tax and other risks, including potential liabilities associated with the acquired business. Difficulties in integrating Felix and our ability to manage the combined company, may result in the combined company performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have an adverse effect on our financial condition, results of operations or cash flows. Potential difficulties that may be encountered in the integration process include, among other factors:

•the inability to successfully integrate the businesses of Felix, operationally and culturally, in a manner that permits us to achieve the full revenue and cost savings anticipated from the Felix Acquisition, which includes accurate assessment of new producing properties based upon several factors such as recoverable reserves, future natural gas and oil prices and their appropriate differentials, availability and cost of transportation of production to markets, availability and cost of drilling equipment and of skilled personnel, development and operating costs and potential environmental and other liabilities and regulatory, permitting and similar matters;

•complexities associated with managing a larger, more complex, integrated business, including the potential diversion of the our management's attention;

•not realizing anticipated operating synergies;

•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Felix Acquisition;

•difficulty or inability to refinance the debt of the combined company or comply with the covenants thereof;

•integrating relationships with customers, vendors and business partners;

•performance shortfalls at one or both of the companies as a result of the diversion of management's attention caused by completing the Felix Acquisition and integrating Felix's operations; and

•the disruption of, or the loss of momentum in, each company's ongoing business or inconsistencies in standards, controls, procedures and policies.

Additionally, the success of the Felix Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining Felix's and the Company's businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the Felix Acquisition may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that the Company does not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized.

Our results may suffer if we do not effectively manage our expanded operations following the Felix Acquisition.

Following completion of the Felix Acquisition, the size of our business will increase significantly beyond its current size. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of Felix into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.

Felix Parent will have significant influence over us after completion of the Felix Acquisition.

Upon completion of the Felix Acquisition, Felix Parent will beneficially own approximately 27% of our common stock. As long as Felix Parent owns or controls a significant percentage of our outstanding voting power, it will have the ability to significantly influence corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment to our certificate of incorporation or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets. Felix Parent's influence over the combined company management could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of the combined company, which could cause the market price of our common stock to decline or prevent stockholders from realizing a premium over the market price for our common stock.

Pursuant to the Stockholders' Agreement to be entered into upon closing of the Felix Acquisition, Felix Parent will have the right to nominate up to two directors to the combined company's board of directors. Felix Parent's right to designate directors to the combined company's board of directors is subject to their ownership percentage of the total outstanding shares of our common stock. If Felix Parent holds: (i) 20% or greater of the outstanding common stock, they will have the right to appoint two directors, or (ii) greater than 10% but less than 20% of the outstanding common stock, they will have the right to appoint one director.

Felix Parent's interests may not align with our interests or the interests of our other stockholders.

The Company's current stockholders will have a reduced ownership and voting interest after the Felix Acquisition compared to their current ownership and will exercise less influence over management.

Based on the number of issued and outstanding shares of the Company's Common Stock as of February 4, 2020, immediately after the Felix Acquisition is completed, it is expected that, on a fully-diluted basis, the Company's current stockholders will collectively own approximately 73% and Felix Parent will own approximately 27% of the outstanding shares of the Company's Common Stock (without giving effect to any shares of the Company's Common Stock held by Felix Parent prior to the Felix Acquisition, if any). As a result of the Felix Acquisition, the Company's current stockholders will own a smaller percentage of the Company than they currently own, and as a result will have less influence on the Company's management and policies. In addition, the Company may issue additional equity from time to time.

Sales of substantial amounts of the Company's Common Stock in the open market by Felix Parent could depress the Company's stock price.

Shares of the Company's Common Stock that are issued to Felix Parent in the Felix Acquisition will become freely tradable once registered pursuant to the Registration Rights Agreement by and between the Company and Felix Parent, which will become effective upon the consummation of the Felix Acquisition. Once registered, the Common Stock held by Felix Parent will have no restrictions or require further registration under the Securities Act, provided, however, that any stockholders, including Felix Parent, who are deemed the Company's affiliates will be subject to the resale restrictions of Rule 144 under the Securities Act.

Felix Parent may wish to dispose of some or all of its interests in the Company, and as a result may seek to sell their shares of the Company's Common Stock. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of the Company's Common Stock, may affect the market for, and the market price of, the Company's Common Stock in an adverse manner.

If the Felix Acquisition is completed and the Company's stockholders, including Felix Parent, sell substantial amounts of the Company's Common Stock in the public market following the closing of the Felix Acquisition, the market price of the Company's Common Stock may decrease. These sales might also make it more difficult for the Company to raise capital by selling equity or equity-related securities at a time and price that it otherwise would deem appropriate.

Following the completion of the Felix Acquisition, we will incorporate Felix's hedging activities into our business, and we may be exposed to additional commodity price risks arising from such hedges.

To mitigate its exposure to changes in commodity prices, Felix hedges oil, natural gas liquids and natural gas prices from time to time, primarily through the use of certain derivative commodity instruments. When we assume existing Felix hedges, we will bear the economic impact of all of Felix's current hedges following the completion of the Felix Acquisition. Actual crude oil, natural gas and natural gas liquids prices may differ from the combined company's expectations and, as a result, such hedges could have a negative impact on our business.

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.

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 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.

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.

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 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 the event that we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”)), our NOL carryovers generated prior to the ownership change would be subject to annual limitations, which could defer or eliminate our ability to utilize these tax losses against future taxable income. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns 5% or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50% over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. 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 10 of our Notes to Consolidated Financial Statements for the information that is called for by this item.


Item 4.			Mine Safety Disclosures

Not applicable.

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,
	2019						2018
	High		Low		High		Low
Common Stock:
Fourth quarter	$	13.82	$	9.26	$	20.80	$	9.89
Third quarter	$	12.70	$	8.79	$	20.37	$	16.94
Second quarter	$	15.33	$	10.08	$	19.23	$	12.75
First quarter	$	13.47	$	10.79	$	16.09	$	12.34

At February 26, 2020, there were 6,313 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.

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:	2014		2015		2016		2017		2018		2019
WPX	$	100.00	$	49.36	$	125.28	$	120.98	$	97.59	$	118.14
MID	$	100.00	$	96.29	$	114.33	$	130.85	$	114.5	$	142.04
S&P O&G	$	100.00	$	63.29	$	86.76	$	78.03	$	55.62	$	49.75

Unregistered Sales of Equity Securities and Use of Proceeds

a.Recent Sales of Unregistered Securities - Not applicable

b.Use of Proceeds - Not applicable.

c.Purchases of Equity Securities by the user and Affiliated Purchasers. The table below provides information about purchases of shares of our common stock during the quarter ended December 31, 2019.


Period	Total number of shares purchased as part of publicly announced plans or programs(a)	Average price paid per share		Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions)(a)





Share repurchase program(a):
October 1, 2019 to October 31, 2019	1,502,512	$	9.96	$	342
November 1, 2019 to November 31, 2019	—	$	—
December 1, 2019 to December 31, 2019	—	$	—


Total for the quarter	1,502,512	$	9.96	$	342

__________

(a) On August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over a 24 month period. As of December 31, 2019 we have repurchased approximately 5.7 million shares at a total cost of $58 million. This stock repurchase program may be modified, suspended or terminated at any time by our Board of Directors.


Item 6.			Selected Financial Data

The following financial data at December 31, 2019 and 2018, and for each of the three years ended December 31, 2019, 2018 and 2017 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,
	2019		2018		2017		2016		2015
Statement of operations data:	(Millions, except per share amounts)
Product revenues	$	2,247	$	2,025	$	1,016	$	507	$	403
Net gain (loss) on derivatives	$	(153)	$	81	$	3	$	(207)	$	418
Commodity management revenue	$	194	$	204	$	25	$	177	$	286
Total revenues	$	2,292	$	2,310	$	1,045	$	478	$	1,113

Income (loss) from continuing operations(a)	$	258	$	242	$	24	$	(672)	$	40
Income (loss) from discontinued operations(b)	(2)		(91)		(40)		71		(1,766)
Net income (loss)	$	256	$	151	$	(16)	$	(601)	$	(1,726)
Less: Net income attributable to noncontrolling interests	—		—		—		—		1
Net income (loss) attributable to WPX Energy, Inc.	$	256	$	151	$	(16)	$	(601)	$	(1,727)
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	$	256	$	143	$	(31)	$	(641)	$	(1,736)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	258	$	234	$	9	$	(712)	$	31
Income (loss) from discontinued operations	$	(2)	$	(91)	$	(40)	$	71	$	(1,767)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.62	$	0.57	$	0.02	$	(2.28)	$	0.13
Income (loss) from discontinued operations	$	(0.01)	$	(0.22)	$	(0.10)	$	0.23	$	(7.55)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.61	$	0.57	$	0.02	$	(2.28)	$	0.13
Income (loss) from discontinued operations	$	—	$	(0.22)	$	(0.10)	$	0.23	$	(7.50)


	As of December 31,
	2019		2018		2017		2016		2015
Balance sheet data:	(Millions)

Total assets	$	8,413	$	8,203	$	8,207	$	7,264	$	8,393
Long-term debt	$	2,202	$	2,485	$	2,575	$	2,575	$	3,189
Total stockholders’ equity	$	4,515	$	4,301	$	4,127	$	3,466	$	3,535
Total equity, including noncontrolling interests	$	4,515	$	4,301	$	4,127	$	3,466	$	3,535

__________

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


	Years Ended December 31,
	2019		2018		2017		2016		2015
	(Millions)

Net (gain) loss on sales of assets, divestment of transportation contracts or impairment of producing properties	$	—	$	(3)	$	(161)	$	239	$	(349)
Gains on equity method investment transactions	$	380	$	—	$	—	$	—	$	—

See Notes 4 and 5 of Notes to Consolidated Financial Statements for further discussion of asset sales and the equity method investment transactions in 2019, 2018 and 2017. In 2016, we completed the divestment of the remaining transportation contracts that were not included in the Piceance Basin divestment and recorded a net loss of $238 million. 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 and holdings in the Powder River Basin. Significant components included in income (loss) from discontinued operations are comprised of the following:


	Years Ended December 31,
	2019		2018		2017		2016		2015
	(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
Powder River pre-tax impairments	$	—	$	—	$	—	$	—	$	16

See Note 2 of Notes to Consolidated Financial Statements for further discussion of discontinued operations in 2019, 2018 and 2017.


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 third- party working interest owners in operated wells and the management of various commodity contracts such as transportation. 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 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. For all periods presented, the results of the San Juan Basin are reported as discontinued operations. See Note 2 of Notes to Consolidated Financial Statements for further discussion of our discontinued operations. Unless indicated otherwise, the following discussion relates to continuing operations.

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. See the Company's Annual Report on Form 10-K for the year ended December 31, 2018 for a discussion of the Company's 2018 results of operations as compared to the Company's 2017 results of operations. 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.”

Overview

Composition of Production (based on Mboe) and Product Revenue


			Years Ended December 31,

Production

Product Revenue

The following table presents our production volumes and financial highlights for 2019, 2018 and 2017:


	Years Ended December 31,
	2019					2018				2017
Production Sales Volume Data(a):			Per day			Per day			Per day
Oil (Mbbls)	37,822		103.6	29,769		81.6	18,964		52.0
Natural gas (MMcf)	78,354		214.7	59,365		162.6	35,311		96.7
NGLs (Mbbls)	10,043		27.5	6,733		18.4	3,656		10.0
Combined equivalent volumes (Mboe)	60,924		166.9	46,396		127.1	28,505		78.1
Financial Data (millions):
Total product revenues	$	2,247		$	2,025		$	1,016
Total revenues	$	2,292		$	2,310		$	1,045
Operating income	$	144		$	554		$	98
Capital expenditure activity(b)	$	(1,313)		$	(1,510)		$	(1,232)

__________


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

Our 2019 operating results were $410 million unfavorable compared to 2018. The primary items impacting 2019 results compared to 2018 results include:

•$234 million unfavorable change in net gain (loss) on derivatives; and

•$350 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income.

Offset by:

•$222 million increase in product revenues, primarily oil sales. Overall, $584 million related to higher production sales volumes substantially offset by $362 million related to lower sales prices.

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 premier geology in the plays and in North America. Over the same period, we 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 made additional investments during 2018 in our equity positions in two companies that own pipeline systems in the Delaware Basin. In 2019, we closed on transactions and monetized the value in those equity positions totaling approximately $500 million and utilized those proceeds to reduce debt. In addition to these monetizations and debt reduction, WPX took other steps to enhance its value proposition, including launching a share buyback program, generating free cash flow and lowering our weighted-average interest rate on long-term debt.

In the latter half of 2019, we communicated a vision for the Company, which included, among other items, implementing a meaningful dividend, targeting a 7% to 10% free cash flow yield and driving down our leverage metric from current levels. Our focus is, in part, on the important metrics that will drive investor interest over the next 5 years and allow us to compete against any sector, not just energy.

In December 2019, we entered into an agreement with Felix Investments Holdings II, LLC ("Felix Parent") to acquire all of the issued and outstanding membership interests of Felix Energy Holdings II, LLC, or Felix (collectively, the "Felix Acquisition"), for consideration of approximately $2.5 billion ("Purchase Price"), consisting of $900 million in cash (such amount the "Unadjusted Cash Purchase Price") and 152,963,671 unregistered shares of our common stock determined by dividing $1.6 billion by $10.46 (the volume weighted-average price per share price of the Company for the ten consecutive days ending on December 13, 2019) (the "Unadjusted Equity Consideration"). The Purchase Price is subject to customary closing adjustments. See Note 17 of Notes to Consolidated Financial Statements for further discussion of the Felix Acquisition. The Felix Acquisition is consistent with the tenets in our 5-year vision and will allow us to accomplish these objectives more quickly and efficiently thru this highly de-risked, leverage neutral transaction. We plan to implement a dividend following the integration of Felix, targeting approximately $0.10 per share on an annualized basis at initiation. To fund the cash portion of the Felix Acquisition, we completed a January 2020 offering of $900 million of 4.50% Senior Notes due in 2030, the proceeds of which are held in escrow until the closing of the Felix Acquisition.

Our expected base full-year 2020 capital budget, including the impact of the Felix Acquisition assuming a late first quarter or early second quarter closing and excluding land purchases, is $1.675 billion to $1.8 billion. Planned capital for drilling and completions, including non-operated wells, is $1.625 billion to $1.725 billion for the full year 2020, with an additional $50 million to $75 million in midstream opportunities in the Delaware Basin.

Our liquidity at December 31, 2019 totaled approximately $1.5 billion, reflecting amounts available under the Credit Facility Agreement and cash on hand. Our next Senior Note maturity of $73 million is not due until 2022. As of this filing and before consideration of the Felix Acquisition, our Credit Facility Agreement is subject to a $2.1 billion borrowing base with aggregate elected commitments of $1.5 billion and a maturity date of April 17, 2023 (see Note 8 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.

Overall, we believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. However, the challenging and dynamic environment of the oil and gas industry, along with future market conditions, may alter these expectations or plans. If we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices, we will evaluate the appropriateness of adjustments to our plans.

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:

•sustainable, value driven and environmentally responsible development of our positions in the Delaware and Williston Basins;

•successful integration of Felix;

•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 or opportunistic acquisitions 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;

•inability to successfully integrate Felix’s operations or to realize cost savings, revenues or other anticipated benefits of the Felix Acquisition;

•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 since 2014. 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 $5.9 billion. In addition, the net book value associated with unproved leasehold is approximately $1.6 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

2019 vs. 2018

Revenue Analysis


	Years ended December 31,						Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2019		2018
	(Millions)
Revenues:
Oil sales	$	2,050	$	1,790	$	260	15	%
Natural gas sales	75		87		(12)		(14)	%
Natural gas liquid sales	122		148		(26)		(18)	%
Total product revenues	2,247		2,025		222		11	%
Net gain (loss) on derivatives	(153)		81		(234)		NM
Commodity management	194		204		(10)		(5)	%
Other	4		—		4		NM
Total revenues	$	2,292	$	2,310	$	(18)	(1)	%

__________

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

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

•$260 million increase in oil sales reflects $485 million related to higher production sales volumes partially offset by $225 million related to lower sales prices for 2019 compared to 2018. The increase in production sales volumes was primarily driven by our Williston Basin. The Williston Basin volumes increased 41 percent to 57.2 MBbls per day from 40.6 MBbls per day for 2019 and 2018, respectively. The Delaware Basin volumes increased 13 percent to 46.4 MBbls per day from 41.0 MBbls per day for 2019 and 2018, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for 2019 and 2018.


	Years ended December 31,
	2019		2018

Oil sales (per barrel)	$	54.20	$	60.14
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	(1.14)		(8.56)
Oil net price including all derivative settlements (per barrel)	$	53.06	$	51.58

Oil production sales volumes (Mbbls)	37,822		29,769
Per day oil production sales volumes (Mbbls/d)	103.6		81.6

__________

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

•$12 million decrease in natural gas sales reflects $39 million decrease related to lower gas sales prices for 2019 compared to 2018, partially offset by $27 million increase related to higher production sales volumes for 2019 compared to 2018. The increase in our production sales volumes primarily relates to our Delaware Basin, which had production volumes of 173.0 MMcf per day for 2019 compared to 137.7 MMcf per day for 2018. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2019 and 2018.


	Years ended December 31,
	2019		2018

Natural gas sales (per Mcf)	$	0.96	$	1.46
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.70		0.51
Natural gas net price including all derivative settlements (per Mcf)	$	1.66	$	1.97

Natural gas production sales volumes (MMcf)	78,354		59,365
Per day natural gas production sales volumes (MMcf/d)	214.7		162.6

__________

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

•$26 million decrease in natural gas liquids sales primarily reflects $99 million related to lower NGL sales prices partially offset by $73 million related to higher production sales volumes for 2019 compared to 2018. The Delaware Basin volumes were 20.8 MBbls per day compared to 14.2 MBbls per day for 2019 and 2018, respectively. The Williston Basin volumes were 6.8 MBbls per day compared to 4.2 MBbls per day for 2019 and 2018, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for 2019 and 2018.


	Years ended December 31,
	2019		2018

NGL sales (per barrel)	$	12.17	$	21.97
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	—		(1.98)
NGL net price including all derivative settlements (per barrel)	$	12.17	$	19.99

NGL production sales volumes (Mbbls)	10,043		6,733
Per day NGL production sales volumes (Mbbls/d)	27.5		18.4

__________

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

•$234 million unfavorable change in net gain (loss) on derivatives primarily reflects changes in crude oil derivatives that were a result of increases in 2019 of forward commodity prices relative to our hedge positions. Settlements to be received on derivatives totaled $12 million for 2019 and settlements to be paid totaled $237 million for 2018.

•$10 million decrease in commodity management revenues primarily due to lower crude sales volumes and lower prices on crude and natural gas sales. These decreases are offset by higher natural gas sales volumes in 2019 as a result of additional excess capacity in the Delaware Basin, which we utilized to purchase natural gas at depressed Delaware Basin pricing and transport to sales points outside the Basin. Related commodity management costs and expenses decreased $19 million and are discussed below.

Cost and operating expense and operating income analysis:


	Years ended December 31,						Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	Per Boe Expense
	2019		2018								2019	2018
	(Millions)
Costs and expenses:
Depreciation, depletion and amortization	$	928	$	777	$	(151)	(19)	%	$15.23	$16.75
Lease and facility operating	374		272		(102)		(38)	%	$6.13	$5.85
Gathering, processing and transportation	183		107		(76)		(71)	%	$3.01	$2.30
Taxes other than income	178		157		(21)		(13)	%	$2.92	$3.39
Exploration	95		75		(20)		(27)	%
General and administrative:
General and administrative expenses	172		150		(22)		(15)	%	$2.83	$3.22
Equity-based compensation	34		32		(2)		(6)	%	$0.57	$0.70
Total general and administrative	206		182		(24)		(13)	%	$3.40	$3.92
Commodity management	163		182		19		10	%
Net gain on sales of assets (Note 4)	—		(3)		(3)		(100)	%
Acquisition costs (Note 17)	3		—		(3)		NM
Other—net	18		7		(11)		(157)	%
Total costs and expenses	$	2,148	$	1,756	$	(392)	(22)	%
Operating income	$	144	$	554	$	(410)	(74)	%

__________

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:

•$151 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $1.52 decrease in the per Boe rate compared to 2018 primarily due to favorable technical revisions

in the Williston Basin. The decrease in the per Boe rate was also a result of the addition of new wells with lower relative cost per Boe.

•$102 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs for 2019 compared to 2018.

•$76 million increase in gathering, processing and transportation is due to growth in production volumes and the impact of new or modified contracts in the Delaware and Williston Basins.

•$21 million increase in taxes other than income related to increased product revenues, previously discussed.

•$20 million increase in exploration expenses is primarily due to higher unproved leasehold amortization in 2019.

•$24 million increase in general and administrative expenses for 2019 compared to 2018. General and administrative expenses in 2019 included $8 million for costs associated with a voluntary exit program we offered to employees. Also included in the increase is approximately $10 million higher employee incentive bonus compared to 2018. Our general and administrative expenses per BOE decreased to an average $3.40 for 2019 compared to $3.92 for 2018. Excluding the $8 million related to the voluntary exit program, our rate per Boe averaged $3.27 in 2019.

•$19 million decrease in commodity management expenses is primarily due to lower crude purchase volumes and depressed Delaware Basin pricing on physical natural gas cost of sales. These decreases are partially offset by higher natural gas sales volumes as discussed above.

•$11 million increase in other expense for 2019 compared to 2018 primarily related to an $11 million charge in 2019 associated with an offer made by us to settle certain contractual disputes in the Williston Basin (See Note 4 of Notes to Consolidated Financial Statements for details of this expense).

Results below operating income


	Years ended December 31,						Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2019		2018
	(Millions)
Operating income	$	144	$	554	$	(410)	(74)	%
Interest expense	(159)		(163)		4		2	%
Loss on extinguishment of debt	(47)		(71)		24		34	%
Gains on equity method investments transactions	380		—		380		NM
Equity earnings (loss)	9		(6)		15		NM
Other income	1		2		(1)		(50)	%
Income from continuing operations before income taxes	328		316		12		4	%
Provision for income taxes	70		74		4		5	%
Income from continuing operations	258		242		16		7	%
Loss from discontinued operations	(2)		(91)		89		98	%
Net income	$	256	$	151	$	105	70	%

__________

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

Interest expense decreased in 2019 compared to 2018 due to a lower amount of average debt outstanding in 2019 and lower average interest rates. Offsetting these decreases was approximately $3 million of fees for a bridge facility related to the Felix Acquisition.

In the third quarter of 2019, we issued $600 million of Senior Notes due in 2027. The net proceeds from this offering were used to fund the purchase of $550 million aggregate principal amount of our 2022 Notes and 2023 Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $47 million in 2019. In the second quarter of 2018, we used proceeds from the San Juan Gallup disposition and proceeds from the issuance of $500 million of 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 2018. See Note 8 of Notes to Consolidated Financial Statements for additional information regarding these transactions.

Gains on equity method investments transactions in 2019 related to the sale of our 20 percent equity interest in the Whitewater natural gas pipeline and a distribution received related to our 25 percent equity interest in the Oryx pipeline. See Note 5 of Notes to Consolidated Financial Statements for details of these transactions.

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. See Note 2 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 2020 are cash on hand, expected cash flows from operations, contributions from noncontrolling interests (see Note 14 of Notes to Consolidated Financial Statements), 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 2020. These goals include implementing a meaningful dividend, targeting a 7 percent to 10 percent free cash flow yield, driving down our leverage metrics from current levels and continuing to opportunistically repurchase our shares. 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 2020:

•our planned capital expenditures, excluding acquisitions, are estimated to be approximately $1.675 billion to $1.8 billion of which $1.625 billion to $1.725 billion relates to drilling and completions, including facilities; and

•we have hedged a portion of our anticipated 2020 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 expenditures discussed above include:

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

•our ability to successfully integrate Felix's operation or to realize costs savings, revenues or other anticipated benefits of the Felix Acquisition;

•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 defined in Note 8 of Notes to Consolidated Financial Statements), includes total commitments of $1.5 billion, on a $2.1 billion Borrowing Base with a maturity date of April 17, 2023. Based on our current credit ratings, a Collateral Trigger Period applies that 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 8 of Notes to Consolidated Financial Statements. As of December 31, 2019, WPX had no borrowings outstanding and $28 million of letters of credit issued under the Credit Facility. Additionally, WPX was in compliance with our covenants under the Credit Facility as of December 31, 2019. Our unused borrowing availability was $1,472 million as of December 31, 2019.

Strategic Partnerships

In September and October 2019, we entered into strategic relationships with two third-parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022, respectively. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. WPX will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds.

Pending Felix Acquisition

As previously discussed, we signed an agreement in December 2019 to purchase Felix Investments Holdings II, LLC for $2.5 billion. The closing is expected in first-quarter 2020. The $900 million cash portion and transaction costs at closing will be funded by the proceeds from the senior notes discussed below and, if necessary, our Credit Facility.

On January 10, 2020, we completed our debt offering of $900 million aggregate principal amount of 4.50% senior unsecured notes due 2030. The proceeds were deposited into an escrow account upon the closing of the offering. Upon release

from escrow, WPX intends to use the proceeds to finance a portion of the cash consideration of the Felix Acquisition and to pay certain fees and expenses (see Note 17 of Notes to Consolidated Financial Statements).

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	2020				2021
	Volume (Bbls/d)	Weighted Average Price ($/Bbl)		Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Fixed Price Swaps—WTI(a)	65,129	$	57.07	—	$	—
Fixed Price Swaptions—WTI	—	$	—	20,000	$	57.02
Fixed Price Costless Collars—WTI	20,000	$53.33 - $63.48		—	$	—
Basis Swaps— Midland/Cushing	7,486	$	(1.31)	—	$	—
Basis Swaps— Brent/WTI Spread	5,000	$	8.36	1,000	$	8.00
Basis Swaps— Nymex Calendar Monthly Avg Roll	8,361	$	0.57	—	$	—

__________

(a) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests.


Natural Gas	2020				2021
	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)		Volume (BBtu/d)	Weighted Average Price ($/MMBtu)

Basis Swaps—Waha	60	$	(0.79)	70	$	(0.59)

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 26, 2020 were as follows:


Standard and Poor’s:
Corporate Credit Rating						BB-
Senior Unsecured Debt Rating						BB-
Outlook						Watch Positive
Moody’s Investors Service:
LT Corporate Family Rating						Ba3
Senior Unsecured Debt Rating						B1
Outlook						Review For Upgrade
Fitch Ratings:
LT Corporate Family Rating						BB
Senior Unsecured Debt Rating						BB
Outlook						Positive Watch

At the time of the Felix Acquisition announcement or shortly thereafter, all three credit rating agencies indicated that WPX could receive credit rating upgrades following the closing of the Felix Acquisition.

Sources (Uses) of Cash


	Years Ended December 31,
	2019		2018		2017
	(Millions)
Net cash provided by (used in):
Operating activities	$	1,257	$	883	$	507
Investing activities	(773)		(896)		(1,436)
Financing activities	(422)		(170)		624
Increase (decrease) in cash and cash equivalents and restricted cash	$	62	$	(183)	$	(305)

Operating activities

Net cash provided by operating activities increased in 2019 from 2018 primarily due to higher production volumes in 2019 and realizations on our derivatives, partially offset by higher operating costs and lower commodity prices. Additionally, 2019 includes the receipt of approximately $38 million related to an alternative minimum tax credit refund (see Note 9 of Notes to Consolidated Financial Statements).

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.

Total cash provided by operating activities related to discontinued operations excluding changes in working capital was approximately $44 million and $143 million for 2018 and 2017, respectively. Cash outflows related to previous accruals for Powder River Basin gathering and transportation contracts retained were $28 million, $47 million and $53 million for 2019, 2018 and 2017, respectively.

Investing activities

The table below reflects capital expenditures, exclusive of partnerships, for the periods presented.


	Years Ended December 31,
	2019			2018		2017
	(Millions)
Incurred capital expenditures:
Drilling, completions and facilities	$	1,092		$	1,327	$	880
Land acquisitions	114			65		63
Infrastructure	91			81		102
Other	16			10		10
Discontinued operations, primarily drilling and completions	—			27		177
Total incurred capital expenditures	1,313		1,313	1,510		1,232
Changes in related accounts payable and accounts receivable	44			(34)		(71)
Cash capital expenditures reported on the Consolidated Statement of Cash Flows	$	1,357		$	1,476	$	1,161

Incurred capital expenditures related to partnerships was approximately $8 million in 2019.

Significant components related to proceeds from the sale of our assets are comprised of the following:

2019

•$505 million of proceeds related to transactions involving our equity method investments including our 20 percent equity interest in Whitewater natural gas pipeline and our 25 percent equity interest in the Oryx pipeline (see Note 5 of Notes to Consolidated Financial Statements); and

•$83 million in proceeds from the sale of certain non-core properties (see Note 4 of Notes to Consolidated Financial Statements).

2018

•$645 million of net proceeds from the sale of San Juan Gallup (see Note 2 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 2 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 acquisition of acreage in the Delaware Basin.

Investing activities in 2017 includes net proceeds of $338 million from the formation of the joint venture with Howard (see Note 5 of Notes to Consolidated Financial Statements).

Financing activities

The following are significant financing activities by year:

2019

•$594 million of payments for retirement of long-term debt, including approximately $44 million of premium, offset by $593 million net proceeds from a debt issuance in the third quarter of 2019. See Note 8 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance;

•$330 million of net repayments on the Credit Facility; and

•$58 million of payments for repurchases of common stock under a share repurchase program approved by the Board of Directors in third-quarter 2019 (see Note 14 of Notes to Consolidated Financial Statements).

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 8 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance;

•$330 million net borrowings on the Credit Facility; and

•$11 million of preferred stock dividends.

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 acquisition of acreage in the Delaware Basin;

•$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.

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, 2019 and December 31, 2018. Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a 2018 divestment (see Note 2 of Notes to Consolidated Financial Statements).

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2019.


	2020		2021 – 2022		2023 – 2024		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal	$	—	$	73	$	1,056	$	1,100	$	2,229
Interest	132		262		222		138		754
Operating leases and associated service commitments:
Drilling rig commitments(a)	73		23		1		—		97
Other	26		16		—		—		42
Transportation commitments(b)	114		181		151		315		761
Oil and gas activities(c)(d)	107		99		77		38		321
Financial derivatives(e)	82		—		—		—		82
Other	14		14		3		1		32
Total obligations	$	548	$	668	$	1,510	$	1,592	$	4,318

__________

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

(b) Includes firm demand obligations of $22 million of which $21 million is recorded as a liability as of December 31, 2019. A liability was recorded in 2015 in conjunction with our exit from the Powder River Basin (see Note 2 of Notes to Consolidated Financial Statements). Excludes additional commitments totaling $875 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 $17 million of which $15 million is recorded as a liability as of December 31, 2019. 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.

(d) Excluded are liabilities associated with asset retirement obligations totaling $97 million as of December 31, 2019. The ultimate settlement and timing of asset retirement obligations cannot be precisely determined in advance; however, we estimate that approximately 21 percent of this liability will be settled in the next five years.

(e) Obligations for financial derivatives are based on market information as of December 31, 2019, 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. In view of (1) trends in public and political sentiment regarding environmental expectations; (2) a desire to continually improve our environmental performance; and (3) elevating attention on emerging public policy, our board added responsibilities to our Nominating and Governance Committee and changed the name to the Nominating, Governance, Environmental & Public Policy Committee. This is a recognition of the reality that new standards and requirements will emerge for producers of traditional energy. The Committee’s amended charter provides for (1) overseeing management’s monitoring and enforcement of WPX’s policies to protect the environment, including those related to flaring and emissions; (2) monitoring emerging political, social and environmental trends and major global legislative and regulatory developments that may affect or require adjustments in our business operations; and (3) advising the Board of Directors on significant stakeholder concerns and shareholder proposals relating to environmental, public policy or sustainability-related matters.

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.

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 $83 million and $101 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 $1.6 billion at December 31, 2019 and are 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, 2019 did not identify any properties with a carrying value in excess of those estimated undiscounted cash flows. Therefore, no impairment charges were recorded in 2019 based on this assessment.

The assessments described above included approximately $5.9 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 since 2014. 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 56 percent of our future production considered in the impairment assessment is in years 2025 and beyond. If the estimated commodity revenues (only one of the many estimates involved) of the predominately oil proved properties were lower by 15 to 25 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 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, 2019, 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 liability requires judgment as our state deferred tax rates can change periodically based on changes in our operations. Our state deferred tax rates are based upon our current entity structure, the jurisdictions in which we operate and corresponding statutory tax rates.

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, 2019, 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.

Of the $24 million net derivative liability at December 31, 2019, $34 million of liability 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.

There were no instruments included in Level 3 at December 31, 2019.

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 10 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, $73 million matures in 2022, $406 million matures in 2023, $650 million matures in 2024, $500 million matures in 2026 and $600 million matures in 2027. Interest rates for each group are 6.00 percent, 8.25 percent, 5.25 percent, 5.75 percent and 5.25 percent, respectively. The aggregate fair value of the senior notes is $2,400 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, 2019, we had no borrowings outstanding under the Credit Facility. See Note 8 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. We have previously disclosed the value-at-risk; however, a sensitivity analysis is predominately the disclosure used by our peers. See Notes 15 and 16 of Notes to Consolidated Financial Statements.

An assumed increase in forward prices used in the valuation of our crude oil and natural gas fixed price swap and option derivatives of $5.00 per Bbl and $0.25 per MMBtu would decrease our derivative valuation by approximately $165 million and $82 million at December 31, 2019 and December 31, 2018, respectively. Conversely, an assumed decrease in forward prices of $5.00 per Bbl and $0.25 per MMBtu would increase our derivative valuation by $151 million and $81 million at December 31, 2019 and December 31, 2018, respectively. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production economically hedged by the derivative instruments. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from this sensitivity analysis.

Our 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 liability of $24 million at December 31, 2019 and net asset of $141 million at December 31, 2018.


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, 2019, 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, 2019, 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.

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, 2019, 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, 2019, 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, 2019 and 2018, 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, 2019, and the related notes and financial statement schedule listed in the Index at Item 15.(a) and our report dated February 27, 2020 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 27, 2020

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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 27, 2020 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.


						Depreciation, Depletion, and Amortization (DD&A) of Proved Properties
Description of the Matter						The net book value of proved properties totaled $5.9 billion at December 31, 2019, and the Company recorded depreciation, depletion and amortization (DD&A) expense of $928 million for the year then ended. As discussed in Note 1, under the successful efforts method of accounting, DD&A for proved properties is recorded on a field basis using the units-of-production method. Proved developed reserves, as estimated by the Company’s internal engineering staff, are used to calculate depreciation and amortization of capitalized exploratory and development drilling costs, including lease and well equipment and intangible development costs. Total proved reserves, also estimated by the Company’s internal engineering staff, are used to calculate depletion of producing leasehold costs. Significant judgment is required by the Company’s internal engineering staff in evaluating geological and engineering data when estimating proved oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and


						gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management used independent petroleum engineers to audit the estimates prepared by the Company’s internal engineering staff as of December 31, 2019. Auditing the Company’s DD&A is especially complex because of the use of the work of the internal engineering staff and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and gas reserves.
How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating proved oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal technical person primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent petroleum engineers used to audit the estimates. In addition, in assessing whether we can use the work of the internal engineering staff and the independent petroleum engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating proved oil and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the mechanical accuracy of the DD&A calculations, including agreeing the proved oil and gas reserve amounts used to the Company’s reserve reports.

						Amortization of Unproved Lease Acquisition Costs
Description of the Matter						At December 31, 2019, unproved properties were $1.8 billion, which includes unproved lease acquisition costs. As discussed in Note 1 to the consolidated financial statements, 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 amortization of lease acquisition costs is included in exploration expense on the Consolidated Statements of Operations. Auditing the amortization of unproved leasehold acquisition costs was complex and judgmental due to the significant estimation required by management in determining the nonproductive portion of leasehold costs and the average holding period. The significant assumptions used to estimate the nonproductive portion of unproved lease acquisition costs included the Company’s historical experience or other information, such as current drilling plans and existing geological data.
How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s process for the amortization of unproved lease acquisition costs. For example, we tested controls over management’s review of the significant assumptions and inputs used in determining the amortization of unproved leasehold acquisition costs, including the estimated unsuccessful portion of unproved lease acquisition costs, and the estimated average holding period of unproved leases. Our audit procedures included, among others, evaluating the significant assumptions and the completeness and accuracy of the underlying financial data used by the Company in determining the amortization of unproved lease acquisition costs. As part of our evaluation, we considered the consistency of the significant assumptions used by management to estimate the unsuccessful portion of unproved lease acquisition costs with historical drilling results and the Company’s drilling schedule, and identified and evaluated corroborative and contrary evidence. In addition, we assessed the estimated average holding period of unproved leases by comparing to the Company’s historical experience. We also tested the mechanical accuracy of the calculation of unproved lease acquisition costs.

/s/ Ernst & Young LLP

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

Tulsa, Oklahoma

February 27, 2020

WPX Energy, Inc.

Consolidated Balance Sheets


	December 31,
	2019		2018
	(Millions)
Assets
Current assets:
Cash and cash equivalents	$	60	$	3
Accounts receivable, net of allowance	450		405
Derivative assets	57		174
Inventories	41		48
Assets classified as held for sale	—		79
Other	39		30
Total current assets	647		739
Investments	48		167
Properties and equipment, net (successful efforts method of accounting)	7,590		7,266
Derivative assets	10		4

Other noncurrent assets (Note 1)	118		27
Total assets	$	8,413	$	8,203

Liabilities and Equity
Current liabilities:
Accounts payable	$	556	$	514
Accrued and other current liabilities	251		178

Derivative liabilities	91		23
Total current liabilities	898		715
Deferred income taxes	290		201
Long-term debt, net	2,202		2,485
Derivative liabilities	—		14


Other noncurrent liabilities (Note 1)	508		487
Contingent liabilities and commitments (Note 10)
Equity:
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding at December 31, 2019 and 2018)	—		—
Common stock (2 billion shares authorized at $0.01 par value; 416.8 million and 420.6 million shares issued and outstanding at December 31, 2019 and 2018)	4		4
Additional paid-in-capital	7,692		7,734
Accumulated deficit	(3,181)		(3,437)
Total stockholders' equity	4,515		4,301


Total liabilities and equity	$	8,413	$	8,203

See accompanying notes.

WPX Energy, Inc.

Consolidated Statements of Operations


	Years Ended December 31,
	2019		2018		2017
Revenues:	(Millions, except per share amounts)
Product revenues:
Oil sales	$	2,050	$	1,790	$	879
Natural gas sales	75		87		67
Natural gas liquid sales	122		148		70
Total product revenues	2,247		2,025		1,016
Net gain (loss) on derivatives	(153)		81		3
Commodity management	194		204		25
Other	4		—		1
Total revenues	2,292		2,310		1,045
Costs and expenses:
Depreciation, depletion and amortization	928		777		542
Lease and facility operating	374		272		168
Gathering, processing and transportation	183		107		24
Taxes other than income	178		157		79
Exploration	95		75		87
General and administrative (including equity-based compensation of $34 million, $32 million and $28 million for the respective periods)	206		182		166
Commodity management	163		182		27
Net gain on sales of assets (Note 4)	—		(3)		(161)




Acquisition costs (Note 17)	3		—		—
Other—net	18		7		15
Total costs and expenses	2,148		1,756		947
Operating income	144		554		98
Interest expense	(159)		(163)		(188)
Loss on extinguishment of debt (Note 8)	(47)		(71)		(17)
Gains on equity method investments transactions	380		—		—
Equity earnings (loss)	9		(6)		—
Other income	1		2		3
Income (loss) from continuing operations before income taxes	328		316		(104)
Provision (benefit) for income taxes	70		74		(128)
Income from continuing operations	258		242		24
Loss from discontinued operations	(2)		(91)		(40)
Net income (loss)	256		151		(16)


Less: Dividends on preferred stock	—		8		15

Net income (loss) available to WPX Energy, Inc. common stockholders	$	256	$	143	$	(31)
(continued on next page)


WPX Energy, Inc.
Consolidated Statements of Operations-(Continued)
	Years Ended December 31,
	2019		2018		2017
	(Millions, except per share amounts)
Amounts available to WPX Energy, Inc. common stockholders:
Income from continuing operations	$	258	$	234	$	9
Loss from discontinued operations	(2)		(91)		(40)
Net income (loss)	$	256	$	143	$	(31)
Basic earnings (loss) per common share:
Income from continuing operations	$	0.62	$	0.57	$	0.02
Loss from discontinued operations	(0.01)		(0.22)		(0.10)
Net income (loss)	$	0.61	$	0.35	$	(0.08)
Basic weighted-average shares	420.4		408.4		395.1
Diluted earnings (loss) per common share:
Income from continuing operations	$	0.61	$	0.57	$	0.02
Loss from discontinued operations	—		(0.22)		(0.10)
Net income (loss)	$	0.61	$	0.35	$	(0.08)
Diluted weighted-average shares	422.0		411.7		397.4

See accompanying notes.

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, 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
Net income							256		256
Stock based compensation, net of tax impact					22				22
Transaction costs related to partnerships					(6)				(6)
Repurchases of common stock					(58)				(58)
Balance at December 31, 2019	$	—	$	4	$	7,692	$	(3,181)	$	4,515

See accompanying notes.

WPX Energy, Inc.

Consolidated Statements of Cash Flows


	Years Ended December 31,
	2019		2018		2017
Operating Activities(a)	(Millions)

Net income (loss)	$	256	$	151	$	(16)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	928		785		673
Deferred income tax provision (benefit)	89		84		(134)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments	86		73		158
Net (gains) losses related to equity method investments transactions and sales of assets	(380)		145		(170)
Net (gain) loss on derivatives	153		(81)		(3)
Net (payments) settlements related to derivatives	12		(237)		4

Amortization of stock-based awards	37		34		32
Loss on extinguishment of debt	47		71		17

Equity losses or undistributed equity (earnings)	(4)		6		—
Cash provided by (used in) operating assets and liabilities:
Accounts receivable	(62)		(59)		(153)
Inventories	6		(15)		(8)

Other current assets	(5)		2		(8)
Accounts payable	97		17		158
Federal income tax receivable and payable	19		(38)		12
Accrued and other current liabilities	3		(22)		(31)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	(28)		(47)		(53)
Other, including changes in other noncurrent assets and liabilities	3		14		29
Net cash provided by operating activities(a)	1,257		883		507
Investing Activities(a)
Capital expenditures(b)	(1,357)		(1,476)		(1,161)
Capital expenditures related to consolidated partnerships(c)	(5)		—		—
Proceeds from sales of assets and equity method investments transactions	592		682		193

Purchases of a business, net of cash acquired	—		—		(799)
Net proceeds from the joint venture formation	—		—		338
Purchases of or contributions to equity method investments	(18)		(102)		(8)
Distributions from equity method investments in excess of cumulative earnings	14		—		—
Other	1		—		1
Net cash provided by (used in) investing activities(a)	(773)		(896)		(1,436)
Financing Activities
Proceeds from common stock	2		10		672

Dividends paid on preferred stock	—		(11)		(15)
Payments for repurchases of common stock	(58)		—		—
Borrowings on credit facility	1,541		1,453		661
Payments on credit facility	(1,871)		(1,123)		(661)
Proceeds from long-term debt, net of discount	593		494		148
Payments for retirement of long-term debt, including premium	(594)		(986)		(165)

Taxes paid for shares withheld	(16)		(14)		(12)
Payments for debt issuance costs and credit facility amendment fees	(3)		(10)		(2)
Other	(16)		17		(2)
Net cash provided by (used in) financing activities	(422)		(170)		624
Net increase (decrease) in cash and cash equivalents and restricted cash	62		(183)		(305)

Cash and cash equivalents and restricted cash at beginning of period	18		201		506
Cash and cash equivalents and restricted cash at end of period	$	80	$	18	$	201
__________
(a) Amounts reflect both continuing and discontinued operations unless otherwise noted.
(b) Incurred capital expenditures were $1,313 million, $1,510 million and $1,232 million for the respective periods. The difference between incurred and cash capital expenditures is due to changes in related accounts payable and accounts receivable.
(c) Incurred capital expenditures were $8 million for 2019. The difference between incurred and cash capital expenditures is due to changes in related accounts payable and accounts receivable.

See accompanying notes.

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, which include oil and natural gas purchased from third-party working interest owners in operated wells and the management of various commodity contracts, such as transportation.

We had operations in the San Juan Basin, which were sold in 2017 and 2018, that are reported in 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

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

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 that 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 $20 million and $15 million as of December 31, 2019 and 2018, respectively, and is included in other current assets on the Consolidated Balance Sheets.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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,
	2019		2018
	(Millions)
Material, supplies and other	$	36	$	46
Commodity production in storage	5		2

	$	41	$	48

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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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


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

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

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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2019 and 2018 was insignificant.

Commodity management expenses

Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate.

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 3).

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 $36 million and $35 million as of December 31, 2019 and 2018, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 8) 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”) 2016-02, Leases, effective January 1, 2019. The standard requires the recognition of right-of-use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is 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. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right-of-use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess:

•whether existing contracts are or contain leases;

•lease classification for any expired or existing leases;

•initial direct costs for any existing lease; and

•whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease.

See Note 11 for additional information related to our contracts that are or contain leases.

We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019. 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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period.

Accounting Standards Not Yet Adopted

In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses. This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This ASU 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 ASU will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of material credit losses.

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 ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.

Note 2. Discontinued Operations

In first-quarter 2018, we sold our properties in the San Juan Basin’s Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of annual gathering and processing commitments that conclude in 2026; however, WPX has left in place a performance guarantee with respect to these commitments. The current remaining commitment is approximately $277 million. We believed and continue to 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 the purchaser, and the declining size of the obligations subject to the guarantee over time. As part of the divestiture, we determined 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.

In December 2017, we sold our natural gas-producing properties in the San Juan Basin for $169 million and recorded a gain of approximately $2 million. A portion of this sale closed in 2018.

Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years related to the sale of Powder River properties. See Note 10 for additional information related to the Powder River liabilities.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Summarized Results of Discontinued Operations

The following table presents the results of discontinued operations for the years presented. For the year ended December 31, 2019, our discontinued operations activity was minimal and therefore not included in the table below.


	Years Ended December 31,
	2018		2017
	(Millions)
Total revenues	$	75	$	291
Costs and expenses:
Depreciation, depletion and amortization	$	8	$	131
Lease and facility operating	7		50
Gathering, processing and transportation	12		70
Taxes other than income	5		23
Exploration	3		14
General and administrative	1		8

Accrual for contract obligations retained	—		5
Net loss—sales of assets and impairments	—		50

Accretion of liabilities related to contract obligations retained	6		6
Other—net(a)	5		(3)
Total costs and expenses	47		354
Operating income (loss)	28		(63)



Loss on sales of assets	(148)		—

Loss from discontinued operations before income taxes	(120)		(63)
Benefit for income taxes	(29)		(23)
Loss from discontinued operations	$	(91)	$	(40)

__________

(a) Includes severance tax refund received in 2017.

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 $28 million, $47 million and $53 million for 2019, 2018 and 2017, 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
	(Millions)
Cash provided by operating activities(a)		$	44	$	143
Cash capital expenditures within investing activities		$	29	$	175

__________

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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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

The following table summarizes the calculation of earnings per share.


	Years Ended December 31,
	2019		2018		2017
	(Millions, except per-share amounts)
Income from continuing operations attributable to WPX Energy, Inc.	$	258	$	242	$	24
Less: Dividends on preferred stock	—		8		15

Income from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income per common share	$	258	$	234	$	9
Basic weighted-average shares	420.4		408.4		395.1
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	1.6		3.1		2.1
Stock options	—		0.2		0.2
Diluted weighted-average shares(a)	422.0		411.7		397.4
Income per common share from continuing operations:
Basic	$	0.62	$	0.57	$	0.02
Diluted	$	0.61	$	0.57	$	0.02

__________

(a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (ii) application of the treasury stock method to certain nonvested restricted stock units. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows:


	Years Ended December 31,
	2019	2018	2017
	(Millions)


Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock	Not Applicable	11.4	19.8
Nonvested restricted stock units antidilutive under the treasury stock method	1.0	0.7	0.6

The table below includes information related to stock options that were outstanding at December 31, 2019, 2018 and 2017 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,
	2019		2018		2017
Options excluded (millions)	0.7		0.7		1.5
Weighted-average exercise price of options excluded	$	16.84	$	18.05	$	17.80
Exercise price range of options excluded	$11.75 - $21.81		$16.46 - $21.81		$14.41 - $21.81
Fourth quarter weighted-average market price	$	10.67	$	15.16	$	12.10

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 4. Asset Sales, Exploration Expenses and Other

Asset Sales

2019

During the first quarter of 2019, we closed on the sale of certain non-core properties, primarily proved, in the Delaware Basin which were held for sale at December 31, 2018. We received approximately $83 million in proceeds. No gain or loss was recorded on this transaction.

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 included 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.

Exploration Expenses

The following table presents a summary of exploration expenses.


	Years Ended December 31,
	2019		2018		2017
	(Millions)
Unproved leasehold property impairments, amortization and expiration	$	89	$	69	$	84
Geologic and geophysical costs	6		$	6	3

Total exploration expenses	$	95	$	75	$	87

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.

Other

In third-quarter 2019, we recorded an $11 million charge included in other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin. The offer is still pending.

Note 5. Investments

Catalyst Midstream Partners, LLC

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 joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity serves as operator. We account for our investment in Catalyst as an equity method investment. In connection with the joint venture formation, 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 $48 million and $58 million as of December 31, 2019 and 2018, respectively. As of December 31, 2019, the difference in our investment and our underlying equity in the net assets of Catalyst was approximately $244 million. In 2017, we deferred recognition of the $349 million we received at closing 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, 2019, the deferred amount was $339 million of which $329 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.

Other

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. During the second quarter of 2019, we received a distribution of approximately $357 million related to our 25 percent equity interest in the Oryx pipeline partnership after the

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

underlying assets were sold. This transaction is subject to post-closing adjustments. The net book value of this equity method investment was approximately $110 million as of the closing date. As a result of this transaction, we recorded a gain of $247 million.

During the first quarter of 2019, we closed on the sale of our 20 percent equity interest in the Whitewater natural gas pipeline. The net book value of this equity method investment at the time of disposition was approximately $15 million. As a result of this transaction, we recorded a $126 million gain in first-quarter 2019 and an additional $7 million gain related to contingent consideration in fourth-quarter 2019.

Note 6. Properties and Equipment

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


	Estimated Useful Life(a) (Years)	December 31,
				2019		2018
		(Millions)
Proved properties	(b)	$	8,719	$	7,289
Unproved properties and land	(c)	1,765		1,891
Gathering, processing and other facilities	15-25	403		294
Construction in progress	(c)	224		350
Other	3-40	133		125
Total properties and equipment, at cost		11,244		9,949
Accumulated depreciation, depletion and amortization		(3,654)		(2,683)
Properties and equipment—net		$	7,590	$	7,266

__________

(a) Estimated useful lives are presented as of December 31, 2019.

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

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

In first-quarter 2019, we closed a $100 million purchase of 14,000 surface acres within our Stateline operations of which a portion was allocated to unproved properties and the remainder to land.

In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin, which closed in the first quarter of 2019. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 4).

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 2019 and 2018 is presented below.


	2019		2018
	(Millions)
Balance, January 1	$	72	$	39
Liabilities incurred	11		8
Liabilities settled	(4)		(7)

Estimate revisions	14		30
Accretion expense(a)	4		2
Balance, December 31	$	97	$	72
Amount reflected as current	$	5	$	5

__________

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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 7. 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,
	2019		2018
	(Millions)
Trade	$	162	$	130
Accrual for capital expenditures	159		190
Royalties	209		170
Cash overdrafts	8		17

Other	18		7
	$	556	$	514

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,
	2019		2018
	(Millions)
Taxes other than income taxes	$	37	$	19
Accrued interest	39		45
Compensation and benefit related accruals	55		39

Gathering and transportation	6		7
Gathering and transportation related to exited areas	26		30

Lease liabilities	60		—

Other, including other loss contingencies	28		38
	$	251	$	178

Note 8. Debt and Banking Arrangements

Interest paid on debt totaled $150 million, $172 million and $178 million for 2019, 2018 and 2017, respectively.

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


	December 31,
	2019		2018
	(Millions)
Credit facility agreement	$	—	$	330
6.000% Senior Notes due 2022	73		529
8.250% Senior Notes due 2023	406		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		500
5.250% Senior Notes due 2027	600		—

Total debt	$	2,229	$	2,509
Less: Current portion of long-term debt	—		—
Total long-term debt	$	2,229	$	2,509
Less: Debt issuance costs(a)	27		24
Total long-term debt, net(a)	$	2,202	$	2,485

__________

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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Credit Facility

On April 22, 2019, the Company entered into a Third 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, gives the Company the option, if certain conditions are met, to elect during any Collateral Trigger Period that scheduled redeterminations of the Borrowing Base be made annually on April 1 instead of semi-annually.

Based on our current credit ratings, a Collateral Trigger Period applies that 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, 2019, WPX had no borrowings outstanding, had $28 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the Credit Facility.

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 April 2019, the Borrowing Base was increased to $2.1 billion and will remain in effect until the next Redetermination Date as described above. At this time, the Credit Facility Agreement is limited by the total commitments which remained at $1.5 billion.

Terms and Conditions. The Credit Facility is 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 guarantees 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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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, 2019.

Senior Note

Face Value (Millions)

Maturity Date

Interest Payment Dates

Optional Redemption Period(a)

6.000% Senior Notes due 2022 (the “2022 Notes”)

January 15, 2022

January 15, July 15

October 15, 2021

8.250% Senior Notes due 2023 (the “2023 Notes”)

406

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

5.250% Senior Notes due 2027 (the “2027 Notes”)

600

October 15,
2027

April 15, October 15

October 15, 2022

__________

(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 the applicable redemption prices set forth in the indenture, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.

See Note 17 for a discussion of Senior Notes issued subsequent to December 31, 2019.

On September 24, 2019, we completed a debt offering of $600 million of 5.250% Senior Notes due in 2027 (the “2027 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 April 15 and October 15 of each year commencing on April 15, 2020. The 2027 Notes will mature on October 15, 2027 with the option, prior to October 15, 2022, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, at any time on or after October 15, 2022, we have the option to redeem the notes, in whole or in part, at the applicable redemption

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

prices set forth in the indenture. The net proceeds from the offering of the 2027 Notes was approximately $592.5 million and approximately $2 million of debt issuance costs were capitalized.

The net proceeds from this offering were used to fund the purchase of $550 million aggregate principal amount of our 2022 Notes and 2023 Notes through cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $47 million, which includes approximately $44 million of premium and approximately $3 million write-off of previously capitalized costs.

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.

The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes, 2026 Notes and 2027 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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 9. Provision (Benefit) for Income Taxes

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


	Years Ended December 31,
	2019		2018		2017
	(Millions)
Provision (benefit):
Current:
Federal	$	(19)	$	(38)	$	(18)
State	(1)		1		1

	(20)		(37)		(17)
Deferred:
Federal	81		107		(100)
State	9		4		(11)

	90		111		(111)
Total provision (benefit)	$	70	$	74	$	(128)

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 lowered the corporate regular tax rate. The Act also 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 had current receivables of $19 million and $38 million as of December 31, 2019 and 2018, respectively, related to AMT credit carryforward refunds. In 2019, we received the $38 million and expect the $19 million to be collected in 2020. 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 and those already received.

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,
	2019			2018			2017
	(Millions)
Federal Statutory Rate	21		%	21		%	35		%
Provision (benefit) at statutory rate	$	69		$	66		$	(36)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	2			(8)			(12)
Valuation allowance on state net operating losses and other assets (net of federal benefit)	14			17			17
Deferred state income tax rate change (net of federal benefit)	(10)			(5)			(12)
Reversal of valuation allowance on federal capital loss	(10)			—			—





Provisional impact of Tax Cuts and Jobs Act	—			—			(92)
Executive compensation deduction limitation	4			4			2
Other	1			—			5
Provision (benefit) for income taxes	$	70		$	74		$	(128)

As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years.

Significant changes to our operations during 2019, 2018 and 2017 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 $10 million, $5 million and $12 million deferred tax benefit in 2019, 2018 and 2017, respectively.

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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

be recorded as they were identified during the one-year measurement period as provided for in SAB 118. However, 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,
	2019		2018
	(Millions)
Deferred tax liabilities:
Properties and equipment	$	938	$	797
Derivatives, net	—		33

Total deferred tax liabilities	938		830
Deferred tax assets:
Accrued liabilities and other	156		137
Alternative minimum tax credits	21		40
NOL and other carryovers	682		665
Derivatives, net	5		—

Total deferred tax assets	864		842
Less: valuation allowance	216		213
Total net deferred tax assets	648		629
Net deferred tax liabilities	$	290	$	201

Net cash payments (receipts) for income taxes, including AMT credit carryforward refunds, were $(38) million, $2 million and $(39) million in 2019, 2018 and 2017, respectively.

The Company has federal NOL carryovers of approximately $2.1 billion at December 31, 2019, including a $218 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, the Company has federal excess business interest expense carryover of approximately $20 million. The Company's $48 million federal capital loss carryovers have been utilized due to current year divestments.

The Company has state NOL carryovers of approximately $4.2 billion and $4.1 billion at 2019 and 2018, 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. 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, 2019, 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 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, 2019, 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 AMT credit carryforward deferred tax asset that was

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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 refunds of AMT credit carryforwards have been received, the Company may have to remit cash to the IRS. Through December 31, 2019, we have received approximately $50 million related to these AMT credit carryforwards.

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 2018 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 approximately $1 million or less for 2019, 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, 2019, the Company has approximately $9 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 that would result in a significant increase or decrease of an unrecognized tax benefit.

Note 10. Contingent Liabilities and Commitments

Contingent Liabilities

Federal gas royalties

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 subsequently 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 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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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. In February, 2019, settlement agreements with the Kansas and Missouri class claimants were executed, and on August 5, 2019, after the final fairness hearing, the court approved the settlement and entered final judgment. In the Wisconsin putative class action, the case was remanded to its originally filed court of the Western District of Wisconsin for trial.

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. In May 2019, the MDL Court remanded the case back to Kansas District Court. On December 30, 2019, Defendants petitioned the United States Court of Appeals for the Tenth Circuit to consider their motion for appeal of their motion to reconsider the denial of their motion for summary judgement. 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 in existence at the time of disposition.

The current owner/operator of properties we divested in the Powder River Basin filed for bankruptcy during the fourth quarter of 2019, and it is uncertain to what extent the current owner/operator will perform its obligations with respect to such properties. Prior to our disposition of such properties, payments under the surface use agreements were approximately $6 million annually and our recorded asset retirement obligation under GAAP related to the plugging and abandoning of wells was approximately $46 million.

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 accounted for transportation costs when calculating royalty payments. In 2017, we settled one of these claims.

As of December 31, 2019, 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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Summary

As of December 31, 2019 and December 31, 2018, the Company had accrued approximately $10 million and $11 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

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

Commitments

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. 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, 2019, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:


	Midstream Services		Transportation		Total
	(Millions)
2020	$	53	$	114	$	167
2021	48		94		142
2022	43		87		130
2023	40		75		115
2024	36		76		112
Thereafter	32		315		347
Total commitments	$	252	$	761	$	1,013

Accrued liabilities	$	15	$	21	$	36

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

Total rent expense, excluding amounts capitalized, was $25 million and $19 million in 2018 and 2017, 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 11. Leases

Our contracts that are leases or contain leases primarily relate to drilling rigs, compression units and office space. Leases are recorded on the balance sheet when the lease term exceeds one year and we direct the use of an identified asset while receiving substantially all of the economic benefit of the asset. Right-of-use assets are included in other noncurrent assets on the Consolidated Balance Sheet. Lease liabilities are included in accrued and other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheet. We have elected to include both lease and non-lease components for all significant asset classes as a single lease component for measurement purposes. Leases with an initial term of 12 months or less are not recorded on the balance sheet and lease expense for these leases is recognized as incurred. We have elected to include lease costs associated with lease terms of one month or less in our short-term lease disclosure below.

We use judgments and assumptions to determine our discount rate and whether a contract contains a lease. The discount rate used to determine the lease payment liability is based on our estimated incremental borrowing rate.

Certain of our leases include rental payments adjusted periodically for inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. From time to time we may enter into lease contracts that commence in future periods. Lease contracts that will commence subsequent to December 31, 2019 are not significant.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

The following tables include quantitative disclosures related to our leases.



	Twelve months ended December 31, 2019
	(Millions)
Lease Costs:
Leases recorded on the Consolidated Balance Sheet:
Operating lease cost—drilling rigs(a)	$	42
Operating lease cost—other(a)	19
Variable lease cost—drilling rigs(a)	6
Variable lease cost—other(a)	3
Short-term leases:
Drilling rigs(b)	41
Other(b)	116
Total lease cost	$	227
Other Information:
Cash paid for amount included in the measurement of lease liabilities:
Operating cash flows used for operating leases(a)	$	19
Investing cash flows used for operating leases(a)	$	42
Right-of-use assets obtained in exchange for new operating lease liabilities	$	44
Weighted-average remaining lease term (in years)	1.36 years
Weighted-average discount rate—operating leases	5		%

__________

(a)Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners.

(b)Includes variable lease costs on short-term leases.

The following tables include quantitative disclosures related to our leases as of December 31, 2019.


	Drilling Rigs		Real Estate, Compression and Other		Total Undiscounted Cash Flows
	(Millions)
Maturity of Lease Liabilities:
2020	$	44	$	18	$	62
2021	5		10		15
2022	—		1		1
2023	—		—		—
2024	—		—		—
Thereafter	—		—		—
					$	78
Lease Liabilities:
Current lease liabilities	$	43	$	17	$	60
Noncurrent lease liabilities	5		11		16
Total lease liabilities	$	48	$	28	$	76
Difference between undiscounted cash flows and discounted cash flows					$	2
Total right-of-use assets on Consolidated Balance Sheet					$	76

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Note 12. Employee Benefit Plans

WPX has a defined contribution plan, which matches employee contributions 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, $10 million and $11 million for 2019, 2018 and 2017, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2019, and 2018 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, 2019, 15 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 8 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 $34 million, $32 million and $28 million for of the years ended December 31, 2019, 2018 and 2017, 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, 2019 was $44 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, 2019.

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 106 thousand shares at an average price of $9.82 per share during 2019.

Nonvested Restricted Stock Units and Awards

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2019.


Restricted Stock Units	Shares	Weighted- Average Fair Value(a)
	(Millions)
Nonvested at December 31, 2018	5.4	$	15.01
Granted	3.8	$	13.16
Forfeited	(0.1)	$	13.12

Vested	(3.2)	$	13.92
Nonvested at December 31, 2019	5.9	$	14.78

__________

(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


	2019		2018		2017
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	13.16	$	16.74	$	13.76
Total fair value of restricted stock units vested during the year (millions)	$	45	$	26	$	33

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Performance-based shares granted represent 35 percent of nonvested restricted stock units outstanding at December 31, 2019. 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, 2019.


Stock Options	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value
	(Millions)			(Years)	(Millions)
Outstanding at December 31, 2018	1.1	$	16.00		$	0.3
Granted	—	$	—
Exercised	(0.1)	$	7.29
Forfeited	(0.3)	$	16.40
Outstanding at December 31, 2019	0.7	$	16.84	2.2	$	0.2
Exercisable at December 31, 2019	0.7	$	16.84	2.2	$	0.2

The total intrinsic value of options exercised was $468 thousand, $4.3 million and $224 thousand for the years ended December 31, 2019, 2018 and 2017, respectively.

Cash received from stock option exercises was $0.5 million, $9.2 million and $0.4 million during 2019, 2018 and 2017, respectively.

The Company did not grant stock options during the years ended 2019, 2018 and 2017.

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. As of December 31, 2019, we have no preferred shares outstanding.

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 2019, 2018 or 2017. 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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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 an acreage acquisition in the Delaware Basin.

Stock Repurchase Program

On August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over a 24 month period. Under the share repurchase program, we may repurchase shares at management’s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume, general market conditions, legal requirements, general business conditions and corporate considerations determined by WPX’s management, such as liquidity and capital needs. This share repurchase program may be modified, suspended or terminated at any time by our Board of Directors. As of December 31, 2019, we have repurchased approximately 5.7 million shares under the program at an average price of $10.16.

Transaction Costs Related to Partnerships

In September and October 2019, we entered into strategic relationships with two third-parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022, respectively. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. During 2019, we incurred approximately $6 million of partnership equity commitment and issuance costs, which are recognized as a reduction of additional paid-in-capital within stockholders’ equity attributable to WPX. The Company will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds.

WPX holds a controlling financial interest in these partnerships. Accordingly, we will consolidate the financial results of these entities and will present the portion attributable to the third parties as a noncontrolling interest in our consolidated financial statements.

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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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


	December 31, 2019														December 31, 2018
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)														(Millions)
Energy derivative assets	$	—	$	67	$	—	$	67	$	—	$	175	$	3	$	178
Energy derivative liabilities	$	—	$	91	$	—	$	91	$	—	$	37	$	—	$	37
Total debt(a)	$	—	$	2,400	$	—	$	2,400	$	—	$	2,414	$	—	$	2,414

__________

(a) The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of December 31, 2019 and 2018, 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 or 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 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 liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Forward, swap, option and swaption contracts are considered Level 2 and 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 calls, costless collars, 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 swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedged prices on the swaps. The sold calls or swaptions establish a maximum price we will receive for the volumes under contract and are financially settled. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 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

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million and $3 million included in Level 3 as of December 31, 2019 and 2018, respectively.

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, 2019 or 2018.

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 4 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 2 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.

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, 2019.


Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	2020	Fixed Price Swaps(d)	WTI	(65,129)	$	57.07
Crude Oil	2020	Fixed Price Costless Collars	WTI	(20,000)	53.33 -63.48

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	2021	Fixed Price Swaptions	WTI	(20,000)	$	57.02
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75

Natural Gas
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, collars or 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.

(d) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests.

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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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,
	2019		2018		2017
	(Millions)
Gain (loss) from derivatives related to production(a)	$	(150)	$	78	$	3
Gain (loss) from derivatives related to physical marketing agreements(b)	(3)		3		—
Net gain (loss) on derivatives	$	(153)	$	81	$	3

__________

(a) Includes settlements totaling $12 million for the year ended December 31, 2019, payments totaling $237 million for the year ended December 31, 2018, and settlements totaling $4 million for the year ended December 31, 2017.

(b) Includes payments totaling less than $1 million for the years ended December 31, 2019, 2018 and 2017.

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, 2019	(Millions)
Derivative assets with right of offset or master netting agreements	$	67	$	(45)	$	22
Derivative liabilities with right of offset or master netting agreements	$	(91)	$	45	$	(46)

December 31, 2018
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	$	—

__________

(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, 2019, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $46 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, 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 $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $46 million and less than $1 million at December 31, 2019 and 2018, respectively.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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,
	2019		2018
	(Millions)
Receivables by product or service:
Sale of natural gas, crude and related products and services	$	336	$	269
Joint interest owners	88		98
Income tax receivable	19		38
Other	7		—
Total	$	450	$	405

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 2019, 2018 and 2017, 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 $67 million and $22 million, respectively, as of December 31, 2019. 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 five largest net counterparty positions represent approximately 98 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, 2019, we held collateral support of $40 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.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

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,
	2019	2018	2017
United Energy Trading LLC	20%	23%	(a)
Occidental Energy Marketing	18%	16%	(a)
Crestwood Midstream Partners LP	(a)	(a)	21%
St. Paul Refining	(a)	(a)	16%
NGL Crude Logistics	13%	14%	13%
Delek Refining, Ltd	(a)	(a)	10%
BP Products North America, Inc.	11%	(a)	(a)

__________

(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 a subsidiary of NGL Energy, noted in the table above as NGL Crude Logistics. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 2 percent of operating expenses.

Note 17. Pending Felix Acquisition

On December 15, 2019, we entered into a Securities Purchase Agreement (the "Purchase Agreement") with Felix Investments Holdings II, LLC ("Felix Parent") to acquire all of the issued and outstanding membership interests of Felix Energy ("Felix") (collectively, the "Felix Acquisition"), for consideration of approximately $2.5 billion (the "Unadjusted Purchase Price"), consisting of $900 million in cash (the "Unadjusted Cash Purchase Price"), and 152,963,671 unregistered shares of our common stock (the "Unadjusted Equity Consideration") determined by dividing $1.6 billion by $10.46, the volume weighted average per share price of the Company for the ten consecutive trading days ending on December 13, 2019. The Unadjusted Purchase Price is subject to certain customary closing adjustments set forth in the Purchase Agreement. If certain closing adjustments are positive, the Unadjusted Cash Purchase Price is adjusted and if certain closing adjustments are negative, the Unadjusted Equity Consideration is adjusted. WPX plans to fund the cash portion through the issuance of $900 million of senior notes (see "Financing Transaction" below). We expect to close the Felix Acquisition in the first quarter of 2020, subject to satisfaction of customary closing conditions and pending shareholder approval. As of December 31, 2019, we have accrued approximately $3 million of acquisition bridge facility fees, included in interest expense, and approximately $3 million of acquisition costs, primarily related to legal and advisory fees, reflected on a separate line item on the Consolidated Statement of Operations. Additional expenses will be incurred upon closing.

Felix Parent has a senior secured notes facility pursuant to that certain Note Purchase Agreement, dated as of August 9, 2017 (as amended, restated, amended and restated, supplemented and otherwise modified prior to the date hereof, the "Felix Parent Notes Facility"), and Felix has a reserve-based revolving credit facility pursuant to that certain Credit Agreement dated as of July 1, 2016 (as amended, restated, amended and restated, supplemented and otherwise modified prior the date hereof, the "Felix Revolving Credit Facility" and together with the Felix Parent Notes Facility, the "Felix Debt Facilities"). The Felix Parent Notes Facility is secured by a lien on the equity of Felix and certain of Felix's assets. As a condition to and simultaneous with the closing of the Felix Acquisition, all remaining amounts outstanding under the Felix Debt Facilities are to be repaid in order to cause the release of such liens and terminate the facilities. Any amounts outstanding under the Felix Debt Facilities that are repaid from the Unadjusted Cash Purchase Price in connection with and simultaneous with the closing of the Felix Acquisition will result in a reduction in the Unadjusted Cash Purchase Price received by Felix Parent. Furthermore, in connection with entering into the Purchase Agreement, Felix Parent received commitments from certain of its affiliates to finance the repayment of any amounts outstanding under the Felix Debt Facilities to the extent such amounts outstanding exceed the Unadjusted Cash Purchase Price subject to certain adjustments.

Pursuant to the Purchase Agreement, Felix Parent will receive our common stock as consideration and Felix Parent (and/or certain of Felix Parent's direct or indirect equity holders) will have registration rights with respect to such common stock. Following the acquisition, Felix will be our wholly-owned subsidiary.

WPX Energy, Inc.

Notes to Consolidated Financial Statements-(Continued)

Felix is engaged in the acquisition, development and production of oil and gas properties in the Permian Basin, and more specifically in the Delaware Basin sub-area. All of Felix's Permian properties are located in the Delaware Basin and include approximately 58,500 net acres with six productive benches, with core operations located in Loving, Reeves, Ward and Winkler counties in Texas. Felix has assembled a multi-year inventory of approximately 1,500 gross drillable locations.

Financing Transaction

On January 10, 2020, we completed our debt offering of $900 million aggregate principal amount of 4.50% senior unsecured notes due 2030 (the "2030 Notes"). The proceeds were deposited into an escrow account upon the closing of the offering. Upon release from escrow, WPX intends to use the proceeds to finance a portion of the cash consideration of the Felix Acquisition and to pay certain fees and expenses.

The Notes are the Company’s senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. The 2030 Notes bear interest at a rate of 4.50% per annum and were priced at 100.0% of par. Interest is payable on the 2030 Notes semi-annually in arrears on January 15 and July 15 of each year commencing on July 15, 2020. The 2030 Notes will mature on January 15, 2030. At any time prior to January 15, 2023, the Company may, on one or more occasions and subject to certain conditions described in the Indenture, redeem up to 35% of the aggregate principal amount of the Notes at a redemption price equal to 104.5% of the principal amount of the Notes redeemed with an amount of cash not greater than the net proceeds that the Company raises in certain equity offerings, as described in the Indenture. The Company also has the option, at any time prior to January 15, 2025, on one or more occasions, to redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus a specified “make whole” premium as described in the Indenture. At any time on or after January 15, 2025, the Company may, on one or more occasions, redeem the Notes, in whole or in part, at the applicable redemption prices set forth in the Indenture. The Indenture contains covenants that, among other things, restrict the Company’s ability to grant liens on its assets and merge, consolidate or transfer or lease all or substantially all of its assets, subject to certain qualifications and exceptions.

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
2019	(Millions, except per-share amounts)
Product revenues	$	507	$	558	$	581	$	601
Net gain (loss) on derivatives	$	(207)	$	78	$	175	$	(199)
Commodity management	$	59	$	58	$	38	$	39
Total revenues	$	359	$	695	$	795	$	443
Operating costs and expenses	$	410	$	422	$	454	$	472
Operating income (loss)	$	(149)	$	181	$	242	$	(130)
Income (loss) from continuing operations	$	(48)	$	305	$	122	$	(121)
Loss from discontinued operations	—		—		(1)		(1)
Net income (loss)	$	(48)	$	305	$	121	$	(122)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	(48)	$	305	$	122	$	(121)
Loss from discontinued operations	—		—		(1)		(1)
Net income (loss)	$	(48)	$	305	$	121	$	(122)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.11)	$	0.72	$	0.29	$	(0.29)

Net income (loss)	$	(0.11)	$	0.72	$	0.29	$	(0.29)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(0.11)	$	0.72	$	0.29	$	(0.29)

Net income (loss)	$	(0.11)	$	0.72	$	0.29	$	(0.29)
2018
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	$	6	$	(3)	$	26	$	525
Income (loss) from continuing operations	$	(26)	$	(79)	$	(6)	$	353
Income (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
Income (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

100

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

First-quarter 2019:

•$126 million gain on sale of our 20 percent equity interest in the Whitewater natural gas pipeline (see Note 5).

Second-quarter 2019:

•$247 million gain related to a distribution received for our 25 percent equity interest in the Oryx pipeline partnership after the underlying assets were sold (see Note 5).

Third-quarter 2019:

•$47 million loss on extinguishment of debt (see Note 8).

•$11 million charge included in Other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin (see Note 4).

Fourth-quarter 2019:

•$7 million additional gain on sale of our 20 percent equity interest in the Whitewater natural gas pipeline (see Note 5).

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 2).

Second-quarter 2018:

•$71 million loss on extinguishment of debt (see Note 8).

101

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.

The following information includes activity through the completion of any asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan Basin, 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.

Capitalized Costs


	As of December 31,
	2019		2018
	(Millions)
Proved Properties	$	8,928	$	7,612
Unproved properties	1,765		1,891
	10,693		9,503
Accumulated depreciation, depletion and amortization and valuation provisions	(3,491)		(2,542)
Net capitalized costs	$	7,202	$	6,961

__________

•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $350 million and $276 million, net, as of December 31, 2019 and 2018, 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,
	2019		2018		2017
	(Millions)
Acquisition	$	115	$	68	$	864
Exploration	8		7		5
Development	1,099		1,350		1,048
	$	1,222	$	1,425	$	1,917

__________

•Costs incurred include capitalized and expensed items but excludes costs associated with facilities.

•Acquisition costs are as follows: Costs in 2019 primarily reflect the purchase of surface acreage within our Delaware Basin acreage. 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 in March 2017 that included approximately $200 million and 23.8 MMboe of proved developed reserves and facilities.

•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 operations were $24 million and $168 million for 2018 and 2017, respectively.

102

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.

103

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, 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
Revisions	(10.7)	41.4	8.6	4.8

Divestitures	(3.7)	(10.7)	(0.8)	(6.3)
Extensions and discoveries	56.7	170.7	25.5	110.7
Production	(37.8)	(78.4)	(10.0)	(60.9)
Proved reserves at December 31, 2019	295.8	740.7	108.3	527.6

Proved developed reserves:
December 31, 2017	130.3	321.2	38.8	222.7
December 31, 2018	156.4	365.4	48.4	265.8
December 31, 2019	184.3	456.5	65.5	325.9

Proved undeveloped reserves:
December 31, 2017	133.4	269.8	35.2	213.5
December 31, 2018	134.9	252.3	36.6	213.5
December 31, 2019	111.5	284.2	42.8	201.7

__________

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

•Revisions in 2019 primarily reflect 21 MMboe of positive technical revisions partially offset by 16 MMboe of negative revisions due to a decrease in the 12 month average price. 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.

•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.

•Extensions and discoveries in 2019 reflect 42 MMboe added for proved developed locations primarily in the Permian Basin and 68 MMboe added for proved undeveloped locations in the Permian Basin. 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.

104

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, 2019, 2018 and 2017 was $53.62, $61.57 and $46.39 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $0.97, $1.21 and $1.67 per Mcf, respectively. The average NGL price per barrel was $13.23, $26.76 and $21.16 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,
	2019		2018
	(Millions)
Future cash inflows	$	18,012	$	20,963
Less:
Future production costs	8,407		7,615
Future development costs	1,469		2,345
Future income tax provisions	772		1,366
Future net cash flows	7,364		9,637
Less 10 percent annual discount for estimated timing of cash flows	3,233		4,446
Standardized measure of discounted future net cash inflows	$	4,131	$	5,191

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


	For the years ended December 31,
	2019		2018		2017
	(Millions)
Beginning of year	$	5,191	$	3,161	$	1,038
Sales of oil and gas produced, net of operating costs	(1,515)		(1,541)		(894)
Net change in prices and production costs	(2,247)		2,004		1,385
Extensions, discoveries and improved recovery, less estimated future costs	667		1,341		816
Development costs incurred during year	636		654		345
Changes in estimated future development costs	585		(35)		105
Purchase of reserves in place, less estimated future costs	—		27		305
Sale of reserves in place, less estimated future costs	(63)		(409)		20
Revisions of previous quantity estimates	85		75		30
Accretion of discount	548		324		104
Net change in income taxes	260		(396)		(83)
Other	(16)		(14)		(10)
Net changes	(1,060)		2,030		2,123
End of year	$	4,131	$	5,191	$	3,161

105

WPX Energy, Inc.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS


	Beginning Balance		Charged (Credited) to Costs and Expenses		Other		Deductions		Ending Balance

2019:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	—	$	9	$	—	$	—	$	9
Deferred tax asset valuation(a)	213		3		—		—		216


2018:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	2	$	—	$	—	$	(2)	$	—
Deferred tax asset valuation(a)	195		18		—		—		213

Price-risk management credit reserves—liabilities(b)(c)	4		—		(4)		—		—
2017:
Allowance for doubtful accounts—accounts and notes receivable(a)	$	3	$	—	$	—	$	(1)	$	2
Deferred tax asset valuation(a)(d)	151		44		—		—		195

Price-risk management credit reserves—liabilities(b)(c)	5		—		(1)		—		4

__________

(a) Deducted from related assets.

(b) Deducted from related liabilities.

(d) 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.

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

106

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 2019 Changes in Internal Controls

There have been no changes during the fourth quarter of 2019 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 2020 Annual meeting of Stockholders, or our 2020 Proxy Statement, anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, 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 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, 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 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, 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 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, 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 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, under the heading “Independent Registered Public Accounting Firm.”

107

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, 2019 and 2018			65
Consolidated Statements of Operations for each year in the three-year period ended December 31, 2019			66
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2019			68
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2019			69
Notes to consolidated financial statements			70
Schedule for each year in the three-year period ended December 31, 2019:
II — Valuation and qualifying accounts			106
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)			100
Supplemental oil and gas disclosures (unaudited)			102

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

108

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)

2.4						Purchase and Sale Agreement, dated as of December 15, 2019, by and among Felix Investment Holdings II, 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 December 16, 2019)

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)

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)

4.5						Third Supplemental Indenture, dated as of May 23, 2018, 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 May 23, 2018)

4.6						Fourth Supplemental Indenture, dated as of September 24, 2019, 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 24, 2019)

4.7						Fifth Supplemental Indenture, dated as of January 7, 2020, 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 January 10, 2020)

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)

109


Exhibit No.						Description

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)

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)

110


Exhibit No.						Description
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)

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 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018) (1)

10.27						Amended and Restated WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018) (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)

111


Exhibit No.						Description
10.35						Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (Incorporated by reference to Exhibit 10.35 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2018)

10.36						Third Amendment to the Second Amended and Restated Credit Agreement dated April 22, 2019, 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 23, 2019)

10.37						Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.37 to WPX Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019)(1)

10.38						Form of Restricted Stock Unit Award Agreement between WPX Energy, Inc. and Non-Employee Directors(incorporated herein by reference to Exhibit 10.38 to WPX Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019)(1)

10.39						Form of amended Exhibit B to Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.39 to WPX Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019)(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

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

112

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 27, 2020

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 27, 2020

/s/ Clay M. Gaspar

Director, President and Chief Operating Officer

February 27, 2020

/s/ J. Kevin Vann

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

February 27, 2020

/s/ Stephen L. Faulkner

Controller

(Principal Accounting Officer)

February 27, 2020

/s/ John A. Carrig*

Director

February 27, 2020

/s/ Robert K. Herdman*

Director

February 27, 2020

/s/ Kelt Kindick*

Director

February 27, 2020

/s/ Karl F. Kurz*

Director

February 27, 2020

/s/ Henry E. Lentz*

Director

February 27, 2020

/s/ Kimberly S. Lubel*

Director

February 27, 2020

/s/ Valerie M. Williams*

Director

February 27, 2020

/s/ David F. Work*

Director

February 27, 2020

/s/ Stephen E. Brilz

*By:

Attorney-in-Fact

February 27, 2020

113