UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form	10-Q	
(Mark One)
						
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the quarterly period ended September 30, 2019
OR
						
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the transition period from to
Commission file number 1-35322

WPX Energy, Inc.	
(Exact Name of Registrant as Specified in Its Charter)	

												
Delaware		45-1836028	
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)	
3500 One Williams Center			
Tulsa,	Oklahoma		74172-0172	
(Address of Principal Executive Offices)		(Zip Code)	
855-979-2012
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
									
Title of Each Class	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 whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
																					
Large accelerated filer	 	þ	  	Accelerated filer	 	☐	
Non-accelerated filer	 	¨ (Do not check if a smaller reporting company)	  	Smaller reporting company	 	☐	
				Emerging growth company		☐	
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐  No  þ
The number of shares outstanding of the registrant’s common stock at October 30, 2019 were 416,740,907.

	

			

WPX Energy, Inc.
Index

 	 	 	Page	
Part I.	Financial Information		
	Item 1.	Financial Statements (Unaudited)		
		Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018	4	
		Consolidated Statements of Operations for the three and nine months ended September 30, 2019 and 2018	5	
	
		Consolidated Statements of Changes in Equity for the three and nine months ended September 30, 2019 and 2018	6	
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2019 and 2018	7	
		Notes to Consolidated Financial Statements	8	
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23	
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36	
	Item 4.	Controls and Procedures	37	
Part II.	Other Information		
	Item 1.	Legal Proceedings	38	
	Item 1A.	Risk Factors	38	
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38	
	Item 3.	Defaults Upon Senior Securities	38	
	Item 4.	Mine Safety Disclosures	38	
	Item 5.	Other Information	38	
	Item 6.	Exhibits	39	
Certain matters contained in this report include forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
•amounts and nature of future capital expenditures;
•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.

2

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
•availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of commodity prices and the availability and cost of capital;
•inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
•the strength and financial resources of our competitors;
•development of alternative energy sources;
•the impact of operational and development hazards;
•costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;
•changes in maintenance and construction costs;
•changes in the current geopolitical situation;
•our exposure to the credit risk of our customers;
•risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;
•risks associated with future weather conditions;
•acts of terrorism;
•other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; and
•additional risks described in our filings with the Securities and Exchange Commission (“SEC”).
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth above. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. Forward-looking statements speak only as of the date they are made. We disclaim any obligation to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018.

3

WPX Energy, Inc.
Consolidated Balance Sheets
(Unaudited) 

	September 30,
2019		December 31,
2018	
 	(Millions)	
Assets				
Current assets:				
Cash and cash equivalents	$	13 	 		$	3 	 	
Accounts receivable, net of allowance	553 	 		405 	 	
	
Derivative assets	169 	 		174 	 	
Inventories	46 	 		48 	 	
	
Assets classified as held for sale	— 	 		79 	 	
Other	35 	 		30 	 	
Total current assets	816 	 		739 	 	
Investments	51 	 		167 	 	
Properties and equipment (successful efforts method of accounting)	10,985 	 		9,949 	 	
Less—accumulated depreciation, depletion and amortization	(3,411)	 		(2,683)	 	
Properties and equipment, net	7,574 	 		7,266 	 	
Derivative assets	56 	 		4 	 	
	
Other noncurrent assets (Note 1)	123 	 		27 	 	
Total assets	$	8,620 	 		$	8,203 	 	
				
Liabilities and Equity				
Current liabilities:				
Accounts payable	$	686 	 		$	514 	 	
Accrued and other current liabilities (Note 1)	209 	 		178 	 	
	
Derivative liabilities	35 	 		23 	 	
Total current liabilities	930 	 		715 	 	
Deferred income taxes	307 	 		201 	 	
Long-term debt, net	2,201 	 		2,485 	 	
Derivative liabilities	7 	 		14 	 	

Other noncurrent liabilities (Note 1)	532 	 		487 	 	
Contingent liabilities and commitments (Note 8)				
Equity:				
Stockholders’ equity:				
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding)	— 	 		— 	 	
Common stock (2 billion shares authorized at $0.01 par value; 418.2 million and 420.6
    million shares issued and outstanding at September 30, 2019 and December 31, 2018)	4 	 		4 	 	
Additional paid-in-capital	7,698 	 		7,734 	 	
Accumulated deficit	(3,059)	 		(3,437)	 	
	
Total stockholders’ equity	4,643 	 		4,301 	 	

Total liabilities and equity	$	8,620 	 		$	8,203 	 	
See accompanying notes.

4

WPX Energy, Inc.
Consolidated Statements of Operations
(Unaudited) 
																								
 	Three months
ended September 30,		Nine months
ended September 30,	
 	2019		2018		2019		2018	
Revenues:	(Millions, except per-share amounts)	
Product revenues:								
Oil sales	$	539 	 		$	503 	 		$	1,499 	 		$	1,331 	 	
Natural gas sales	16 	 		18 	 		57 	 		51 	 	
Natural gas liquid sales	26 	 		33 	 		90 	 		99 	 	
Total product revenues	581 	 		554 	 		1,646 	 		1,481 	 	
Net gain (loss) on derivatives	175 	 		(139)	 		46 	 		(362)	 	
Commodity management	38 	 		68 	 		155 	 		168 	 	
Other	1 	 		1 	 		2 	 		1 	 	
Total revenues	795 	 		484 	 		1,849 	 		1,288 	 	
Costs and expenses:								
Depreciation, depletion and amortization	241 	 		193 	 		681 	 		551 	 	
Lease and facility operating	96 	 		68 	 		276 	 		182 	 	
Gathering, processing and transportation	49 	 		26 	 		131 	 		64 	 	
Taxes other than income	46 	 		45 	 		128 	 		116 	 	
Exploration (Note 4)	22 	 		18 	 		70 	 		54 	 	
General and administrative (including equity-based compensation of $9 million, $8
    million, $25 million and $25 million for the respective periods)	51 	 		44 	 		146 	 		131 	 	
Commodity management	36 	 		63 	 		126 	 		156 	 	

	
	
Other—net	12 	 		1 	 		17 	 		5 	 	
Total costs and expenses	553 	 		458 	 		1,575 	 		1,259 	 	
Operating income	242 	 		26 	 		274 	 		29 	 	
Interest expense	(38)	 		(38)	 		(119)	 		(123)	 	
Loss on extinguishment of debt	(47)	 		— 	 		(47)	 		(71)	 	
	
Gains on equity method investment transactions	— 	 		— 	 		373 	 		— 	 	
Investment income (loss) and other	4 	 		(2)	 		7 	 		(2)	 	
Income (loss) from continuing operations before income taxes	161 	 		(14)	 		488 	 		(167)	 	
Provision (benefit) for income taxes	39 	 		(8)	 		109 	 		(56)	 	
Income (loss) from continuing operations	122 	 		(6)	 		379 	 		(111)	 	
Loss from discontinued operations	(1)	 		(1)	 		(1)	 		(92)	 	

Net income (loss)	121 	 		(7)	 		378 	 		(203)	 	
Less: Dividends on preferred stock	— 	 		— 	 		— 	 		8 	 	
	
Net income (loss) available to WPX Energy, Inc. common stockholders	$	121 	 		$	(7)	 		$	378 	 		$	(211)	 	
Amounts available to WPX Energy, Inc. common stockholders:								
Income (loss) from continuing operations	$	122 	 		$	(6)	 		$	379 	 		$	(119)	 	
Loss from discontinued operations	(1)	 		(1)	 		(1)	 		(92)	 	
Net income (loss)	$	121 	 		$	(7)	 		$	378 	 		$	(211)	 	

	

Basic earnings (loss) per common share:								
Income (loss) from continuing operations	$	0.29 	 		$	(0.01)	 		$	0.90 	 		$	(0.29)	 	
Loss from discontinued operations	— 	 		— 	 		— 	 		(0.23)	 	
Net income (loss)	$	0.29 	 		$	(0.01)	 		$	0.90 	 		$	(0.52)	 	
Basic weighted-average shares	420.8 	 		414.0 	 		421.4 	 		404.3 	 	
Diluted earnings (loss) per common share:								
Income (loss) from continuing operations	$	0.29 	 		$	(0.01)	 		$	0.89 	 		$	(0.29)	 	
Loss from discontinued operations	— 	 		— 	 		— 	 		(0.23)	 	
Net income (loss)	$	0.29 	 		$	(0.01)	 		$	0.89 	 		$	(0.52)	 	
Diluted weighted-average shares	421.8 	 		414.0 	 		423.0 	 		404.3 	 	
See accompanying notes.

5

WPX Energy, Inc.
Consolidated Statements of Changes in Equity
(Unaudited)

	Three months ended September 30,	
 	Preferred Stock		Common
Stock		Additional
Paid-In-
Capital		Accumulated
Deficit		Total
Stockholders’
Equity	
 	(Millions)	
Balance at June 30, 2019	$	— 	 		$	4 	 		$	7,737 	 		$	(3,180)	 		$	4,561 	 	
Net income	— 	 		— 	 		— 	 		121 	 		121 	 	
Stock-based compensation, net of tax impact	— 	 		— 	 		9 	 		— 	 		9 	 	
Transaction costs (Note 10)	— 	 		— 	 		(5)	 		— 	 		(5)	 	
Repurchases of common stock	— 	 		— 	 		(43)	 		— 	 		(43)	 	
Balance at September 30, 2019	$	— 	 		$	4 	 		$	7,698 	 		$	(3,059)	 		$	4,643 	 	
										
Balance at June 30, 2018	$	232 	 		$	4 	 		$	7,483 	 		$	(3,784)	 		$	3,935 	 	
Net loss	— 	 		— 	 		— 	 		(7)	 		(7)	 	
Stock-based compensation, net of tax impact	— 	 		— 	 		11 	 		— 	 		11 	 	
Conversion of preferred stock to common stock	(232)	 		— 	 		232 	 		— 	 		— 	 	
Dividends on preferred stock	— 	 		— 	 		— 	 		— 	 		— 	 	
Balance at September 30, 2018	$	— 	 		$	4 	 		$	7,726 	 		$	(3,791)	 		$	3,939 	 	

																														
	Nine months ended September 30,	
	Preferred Stock		Common
Stock		Additional
Paid-In-
Capital		Accumulated
Deficit		Total
Stockholders’
Equity	
	(Millions)	
Balance at December 31, 2018	$	— 	 		$	4 	 		$	7,734 	 		$	(3,437)	 		$	4,301 	 	
Net income	— 	 		— 	 		— 	 		378 	 		378 	 	
Stock-based compensation, net of tax impact	— 	 		— 	 		12 	 		— 	 		12 	 	
Transaction costs (Note 10)	— 	 		— 	 		(5)	 		— 	 		(5)	 	
Repurchases of common stock	— 	 		— 	 		(43)	 		— 	 		(43)	 	
Balance at September 30, 2019	$	— 	 		$	4 	 		$	7,698 	 		$	(3,059)	 		$	4,643 	 	
										
Balance at December 31, 2017	$	232 	 		$	4 	 		$	7,479 	 		$	(3,588)	 		$	4,127 	 	
Net loss	— 	 		— 	 		— 	 		(203)	 		(203)	 	
Stock-based compensation, net of tax impact	— 	 		— 	 		23 	 		— 	 		23 	 	
Conversion of preferred stock to common stock	(232)	 		— 	 		232 	 		— 	 		— 	 	
Dividends on preferred stock	— 	 		— 	 		(8)	 		— 	 		(8)	 	
Balance at September 30, 2018	$	— 	 		$	4 	 		$	7,726 	 		$	(3,791)	 		$	3,939 	 	
See accompanying notes.

6

WPX Energy, Inc.
Consolidated Statements of Cash Flows
(Unaudited)

	Nine months
ended September 30,	
 	2019		2018	
Operating Activities(a)	(Millions)	
Net income (loss)	$	378 	 		$	(203)	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:				
Depreciation, depletion and amortization	681 	 		559 	 	
Deferred income tax provision (benefit)	106 	 		(84)	 	
Provision for impairment of properties and equipment (including certain exploration expenses)	62 	 		53 	 	
Gains related to equity method investment transactions	(373)	 		— 	 	
Net (gain) loss on derivatives	(46)	 		362 	 	
Net settlements related to derivatives	3 	 		(218)	 	
	
Amortization of stock-based awards	26 	 		26 	 	
	
Loss on extinguishment of debt	47 	 		71 	 	
Net loss on sales of assets including discontinued operations	— 	 		150 	 	
Cash provided by (used in) operating assets and liabilities:				
Accounts receivable	(193)	 		(61)	 	
Inventories	1 	 		(15)	 	
	
Other current assets	(2)	 		5 	 	
Accounts payable	225 	 		71 	 	
Federal income taxes receivable	38 	 		— 	 	
Accrued and other current liabilities	(40)	 		(48)	 	
Liabilities accrued in prior years for retained transportation and gathering contracts related to
    discontinued operations	(22)	 		(37)	 	
Other, including changes in other noncurrent assets and liabilities	15 	 		21 	 	
Net cash provided by operating activities(a)	906 	 		652 	 	
Investing Activities(a)				
Capital expenditures(b)	(1,090)	 		(1,013)	 	
Proceeds from sales of assets and equity method investment transactions	589 	 		682 	 	

Contributions to or purchases of equity method investments	(18)	 		(72)	 	
Distributions from equity method investments	11 	 		— 	 	
Other	1 	 		— 	 	
Net cash used in investing activities(a)	(507)	 		(403)	 	
Financing Activities				
Proceeds from common stock	1 	 		9 	 	
	
Dividends paid on preferred stock	— 	 		(11)	 	
Payments for repurchases of common stock	(43)	 		— 	 	
Borrowings on credit facility	1,281 	 		726 	 	
Payments on credit facility	(1,611)	 		(638)	 	
Proceeds from long-term debt, net of discount	593 	 		494 	 	
Payments for retirement of long-term debt, including premium	(594)	 		(986)	 	
Taxes paid for shares withheld	(16)	 		(13)	 	
	
Payments for debt issuance costs and credit facility amendment fees	(2)	 		(10)	 	
Other	6 	 		29 	 	
Net cash used in financing activities	(385)	 		(400)	 	
Net increase (decrease) in cash and cash equivalents and restricted cash	14 	 		(151)	 	
	
Cash and cash equivalents and restricted cash at beginning of period	18 	 		201 	 	
Cash and cash equivalents and restricted cash at end of period	$	32 	 		$	50 	 	
__________				
(a) Amounts reflect continuing and discontinued operations unless otherwise noted.				
(b) Increase to properties and equipment	$	(1,030)	 		$	(1,074)	 	
Changes in related accounts payable and accounts receivable	(60)	 		61 	 	
Capital expenditures	$	(1,090)	 		$	(1,013)	 	

See accompanying notes.

7

WPX Energy, Inc.
Notes to Consolidated Financial Statements

Note 1. Description of Business and Basis of Presentation
Description of Business
Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from other third-parties in our operating areas in conjunction with the management of various commodity related contracts such as transportation.
We have sold certain operations which are reported as discontinued operations and are discussed in Note 2 of Notes to Consolidated Financial Statements.
The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.”
Basis of Presentation
The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2018 in the Company's Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2019, results of operations for the three and nine months ended September 30, 2019 and 2018, changes in equity for the three and nine months ended September 30, 2019 and 2018, and cash flows for the nine months ended September 30, 2019 and 2018. The Company has no element of comprehensive income (loss) other than net income (loss).
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations
See Note 2 for a discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

8

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
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 9 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 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 Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. 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
9

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
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.
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 associated with our exit from the Powder River Basin.
Summarized Results of Discontinued Operations
The following table presents the results of our discontinued operations for the nine months ended September 30, 2018. For the three and nine months ended September 30, 2019 and the three months ended September 30, 2018, our discontinued operations activity was minimal and therefore is not included in the table below.

		Nine months
ended September 30,	
		2018	
 	(Millions)	
Total revenues		$	75 	 	
Costs and expenses:			
Depreciation, depletion and amortization		$	8 	 	
Lease and facility operating		7 	 	
Gathering, processing and transportation		12 	 	
Taxes other than income		5 	 	
General and administrative		1 	 	
	
Exploration		3 	 	

	
Accretion for transportation and gathering obligations retained		5 	 	
Other—net		4 	 	
Total costs and expenses		45 	 	
Operating income		30 	 	

	
Loss on sale of assets		(151)	 	
Loss from discontinued operations before income taxes		(121)	 	
Income tax benefit		(29)	 	
Loss from discontinued operations		$	(92)	 	

Cash Flows Attributable to Discontinued Operations
Cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $22 million and $37 million for the nine months ended September 30, 2019 and 2018, respectively. In addition, cash flows related to San Juan Gallup were $44 million of cash provided by operating activities, excluding income taxes and changes in working capital items, and $29 million of cash capital expenditures within investing activities for the nine months ended September 30, 2018.

		

		

10

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.
																								
 	Three months
ended September 30,		Nine months
ended September 30,	
 	2019		2018		2019		2018	
 	(Millions, except per-share amounts)	
Income (loss) from continuing operations	$	122 	 		$	(6)	 		$	379 	 		$	(111)	 	
Less: Dividends on preferred stock	— 	 		— 	 		— 	 		8 	 	
	
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share	$	122 	 		$	(6)	 		$	379 	 		$	(119)	 	

								
Basic weighted-average shares	420.8 	 		414.0 	 		421.4 	 		404.3 	 	
	
Effect of dilutive securities(a)	1.0 	 		— 	 		1.6 	 		— 	 	

Diluted weighted-average shares	421.8 	 		414.0 	 		423.0 	 		404.3 	 	
Earnings (loss) per common share from continuing operations:								
Basic	$	0.29 	 		$	(0.01)	 		$	0.90 	 		$	(0.29)	 	
Diluted	$	0.29 	 		$	(0.01)	 		$	0.89 	 		$	(0.29)	 	
__________
(a) Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders, or (ii) application of the treasury stock method to certain nonvested restricted stock units and awards. The excluded amounts are as follows:
																								
	Three months
ended September 30,		Nine months
ended September 30,	
	2019		2018		2019		2018	
	(Millions)	
Weighted-average nonvested restricted stock units and awards	— 	 		3.5 	 		— 	 		3.1 	 	
Weighted-average stock options	— 	 		0.2 	 		— 	 		0.2 	 	
	
Nonvested restricted stock units and awards antidilutive under the treasury stock method	4.5 	 		— 	 		4.5 	 		— 	 	

Note 4. Asset Sale, Equity Method Investment Transactions, Exploration Expenses and Other
Asset Sale
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.
Equity Method Investment Transactions
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.
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 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.

11

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
Exploration Expenses
The following table presents a summary of exploration expenses.
																								
 	Three months
ended September 30,		Nine months
ended September 30,	
 	2019		2018		2019		2018	
 	(Millions)	
Unproved leasehold property amortization	$	20 	 		$	18 	 		$	64 	 		$	51 	 	
Geologic and geophysical costs	2 	 		— 	 		6 	 		3 	 	
	
Total exploration expenses	$	22 	 		$	18 	 		$	70 	 		$	54 	 	
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. Inventories
The following table presents a summary of our inventories as of the dates indicated.
												
	September 30,
2019		December 31,
2018	
 	(Millions)	
Material, supplies and other	$	42 	 		$	46 	 	
Commodity production in transit or storage	4 	 		2 	 	
	
     Total inventories	$	46 	 		$	48 	 	

Note 6. Debt and Banking Arrangements
The following table presents a summary of our debt as of the dates indicated.
												
	September 30,
2019		December 31,
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 long-term debt	$	2,229 	 		$	2,509 	 	
Less: Debt issuance costs on long-term debt(a)	28 	 		24 	 	
     Total long-term debt, net(a)	$	2,201 	 		$	2,485 	 	
__________
(a)Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Credit Facility 
As of September 30, 2019, we had no borrowings outstanding and $37 million of letters of credit issued under the Credit Facility and we were in compliance with our financial covenants with full access to the 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, the Swingline Lender and each of the issuing banks party thereto (the "Credit Facility"). The Credit Facility, as amended, gives the Company the option, if certain conditions are
12

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
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.
Additionally 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.
See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information on covenants related to our Credit Facility. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended.
Senior Notes
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 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.
See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional discussion related to our senior notes.

Note 7. Provision (Benefit) for Income Taxes
The following table presents the provision (benefit) for income taxes from continuing operations. 
																								
 	Three months
ended September 30,		Nine months
ended September 30,	
 	2019		2018		2019		2018	
 	(Millions)	
Current:								
Federal	$	— 	 		$	— 	 		$	— 	 		$	— 	 	
State	1 	 		(1)	 		2 	 		(1)	 	
	
	1 	 		(1)	 		2 	 		(1)	 	
Deferred:								
Federal	33 	 		(6)	 		96 	 		(43)	 	
State	5 	 		(1)	 		11 	 		(12)	 	
	
	38 	 		(7)	 		107 	 		(55)	 	
Total provision (benefit)	$	39 	 		$	(8)	 		$	109 	 		$	(56)	 	

The effective income tax rate for the three months ended September 30, 2019, differs from the federal statutory rate of 21 percent due to the effect of state income taxes.
The effective income tax rate for the three months ended September 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of state income taxes.
The effective income tax rate for the nine months ended September 30, 2019, differs slightly from the federal statutory rate of 21 percent due to the effect of state income taxes and equity-based compensation, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gains from the 2019 transactions involving equity interests in partnerships.
The effective income tax rate for the nine months ended September 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of an adjustment to state deferred taxes as a result of a
13

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
decrease in the blended state income tax rate due to changes in state apportionment factors resulting from the divestment of our San Juan Basin assets.
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state net operating loss (“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. We have not recorded a valuation allowance against our federal NOL carryover, but a valuation allowance could be required in future periods if the federal NOL carryover increases or circumstances change.
The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three-year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of September 30, 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 (“RKI”). Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the acquisition.
Pursuant to our tax sharing agreement with The Williams Companies, Inc. (“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. In 2017, the IRS proposed an adjustment related to our business for which a payment to Williams could be required. We, along with Williams, have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS.
As of September 30, 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. Currently, we do not expect ultimate resolution of our uncertain tax position during the next 12 months.

Note 8. Contingent Liabilities and Commitments
Contingent Liabilities
Royalty litigation
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to many of our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.

14

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. 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 class action, defendants' motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs' motion to remand the case to the originally filed district court.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court, and the MDL Court has now remanded the case to the United States District Court for the District of Kansas. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements.
The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in such
15

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments.
As of September 30, 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.
Summary
As of September 30, 2019 and December 31, 2018, the Company had accrued approximately $11 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
During 2019, primarily in the second quarter, we contracted for additional oil and natural gas transportation capacity to other locations in attempts to avoid location constraints and obtain more favorable pricing differentials. This capacity is associated with projects for which the counterparties have not yet begun construction. Related minimum commitments, when construction is complete and facilities are in service, total approximately $880 million over a five to ten year period with annual demand payments, beginning in 2020, ranging from approximately $19 million to $118 million.

Note 9. 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 September 30, 2019 are not significant.

16

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
The following tables include quantitative disclosures related to our leases.

			
	Nine months ended September 30, 2019		
 	(Millions)	
Lease Costs:			
Leases recorded on the Consolidated Balance Sheet:			
Operating lease cost—drilling rigs(a)	$	31 	 		
Operating lease cost—other(a)	14 	 		
Variable lease cost—drilling rigs(a)	4 	 		
Variable lease cost—other(a)	3 	 		
Short-term leases:			
Drilling rigs(b)	30 	 		
Other(b)	89 	 		
Total lease cost	$	171 	 		
Other Information:			
Cash paid for amount included in the measurement of lease liabilities:			
Operating cash flows used for operating leases(a)	$	14 	 		
Investing cash flows used for operating leases(a)	$	31 	 		
Right-of-use assets obtained in exchange for new operating lease liabilities	$	44 	 		
Weighted-average remaining lease term (in years)	1.59 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 September 30, 2019.

	Drilling Rigs		Real Estate, Compression and Other		Total Undiscounted Cash Flows	
 	(Millions)	
Maturity of Lease Liabilities:						
October 2019 through December 2019	$	11 	 		$	5 	 		$	16 	 	
2020	44 	 		18 	 		62 	 	
2021	5 	 		10 	 		15 	 	
2022	— 	 		1 	 		1 	 	
2023	— 	 		— 	 		— 	 	
Thereafter	— 	 		— 	 		— 	 	
					$	94 	 	
Current lease liabilities	$	43 	 		$	17 	 		$	60 	 	
Noncurrent lease liabilities	16 	 		15 	 		31 	 	
Total lease liabilities	$	59 	 		$	32 	 		$	91 	 	
Difference between undiscounted cash flows and discounted cash flows					$	3 	 	
Total right-of-use assets on Consolidated Balance Sheet					$	91 	 	

17

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
Note 10. Stockholders' Equity
Share 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 September 30, 2019, we have repurchased approximately 4.2 million shares under the program at an average price of $10.23.
Transaction Costs
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. 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.

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. We incurred approximately $5 million of costs associated with the formation of the partnerships which are recognized as a reduction of additional paid-in-capital within stockholders’ equity attributable to WPX.

Note 11. Fair Value Measurements
The following table presents, by level within the fair value hierarchy, certain assets and liabilities at fair value on a recurring basis for disclosure. 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.

 	September 30, 2019		December 31, 2018	
 	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total	
 	(Millions)		(Millions)	
Energy derivative assets	$	— 	 		$	225 	 		$	— 	 		$	225 	 		$	— 	 		$	175 	 		$	3 	 		$	178 	 	
Energy derivative liabilities	$	— 	 		$	42 	 		$	— 	 		$	42 	 		$	— 	 		$	37 	 		$	— 	 		$	37 	 	
Total debt(a)	$	— 	 		$	2,317 	 		$	— 	 		$	2,317 	 		$	— 	 		$	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 September 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.
Energy derivatives include commodity-based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts may 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 derivative liabilities does not consider noncash collateral credit enhancements.

18

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
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 and collars that 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 hedge 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 quarterly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million and $3 million included in Level 3 as of September 30, 2019 and December 31, 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 occurred during the periods ended September 30, 2019 and 2018.
There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

Note 12. Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of crude oil, natural gas and natural gas liquids attributable to commodity price risk.
We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaption.

19

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2019.
																																	
Commodity		Period		Contract Type (a)		Location		Notional Volume (b)		Weighted Average
Price (c)	
											
Crude Oil											
	
Crude Oil		Oct - Dec 2019		Fixed Price Swaps		WTI		(83,000)	 		$	56.72 	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Midland/Cushing		(22,000)	 		$	(1.37)	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Nymex CMA Roll		(13,261)	 		$	0.11 	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Magellan East Houston		(2,000)	 		$	4.63 	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Magellan East Houston/Midland		(9,000)	 		$	6.02 	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Argus LLS/Midland		(2,000)	 		$	8.60 	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Magellan East Houston/Argus LLS		(2,000)	 		$	0.75 	 	
Crude Oil		Oct - Dec 2019		Basis Swaps		Clearbrook		(8,000)	 		$	(3.23)	 	
Crude Oil		Oct - Dec 2019		Fixed Price Calls		WTI		(5,000)	 		$	54.08 	 	
Crude Oil		Oct - Dec 2019		Fixed Price Collars		WTI		(8,000)	 		$50.00 - $60.19 	 	
Crude Oil		2020		Fixed Price Swaps		WTI		(45,000)	 		$	57.10 	 	
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		2020		Fixed Price Collars		WTI		(20,000)	 		$53.33 - $63.48 	 	
Crude Oil		2021		Basis Swaps		Brent/WTI Spread		(1,000)	 		$	8.00 	 	
Crude Oil		2022		Basis Swaps		Brent/WTI Spread		(1,000)	 		$	7.75 	 	
Natural Gas											

	
Natural Gas		Oct - Dec 2019		Fixed Price Swaps		Henry Hub		(110)	 		$	3.07 	 	
	
Natural Gas		Oct - Dec 2019		Basis Swaps		Permian		(25)	 		$	(0.39)	 	

	
Natural Gas		Oct - Dec 2019		Basis Swaps		Waha		(35)	 		$	0.81 	 	
Natural Gas		Oct - Dec 2019		Basis Swaps		Houston Ship Channel		(30)	 		$	(0.09)	 	
Natural Gas		2020		Basis Swaps		Waha		(60)	 		$	(0.79)	 	
Natural Gas		2021		Basis Swaps		Waha		(70)	 		$	(0.59)	 	
Natural Gas		2022		Basis Swaps		Waha		(70)	 		$	(0.57)	 	
Natural Gas		2023		Basis Swaps		Waha		(70)	 		$	(0.51)	 	
	
__________
(a)Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls or swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread.
(b)Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
(c)The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.
Fair values and gains (losses)
Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

20

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. Net gain (loss) on derivatives on the Consolidated Statements of Operations includes net settlements to be received of $4 million and $3 million for the three and nine months ended September 30, 2019, respectively, and net settlements to be paid of $85 million and $218 million for the three and nine months ended September 30, 2018, respectively.
The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows.
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet		Netting Adjustments (a)		Net Amount	
September 30, 2019	(Millions)	
Derivative assets with right of offset or master netting agreements	$	225 	 		$	(39)	 		$	186 	 	
Derivative liabilities with right of offset or master netting agreements	$	(42)	 		$	39 	 		$	(3)	 	
						
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 September 30, 2019, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $3 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. Assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, the additional collateral that we would have been required to post at September 30, 2019 was $3 million. 
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

21

WPX Energy, Inc.
Notes to Consolidated Financial Statements — (Continued)
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2019 and 2018, 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 $225 million and $186 million, respectively, as of September 30, 2019. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.
Our seven largest net counterparty positions represent approximately 86 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.
One of our senior officers is on the board of directors of NGL Energy Partners, LP (“NGL Energy”). In the normal course of business, we sell crude oil to NGL Energy. For the first nine months of 2019, sales to NGL Energy were approximately 13 percent of our total consolidated revenues adjusted for loss on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent approximately 1 percent of operating expenses.
Other
Collateral support for our commodity agreements could include margin deposits, letters of credit, surety bonds and guarantees of payment by credit worthy parties.

22

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes included elsewhere in this Form 10-Q and our 2018 Annual Report on Form 10-K. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Form 10-Q and our 2018 Annual Report on Form 10-K.
Unless indicated otherwise, the following discussion relates to continuing operations. See Note 2 of Notes to Consolidated Financial Statements for a discussion of discontinued operations.
Overview
Composition of production (based on MBoe) and product revenue

	Three months ended September 30,		Nine months ended September 30,		

Overall quarter volumes increased 40 percent with oil leading the increase at 30 percent for the quarter. Our oil production as a percent of total production declined compared to 2018 due to Delaware production growth which has a higher natural gas component than our Williston production. The following table presents our production volumes and financial highlights for the three and nine months ended September 30, 2019 and 2018:
																																																
 	Three months
ended September 30,		Nine months
ended September 30,	
 	2019		2018		2019		2018	
Production Sales Volume Data(a):			Per day				Per day				Per day				Per day	
Oil (MBbls)	9,991		108.6		7,670		83.4 	 		27,543		100.9		20,941		76.7 	 	
Natural gas (MMcf)	20,874		226.9		14,759		160.4 	 		57,821		211.8		40,522		148.4 	 	
NGLs (MBbls)	2,486		27.0		1,259		13.7 	 		7,267		26.6		4,313		15.8 	 	
Combined equivalent volumes (MBoe)(b)	15,955 	 		173.4		11,389 	 		123.8 	 		44,446 	 		162.8 	 		32,007 	 		117.2 	 	

	

Financial Data (millions):																
Total product revenues	$	581 	 				$	554 	 				$	1,646 	 				$	1,481 	 			
Total revenues	$	795 	 				$	484 	 				$	1,849 	 				$	1,288 	 			
Operating income (loss)	$	242 	 				$	26 	 				$	274 	 				$	29 	 			
Capital expenditure activity(c)	$	264 	 				$	370 	 				$	1,030 	 				$	1,074 	 			
 __________
(a)Excludes production from our discontinued operations.
(b)MBoe are calculated using the ratio of six Mcf to one barrel of oil.
(c)Includes capital expenditures activity related to discontinued operations of $27 million for the nine months ended September 30, 2018.

23

Our third quarter 2019 operating results were $216 million favorable compared to third quarter 2018. The primary items impacting the three months ended September 30, 2019 compared to the same period in 2018 include:
•$27 million increase in product revenues, primarily oil sales. Overall, $192 million related to higher production sales volumes substantially offset by $165 million related to lower sales prices; and
•$314 million favorable change in net gain (loss) on derivatives.
Offset by:
•$100 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income.
Our year-to-date 2019 operating results were $245 million favorable compared to year-to-date 2018. The primary items impacting the nine months ended September 30, 2019 compared to the same period in 2018 include:
•$165 million increase in product revenues, primarily oil sales. Overall, $509 million related to higher oil volumes, partially offset by $344 million related to lower sales prices; and
•$408 million favorable change in net gain (loss) on derivatives.
Offset by:
•$303 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income.
Outlook
After our multi-year transformation of WPX, our oil-prone positions in the Delaware (Permian) and Williston Basins now form the foundation of WPX. Our acreage positions in each of these basins contains some of the top geology in the plays and in North America. 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 Whitewater and Oryx pipeline systems. In 2019, we closed on transactions and monetized the value in Whitewater and Oryx totaling approximately $500 million. Overall, we believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. For 2019, we currently expect our operating cash flows to exceed our base capital expenditures plan. However, the challenging and dynamic environment of the oil and gas industry, along with future market conditions, may alter these expectations or plans. We would make appropriate adjustments to our plans if we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices.
Our expected base capital budget, excluding land purchases, for full-year 2019 is $1.125 billion to $1.25 billion. Planned capital for drilling and completions, including non-operated wells, is $1.075 billion to $1.150 billion for the full year 2019, with an additional $50 million to $100 million in midstream opportunities in the Delaware Basin.
Our liquidity at September 30, 2019 totaled approximately $1.5 billion, reflecting amounts available under the Credit Facility Agreement and cash on hand. In September 2019, we issued $600 million of 5.250% Senior Notes due 2027 and these funds were used to purchase $550 million aggregate principal amount of our 2022 and 2023 Notes. Our next Senior Note maturity of $73 million is not due until 2022. As of this filing, 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, subject to a springing maturity on October 15, 2021 (see Note 6 of Notes to Consolidated Financial Statements for further discussion). We believe our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a downturn. 
As we execute on our long-term strategy, we continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:
•value driven development of our positions in the Delaware and Williston Basins;
•continuing to pursue cost improvements and efficiency gains;
•employing new technology and operating methods;
•continuing to invest in projects to assess resources and add new development opportunities to our portfolio;
•retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and
•continuing to maintain an active economic hedging program around our commodity price risks.

24

Potential risks or obstacles that could impact the execution of our plan include:
•lower than anticipated energy commodity prices;
•increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation;
•higher capital costs of developing our properties, including the impact of inflation;
•lower than expected levels of cash flow from operations;
•counterparty credit and performance risk;
•general economic, financial markets or industry downturn;
•unavailability of capital either under our revolver or access to capital markets;
•changes in the political and regulatory environments; and
•decreased drilling success.
We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel 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 $1.7 billion and is primarily associated with our Delaware Basin properties. See our discussion of impairment of long-lived assets in our Critical Accounting Estimates discussion in our 2018 Annual Report on Form 10-K.

25

Results of Operations
Three Month-Over-Three Month Results of Operations
Revenue analysis 
																								
 	Three months
ended September 30,		Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	
 	2019		2018					
 	(Millions)		 		 	
Revenues:								
Oil sales	$	539 	 		$	503 	 		$	36 	 		7 	%	
Natural gas sales	16 	 		18 	 		(2)	 		(11)	%	
Natural gas liquid sales	26 	 		33 	 		(7)	 		(21)	%	
Total product revenues	581 	 		554 	 		27 	 		5 	%	
Net gain (loss) on derivatives	175 	 		(139)	 		314 	 		NM 	 	
Commodity management	38 	 		68 	 		(30)	 		(44)	%	
Other	1 	 		1 	 		— 	 		— 	%	
Total revenues	$	795 	 		$	484 	 		$	311 	 		64 	%	
__________
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:
•$36 million increase in oil sales reflects $152 million related to higher production sales volumes partially offset by $116 million related to lower sales prices for the three months ended September 30, 2019 compared to 2018. The increase in production sales volumes was driven by primarily by our Williston Basin. The Williston Basin volumes increased 51 percent to 61.4 MBbls per day from 40.6 MBbls per day for the three months ended September 30, 2019 and 2018, respectively. The Delaware Basin volumes increased 10 percent to 47.2 MBbls per day from 42.8 MBbls per day for the three months ended September 30, 2019 and 2018, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for the three months ended September 30, 2019 and 2018:

 	Three months
ended September 30,	
 	2019		2018	

	
Oil sales (per barrel)	53.92 	 		$	65.52 	 	
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	(1.25)	 		(11.09)	 	
Oil net price including derivative settlements (per barrel)	$	52.67 	 		$	54.43 	 	
				
Oil production sales volumes (MBbls)	9,991		7,670	
Per day oil production sales volumes (MBbls/d)	108.6		83.4	
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
26

•$2 million decrease in natural gas sales reflects $9 million related to lower sales prices offset by $7 million related to higher production sales volumes for the three months ended September 30, 2019 compared to 2018. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 180.9 Mmcf per day compared to 135.5 Mmcf per day for the three months ended September 30, 2019 and 2018, respectively. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for the three months ended September 30, 2019 and 2018:

 	Three months
ended September 30,	
 	2019		2018	

	
Natural gas sales (per Mcf)	$	0.77 	 		$	1.22 	 	
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.80 	 		0.61 	 	
Natural gas net price including derivative settlements (per Mcf)	$	1.57 	 		$	1.83 	 	
				
Natural gas production sales volumes (MMcf)	20,874 	 		14,759 	 	
Per day natural gas production sales volumes (MMcf/d)	226.9		160.4	
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$7 million decrease in natural gas liquids sales primarily reflect $40 million related to lower sales price partially offset by $33 million related to higher production sales volumes for the three months ended September 30, 2019 compared to 2018. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 19.3 MBbls per day compared to 10.0 MBbls per day for the three months ended September 30, 2019 and 2018, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for the three months ended September 30, 2019 and 2018:

 	Three months
ended September 30,	
 	2019		2018	

	
NGL sales (per barrel)	$	10.73 	 		$	26.68 	 	
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	— 	 		(7.09)	 	
NGL net price including derivative settlements (per barrel)	$	10.73 	 		$	19.59 	 	
				
NGL production sales volumes (MBbls)	2,486		1,259	
Per day NGL production sales volumes (MBbls/d)	27.0		13.7	
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$314 million favorable change in net gain (loss) on derivatives primarily reflects favorable change in crude oil derivatives which was a result of gains in 2019 due to decreases in 2019 of forward commodity prices relative to our hedge positions as opposed to losses in 2018 due to increases in 2018 of forward commodity prices relative to our hedge positions at that time. Settlements to be received on derivatives totaled $4 million for the three months ended September 30 2019 and settlements to be paid totaled $85 million for three months ended September 30, 2018, respectively.
•$30 million decrease in commodity management revenues is primarily due to lower crude sales volumes as well as lower natural gas prices. Crude sales volumes include purchases to fulfill certain sales commitments. Related commodity management costs and expenses decreased $27 million and are discussed below.

27

Cost and operating expense and operating income analysis
																																				
 	Three months
ended September 30,		Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	 		Per Boe Expense	
 	2019		2018							2019		2018	
 	(Millions)		 		 					
Costs and expenses:												
Depreciation, depletion and amortization	$	241 	 		$	193 	 		$	(48)	 		(25)	%		$15.11		$17.01	
Lease and facility operating	96 	 		68 	 		(28)	 		(41)	%		$6.02		$5.92	
Gathering, processing and transportation	49 	 		26 	 		(23)	 		(88)	%		$3.10		$2.29	
Taxes other than income	46 	 		45 	 		(1)	 		(2)	%		$2.90		$3.96	
Exploration	22 	 		18 	 		(4)	 		(22)	%					
General and administrative:												
General and administrative expenses	42 	 		36 	 		(6)	 		(17)	%		$2.69		$3.17	
Equity-based compensation	9 	 		8 	 		(1)	 		(13)	%		$0.54		$0.68	
Total general and administrative	51 	 		44 	 		(7)	 		(16)	%		$3.23		$3.85	
Commodity management	36 	 		63 	 		27 	 		43 	%					
	
Other—net	12 	 		1 	 		(11)	 		NM 	 					
Total costs and expenses	$	553 	 		$	458 	 		$	(95)	 		(21)	%					
Operating income	$	242 	 		$	26 	 		$	216 	 		NM 	 					
	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant variances in our costs and expenses are comprised of the following:
•$48 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $1.90 per Boe decrease in rate compared to September 30, 2018 primarily due to favorable technical revisions in the Williston Basin. The decrease in rate was also a result of the addition of new wells in the Williston Basin with lower relative cost per Boe.
•$28 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs.
•$23 million increase in gathering, processing and transportation primarily due to growth in production volumes and the impact of new or modified contracts in the Delaware and Williston Basins.
•$7 million increase in general and administrative expense for the three months ended September 30, 2019 compared to the same period in 2018. The three months ended September 30, 2019 included $3 million for costs associated with a voluntary exit program we offered to employees. We expect additional expense during the fourth quarter of 2019. Our general and administrative expenses per Boe decreased to an average $3.23 for the three months ended September 30, 2019 compared to $3.85 for the same period in 2018. Excluding the $3 million related to the voluntary exit program, our rate per Boe averaged $3.05 in 2019.
•$27 million decrease in commodity management expenses is primarily due to lower crude oil purchase volumes and depressed Delaware Basin pricing on physical natural gas cost of sales.
•$11 million increase in other expense primarily due to expense associated with an offer made by us to settle certain contract disputes. (See Note 4 of Notes to Consolidated Financial Statements).

28

Results below operating income
																								
 	Three months
ended September 30,		Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	 	
 	2019		2018						
 	(Millions)		 		 	
Operating income	$	242 	 		$	26 	 		$	216 	 		NM 	 	
Interest expense	(38)	 		(38)	 		— 	 		— 	%	
Loss on extinguishment of debt	(47)	 		— 	 		(47)	 		NM 	 	
	
Investment income (loss) and other	4 	 		(2)	 		6 	 		NM 	 	
Income (loss) from continuing operations before income
    taxes	161 	 		(14)	 		175 	 		NM 	 	
Provision (benefit) for income taxes	39 	 		(8)	 		(47)	 		NM 	 	
Income (loss) from continuing operations	122 	 		(6)	 		128 	 		NM 	 	
Loss from discontinued operations	(1)	 		(1)	 		— 	 		— 	%	
Net income (loss)	$	121 	 		$	(7)	 		128 	 		NM 	 	

__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
In the third quarter of 2019, we issued $600 million 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 third-quarter 2018. See Note 6 of Notes to Consolidated Financial Statements for detail of this transaction.
For the three months ended September 30, 2019, we had provision for income taxes compared to a benefit for income taxes for the same period for 2018. See Note 7 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

29

Nine Month-Over-Nine Month Results of Operations
Revenue analysis 
																								
 	Nine months
ended September 30,		Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	
 	2019		2018					
 	(Millions)		 		 	
Revenues:								
Oil sales	$	1,499 	 		$	1,331 	 		$	168 	 		13 	%	
Natural gas sales	57 	 		51 	 		6 	 		12 	%	
Natural gas liquid sales	90 	 		99 	 		(9)	 		(9)	%	
Total product revenues	1,646 	 		1,481 	 		165 	 		11 	%	
Net gain (loss) on derivatives	46 	 		(362)	 		408 	 		NM 	 	
Commodity management	155 	 		168 	 		(13)	 		(8)	%	
Other	2 	 		1 	 		1 	 		100 	%	
Total revenues	$	1,849 	 		$	1,288 	 		$	561 	 		44 	%	
__________
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:
•$168 million increase in oil sales reflects $420 million related to higher production sales volumes offset by $252 million related to lower sales prices for the nine months ended September 30, 2019 compared to 2018. The Delaware Basin volumes were 46.0 MBbls per day compared to 38.6 MBbls per day for the nine months ended September 30, 2019 and 2018, respectively. The Williston Basin volumes were 54.9 MBbls per day compared to 38.1 MBbls per day for the nine months ended September 30, 2019 and 2018, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for the nine months ended September 30, 2019 and 2018:

 	Nine months
ended September 30,	
 	2019		2018	

	
Oil sales (per barrel)	$	54.42 	 		$	63.55 	 	
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	(1.40)	 		(10.89)	 	
Oil net price including derivative settlements (per barrel)	$	53.02 	 		$	52.66 	 	
				
Oil production sales volumes (MBbls)	27,543		20,941	
Per day oil production sales volumes (MBbls/d)	100.9 	 		76.7 	 	
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
30

•$6 million increase in natural gas sales reflects $21 million in higher production sales volumes partially offset by $15 million related to lower sales prices for the nine months ended September 30, 2019 compared to 2018. The increase in our production sales volumes primarily relates to our Delaware Basin which had production volumes of 172.8 MMcf per day compared to 124.5 MMcf per day for the nine months ended September 30, 2019 compared to 2018, respectively. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for the nine months ended September 30, 2019 and 2018:

 	Nine months
ended September 30,	
 	2019		2018	

	
Natural gas sales (per Mcf)	$	0.99 	 		$	1.25 	 	
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.71 	 		0.59 	 	
Natural gas net price including derivative settlements (per Mcf)	$	1.70 	 		$	1.84 	 	
				
Natural gas production sales volumes (MMcf)	57,821		40,522	
Per day natural gas production sales volumes (MMcf/d)	211.8 	 		148.4 	 	
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$9 million decrease in natural gas liquids sales primarily reflects $77 million related to lower sales prices offset by $68 million related to higher production sales volumes for the nine months ended September 30, 2019 compared to 2018. The primary increase in natural gas liquids production volumes was in the Delaware Basin, the volumes were 20.3 MBbls per day compared to 11.7 MBbls per day for the nine months ended September 30, 2019 and 2018, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for the nine months ended September 30, 2019 and 2018:

 	Nine months
ended September 30,	
 	2019		2018	

	
NGL sales (per barrel)	$	12.42 	 		$	22.99 	 	
Impact of net cash paid related to settlement of derivatives (per barrel)(a)	— 	 		(3.10)	 	
NGL net price including derivative settlements (per barrel)	$	12.42 	 		$	19.89 	 	
				
NGL production sales volumes (MBbls)	7,267		4,313	
Per day NGL production sales volumes (MBbls/d)	26.6		15.8	
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$408 million favorable change in net gain (loss) on derivatives primarily reflects favorable change in crude oil derivatives which was a result of gains in 2019 due to decreases in 2019 of forward commodity prices relative to our hedge positions as opposed to losses in 2018 due to increases in 2018 of forward commodity prices relative to our hedge position at that time. Settlements to be received on derivatives totaled $3 million and to be paid totaled $218 million for the nine months ended September 30, 2019 and 2018, respectively.
•$13 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 pipeline 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 $30 million and are discussed below.

31

Cost and operating expense and operating income analysis
																																				
 	Nine months
ended September 30,		Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	 		Per Boe Expense	
 	2019		2018							2019		2018	
 	(Millions)		 		 					
Costs and expenses:												
Depreciation, depletion and amortization	$	681 	 		$	551 	 		$	(130)	 		(24)	%		$15.33		$17.22	
Lease and facility operating	276 	 		182 	 		(94)	 		(52)	%		$6.21		$5.68	
Gathering, processing and transportation	131 	 		64 	 		(67)	 		(105)	%		$2.96		$2.01	
Taxes other than income	128 	 		116 	 		(12)	 		(10)	%		$2.88		$3.64	
Exploration	70 	 		54 	 		(16)	 		(30)	%					
General and administrative:												
General and administrative expenses	121 	 		106 	 		(15)	 		(14)	%		$2.74		$3.27	
Equity-based compensation	25 	 		25 	 		— 	 		— 	%		$0.55		$0.82	
Total general and administrative	146 	 		131 	 		(15)	 		(11)	%		$3.29		$4.09	
Commodity management	126 	 		156 	 		30 	 		19 	%					

Other—net	17 	 		5 	 		(12)	 		NM 	 					
Total costs and expenses	$	1,575 	 		$	1,259 	 		$	(316)	 		(25)	%					
Operating income	$	274 	 		$	29 	 		$	245 	 		NM 	 					
	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant variances in our costs and expenses are comprised of the following:
•$130 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $1.89 per Boe decrease in rate compared to September 30, 2018 primarily due to favorable technical revisions in the Williston Basin. The decrease in rate was also a result of the addition of new wells with lower relative cost per Boe.
•$94 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs.
•$67 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.
•$12 million increase in taxes other than income related to increased product revenues, previously discussed.
•$16 million increase in exploration expense relates to higher unproved leasehold amortization in 2019.
•$15 million increase in general and administrative expenses for the nine months ended September 30, 2019 compared to 2018. The nine months ended September 30, 2019 included $3 million for costs associated with a voluntary exit program we offered to employees. We expect additional expense during the fourth quarter of 2019. Our general and administrative expenses per Boe decreased to an average $3.29 for the nine months ended September 30, 2019 compared to $4.09 for the same period in 2018. Excluding the $3 million related to the voluntary exit program, our rate per Boe averaged $3.23 in 2019.
•$30 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 purchase volumes as discussed above.
•$12 million increase in other expense primarily due to expense associated with an offer made by us to settle certain contract disputes. (See Note 4 of Notes to Consolidated Financial Statements).

32

Results below operating income
																								
 	Nine months
ended September 30,		Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change	 	
 	2019		2018						
 	(Millions)		 		 	
Operating income	$	274 	 		$	29 	 		$	245 	 		NM 	 	
Interest expense	(119)	 		(123)	 		4 	 		3 	%	
Loss on extinguishment of debt	(47)	 		(71)	 		24 	 		34 	%	
Gains on equity method investment transactions	373 	 		— 	 		373 	 		NM 	 	
Investment income (loss) and other	7 	 		(2)	 		9 	 		NM 	 	
Income (loss) from continuing operations before income taxes	488 	 		(167)	 		655 	 		NM 	 	
Provision (benefit) for income taxes	109 	 		(56)	 		(165)	 		NM 	 	
Income (loss) from continuing operations	379 	 		(111)	 		490 	 		NM 	 	
Loss from discontinued operations	(1)	 		(92)	 		91 	 		99 	%	
Net income (loss)	$	378 	 		$	(203)	 		581 	 		NM 	 	

__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
The decrease in interest expense primarily relates to lower level of debt outstanding in 2019 compared to 2018.
In the third-quarter of 2019, we issued $600 million 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 third-quarter 2019. In the second-quarter of 2018, we used proceeds from the San Juan Gallup disposition and proceeds from the issuance of $500 million Senior Notes due in 2026 to retire $921 million aggregate principal amount of our Senior Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $71 million in second-quarter 2018. See Note 6 of Notes to Consolidated Financial Statements for detail of these transactions.
Gains on equity method investment transactions in 2019 related to the sales of our 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 4 of Notes to Consolidated Financial Statements for details of these sales.
For the nine months ended September 30, 2019, we had provision for income taxes compared to a benefit for income taxes for the same period for 2018. See Note 7 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for 2019 and 2018.
Loss from discontinued operations in 2018 included 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 2019 are cash on hand, expected cash flows from operations, anticipated proceeds from the sales of non-core assets, and, if necessary, borrowings on our credit facility. We anticipate that the combination of these sources should be sufficient to allow us to pursue our business strategy and goals through at least 2019. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities.
We note the following assumptions for 2019 capital expenditures:
•our planned capital expenditures for full-year 2019, excluding acquisitions, are estimated to be approximately $1.125 billion to $1.250 billion of which $1.075 billion to $1.150 billion relates to drilling and completions, including facilities. As of September 30, 2019, we have incurred $821 million of drilling and completion capital expenditures including facilities; and
33

•we have hedged a portion of our anticipated 2019 oil and gas production as disclosed in Commodity Price Risk Management following this section.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
•lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs;
•lower than anticipated proceeds from asset sales;
•significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold;
•reduced access to our credit facility pursuant to our financial covenants; and
•higher than expected development costs, including the impact of inflation.
Credit Facility
Our Credit Facility, as amended, includes total commitments of $1.5 billion on a $2.1 billion Borrowing Base with a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million (see Note 6 of Notes to Consolidated Financial Statements). Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. For additional information regarding the terms of our Credit Facility see Note 9 of Notes to Consolidated Financial Statements on our Annual Report on Form 10-K for the year ended December 31, 2018. As of September 30, 2019, WPX had no borrowings outstanding and $37 million of letters of credit issued under the Credit Facility and we were in compliance with our covenants under the credit agreement. Our unused borrowing availability was $1,463 million as of September 30, 2019. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended.

Commodity Price Risk Management
To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 12 of Notes to Consolidated Financial Statements). We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. The following table sets forth, as of the date of this filing, the derivative notional volumes of the net (long) short positions for the remainder of 2019 and 2020 that are economic hedges of our production volumes:

Crude Oil	Oct - Dec 2019		2020	
 	Volume
(Bbls/d)		Weighted Average
Price ($/Bbl)		Volume
(Bbls/d)		Weighted Average
Price ($/Bbl)	
Fixed Price Swaps—WTI	83,000 	 		$	56.72 	 		55,000 	 		$	57.03 	 	
	
Fixed Price Calls—WTI	5,000 	 		$	54.08 	 		— 	 		$	— 	 	
Fixed Price Costless Collars—WTI	8,000 	 		$50.00 - $60.19 	 		20,000 	 		$53.33 - $63.48 	 	
Basis swaps—Midland/Cushing	22,000 	 		$	(1.37)	 		7,486 	 		$	(1.31)	 	
Basis swaps—Nymex Calendar Monthly Avg Roll	13,261 	 		$	0.11 	 		— 	 		$	— 	 	
Basis swaps—Magellan East Houston	2,000 	 		$	4.63 	 					
Basis swaps—Magellan East Houston/Midland	9,000 	 		$	6.02 	 		— 	 		$	— 	 	
Basis swaps—Argus LLS/Midland	2,000 	 		$	8.60 	 		— 	 		$	— 	 	
Basis swaps—Magellan East Houston/Argus LLS	2,000 	 		$	0.75 	 		— 	 		$	— 	 	
Basis swaps—Clearbrook	8,000 	 		$	(3.23)	 		— 	 		$	— 	 	
Basis swaps—Brent/WTI Spread	— 	 		$	— 	 		5,000 	 		$	8.36 	 	

34

																								
Natural Gas	Oct - Dec 2019		2020	
 	Volume
(BBtu/d)		Weighted Average
Price ($/MMBtu)		Volume
(BBtu/d)		Weighted Average
Price ($/MMBtu)	
Fixed Price Swaps—Henry Hub	110 	 		$	3.07 	 		— 	 		$	— 	 	

	
	
Basis swaps—Permian	25 	 		$	(0.39)	 		— 	 		$	— 	 	
	
Basis swaps—Waha	22 	 		$	1.98 	 		60 	 		$	(0.79)	 	
Basis swaps—Houston Ship Channel	30 	 		$	(0.09)	 		— 	 		$	— 	 	

Sources (Uses) of Cash
												
 	Nine months
ended September 30,	
 	2019		2018	
 	(Millions)	
Net cash provided by (used in):				
Operating activities	$	906 	 		$	652 	 	
Investing activities	(507)	 		(403)	 	
Financing activities	(385)	 		(400)	 	
Net increase (decrease) in cash and cash equivalents and restricted cash	$	14 	 		$	(151)	 	
Operating activities
Net cash provided by operating activities increased for the nine months ended September 30, 2019 compared to the same period in 2018 primarily due to higher production volumes in 2019 and realizations on our derivatives, partially offset by higher operating costs and lower commodity prices. Net cash provided by operating activities for the nine months ended September 30, 2019 also includes the receipt of approximately $38 million related to an AMT credit refund which represents approximately half of our AMT credit carryforwards. Excluding changes in working capital, total cash provided by operating activities related to discontinued operations was approximately $44 million for the nine months ended September 30, 2018. In addition, cash outflows related to Powder River Basin gathering and transportation contracts retained by WPX were $22 million and $37 million for the nine months ended September 30, 2019 and 2018, respectively.
Investing activities
The table below includes cash and incurred capital expenditures for drilling and completions and capital expenditures excluding facilities for land acquisitions.

		Nine months
ended September 30,	
		2019		2018	
			
Cash capital expenditures for drilling and completions:					
Continuing operations		$	887 	 		$	905 	 	
Discontinued operations		— 	 		26 	 	
Total		$	887 	 		$	931 	 	
					
Capital expenditures incurred for drilling and completions:					
Continuing operations		$	828 	 		$	958 	 	
Discontinued operations		— 	 		23 	 	
Total		$	828 	 		$	981 	 	
					
Land acquisitions		$	107 	 		$	27 	 	
Net cash used in investing activities for the nine months ended September 30, 2019 includes the proceeds from the sale of certain non-core properties and 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 4 of Notes to Consolidated Financial Statements). Net cash used in investing activities for the nine months ended September 30, 2018 includes $645 million of net proceeds from the sale of San Juan Gallup (see Note 2 of Notes to Consolidated Financial Statements) and $72 million of additional investment in equity method investments.

35

Financing activities
Net cash used in financing activities for the nine months ended September 30, 2019 includes $594 million of payments for retirement of long-term debt, including approximately $44 million of premium, partially offset by $593 million net proceeds from a debt issuance in the third quarter of 2019 (see Note 6 of Notes to Consolidated Financial Statements). Net cash used in financing activities for the nine months ended September 30, 2019 also includes approximately $43 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 10 of Notes to Consolidated Financial Statements).
Net cash used in financing activities for the nine months ended September 30, 2019 and 2018 also includes payment for shares withheld for taxes of $16 million and $13 million, respectively.
Net cash used in financing activities for the nine months ended September 30, 2018 includes $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.
Contractual Obligations
See Note 8 of Notes to Consolidated Financial Statements for a discussion of additional transportation commitments.
Off-Balance Sheet Financing Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at September 30, 2019 or at December 31, 2018. Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a divestment.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is primarily related to our debt portfolio and has not materially changed during the first nine months of 2019.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of oil, natural gas and natural gas liquids as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our marketing trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Notes 11 and 12 of Notes to Consolidated Financial Statements.
An assumed increase in the 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 $159 million and $82 million at September 30, 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 $157 and $81 million at September 30, 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.
We have previously disclosed the value-at-risk; however, a sensitivity analysis is predominately the disclosure used by our peers. The value-at-risk information below is included for comparative purposes to our 2018 Form 10-K disclosures.
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 asset of $183 million and $141 million at September 30, 2019 and December 31, 2018, respectively.
The value at risk for derivative contracts held for nontrading purposes was $42 million at September 30, 2019 and $26 million at December 31, 2018. During the last 12 months, our value at risk for these contracts ranged from a high of $42 million to a low of $26 million. See Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2018 for additional discussion regarding our value at risk.

36

Item 4. Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (“Disclosure Controls”) or our internal control over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control over Financial Reporting
During the first nine months of 2019, we implemented a major portion of a new enterprise resource planning (“ERP”) accounting and reporting system in order to upgrade our technology and improve the timeliness and processing of our financial and operational information. The overall implementation will be ongoing throughout 2019 and will be substantially complete by December 31, 2019. Although the ERP functions as an integral part of our processes and system of internal controls, we concluded that, as of the end of the period covered in this report, there have been no changes that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

37

Part II. OTHER INFORMATION

Item 1. Legal Proceedings
See Note 8 of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

Item 1A. Risk Factors
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018, includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed as of September 30, 2019.

Item 2. 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 three months ended September 30, 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)	
July 1, 2019 to July 31, 2019:										
August 1, 2019 to August 31, 2019:								
Share repurchase program(a)	 		3,365,168 	 		$	10.18 	 		$	366 	 	
September 1, 2019 to September 30, 2019:										
Share repurchase program(a)		850,000 	 		$	10.41 	 		$	357 	 	
Total for the quarter		4,215,168 	 		$	10.23 	 		$	357 	 	

__________
(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 September 30, 2019 we have repurchased the shares reflected above at a total cost of $43 million. This stock repurchase program may be modified, suspended or terminated at any time by our Board of Directors.

Item 3. Defaults Upon Senior Securities
Not applicable.

Item 4. Mine Safety Disclosures
Not applicable.

Item 5. Other Information
Not applicable.

38

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 herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2016)	
			
2.3**		Purchase and Sale Agreement, dated as of January 12, 2017, by and among RKI Exploration & Production, LLC, Panther Energy Company II, LLC and CP2 Operating, LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 13, 2017)	
			
3.1	  	Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)	
			
3.2		Certificate of Amendment of Amended and Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)	
		
3.3	  	Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 21, 2014)	
			
3.4		Certificate of Designations for 6.25% Series A Mandatory Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)	
		
4.1	  	Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)	
		
4.2		Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)	
			
4.3		First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)	
			
4.4		Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)	
			
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)	
			
10.1	  	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)	
		
10.2	  	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)	
		
10.3	  	Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)	
			
10.4		WPX Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 29, 2013) (1)	
			
39

															
Exhibit No.	 	Description			
10.5		WPX Energy, Inc. Amended 2011 Employee Stock Purchase Plan (incorporated herein by reference to Appendix B to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A (File No. 001-35322) filed with the SEC on March 29, 2018) (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 Section 16 Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014) (1)			
				
10.11	 	WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)			
					
10.12		WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)			
					
10.13		Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)			
					
10.14		Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)			
					
10.15		Form of 2014 Time-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)			
					
10.16		Form of 2014 Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)			
					
10.17		Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)			
					
10.18		Form of Performance-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.6 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)			
					
10.19		Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)			
					
10.20		Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)			
					
40

															
Exhibit No.		Description			
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)			
					
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)			
					
41

															
Exhibit No.		Description			
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, 201)(1)			
					
31.1*	 	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002			
				
31.2*	 	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002			
				
32.1*	 	Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002			
				
101.INS*	 	XBRL Instance Document - 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 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	

															

42

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

				
	WPX Energy, Inc.
(Registrant)	
			
	By:	 	/s/ Stephen L. Faulkner	
		 	Stephen L. Faulkner
Controller
(Principal Accounting Officer)	
Date: October 31, 2019
43

Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
I, Richard E. Muncrief, certify that:
1.I have reviewed this quarterly report on Form 10-Q of WPX Energy, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2019

	
/s/ Richard E. Muncrief	
Richard E. Muncrief
Chief Executive Officer	

Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
I, J. Kevin Vann, certify that:
1.I have reviewed this quarterly report on Form 10-Q of WPX Energy, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: October 31, 2019

/s/ J. Kevin Vann	
J. Kevin Vann
Chief Financial Officer	

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of WPX Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	
/s/ Richard E. Muncrief	
Richard E. Muncrief
Chief Executive Officer	
October 31, 2019	

	
/s/ J. Kevin Vann	
J. Kevin Vann
Executive Vice President and Chief Financial Officer	
October 31, 2019	
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.