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

	
Form 8-K	
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): May 7, 2018

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

					
Delaware	 	1-35322	 	45-1836028	
(State or other jurisdiction
of incorporation)	 	(Commission
File Number)	 	(IRS Employer
Identification No.)	
 	 	 	 	 	
3500 One Williams Center,
Tulsa, Oklahoma	 	 	 	74172-0172	
(Address of principal executive offices)	 	 	 	(Zip Code)	
Registrant’s telephone number, including area code: (855) 979-2012
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

		
¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	

		
¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240-14a-12)	

		
¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	

		
¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	

	

TABLE OF CONTENTS

			
 	 	 	
Item 8.01. Other Events	 	 	
 	 	 	
Item 9.01. Financial Statements and Exhibits	 	 	
 	 	 	
SIGNATURE	 	 	
 	 	 	
INDEX TO EXHIBITS	 	 	
 	 	 	
EX-12	 	 	
 	 	 	
EX-23.1	 	 	
 	 	 	
EX-99.1	 	 	
EX-99.2	 	 	
EX-101 INSTANCE DOCUMENT	 	 	
EX-101 SCHEMA DOCUMENT	 	 	
EX-101 CALCULATION LINKBASE DOCUMENT	 	 	
EX-101 LABELS LINKBASE DOCUMENT	 	 	
EX-101 PRESENTATION LINKBASE DOCUMENT	 	 	
EX-101 DEFINITION LINKBASE DOCUMENT	 	 	
Item 8.01. Other Events
As noted in our Quarterly Report on Form 10-Q for the period ended March 31, 2018, we sold our properties in the San Juan Basin's Gallup oil play. In addition, we sold our natural gas-producing properties in the San Juan Basin in December 2017. As a result of these divestments, we no longer have operations in the San Juan Basin. In our Form 10-Q for the quarterly period ended March 31, 2018, we reported the results of operations and financial position of our San Juan Basin operations as discontinued operations.
In this filing, we have recast certain historical financial information originally included in our Annual Report on Form 10-K for the year ended December 31, 2017, to reflect the reclassification of our San Juan Basin operations as discontinued operations. In addition, we have recast the Consolidated Statements of Cash Flows for the retrospective adoption of Accounting Standards Update 2016-18.
The following Items of the Form 10-K have been recast for the items described above, to the extent applicable, and are filed or furnished as exhibits to this Current Report on Form 8-K:

•	Exhibit 12 Computation of Ratio of Earnings to Fixed Charges	

•	Exhibit 99.1	

◦	Item 6. Selected Financial Data	

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

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

◦	Item 8. Financial Statements and Supplementary Data	

•	Exhibit 99.2. Schedule II — Valuation and Qualifying Accounts for each of the three years ended December 31, 2017	

•	Exhibit 101.INS — XBRL Instance Document.	

•	Exhibit 101.SCH — XBRL Taxonomy Extension Schema.	

•	Exhibit 101.CAL — XBRL Taxonomy Extension Calculation Linkbase.	

•	Exhibit 101.DEF — XBRL Taxonomy Extension Definition Linkbase.	

•	Exhibit 101.LAB — XBRL Taxonomy Extension Label Linkbase.	

•	Exhibit 101.PRE — XBRL Taxonomy Extension Presentation Linkbase.	

The recast Items of the Form 10-K have been updated as described above. We have not otherwise updated for activities or events occurring after the date we filed our Form 10-K other than those disclosed in Note 3 and Note 17 of Notes to Consolidated Financial Statements. This Current Report on Form 8-K should be read in conjunction with our Quarterly Report on Form 10-Q for the period ended March 31, 2018.

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR
PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
Certain matters contained in this 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.	
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

•	availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of prices and the availability and cost of capital;	
		
•	inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);	
		
•	the strength and financial resources of our competitors;	
		
•	development of alternative energy sources;	
		
•	the impact of operational and development hazards;	
		
•	costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;	
		
•	changes in maintenance and construction costs;	
		
•	changes in the current geopolitical situation;	
		
•	our exposure to the credit risk of our customers;	
		
•	risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;	
		
•	risks associated with future weather conditions;	
		
•	acts of terrorism;	
		
•	other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; and	

		
•	additional risks described in our filings with the Securities and Exchange Commission (“SEC”).	
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth above. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. Forward-looking statements speak only as of the date they are made. We disclaim any obligation to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017.

Item 9.01. Financial Statements and Exhibits
(a) None
(b) None
(c) None
(d) Exhibits

			
 	 	 	
Exhibit
No.	 	Description	
 	 	 	
12 *	 	Computation of Ratio of Earnings to Fixed Charges	
 	 	 	
23.1 *	 	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP	
 	 	 	
99.1 *	 	Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Financial Statements and Supplementary Data (Part II, Items 6, 7, 7A, and 8 of our Annual Report on Form 10-K for the year ended December 31, 2017)	
 	 	 	
99.2 *	 	Schedule II — Valuation and Qualifying Accounts for each of the three years ended December 31, 2017	
 	 	 	
101.INS*	 	XBRL Instance Document	
 	 	 	
101.SCH*	 	XBRL Taxonomy Extension Schema	
 	 	 	
101.CAL*	 	XBRL Taxonomy Extension Calculation Linkbase	
 	 	 	
101.DEF*	 	XBRL Taxonomy Extension Definition Linkbase	
 	 	 	
101.LAB*	 	XBRL Taxonomy Extension Label Linkbase	
 	 	 	
101.PRE*	 	XBRL Taxonomy Extension Presentation Linkbase	

	
		
*	Filed herewith.	

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: May 7, 2018

INDEX TO EXHIBITS

			
Exhibit
No.	 	Description	
 	 	 	
12 *	 	Computation of Ratio of Earnings to Fixed Charges	
 	 	 	
23.1 *	 	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP	
 	 	 	
99.1 *	 	Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Financial Statements and Supplementary Data (Part II, Items 6, 7, 7A, and 8 of our Annual Report on Form 10-K for the year ended December 31, 2017)	
 	 	 	
99.2 *	 	Schedule II — Valuation and Qualifying Accounts for each of the three years ended December 31, 2017	
 	 	 	
101.INS*	 	XBRL Instance Document	
 	 	 	
101.SCH*	 	XBRL Taxonomy Extension Schema	
 	 	 	
101.CAL*	 	XBRL Taxonomy Extension Calculation Linkbase	
 	 	 	
101.DEF*	 	XBRL Taxonomy Extension Definition Linkbase	
 	 	 	
101.LAB*	 	XBRL Taxonomy Extension Label Linkbase	
 	 	 	
101.PRE*	 	XBRL Taxonomy Extension Presentation Linkbase	
__________

		
*	Filed herewith.	

Exhibit 12
WPX Energy, Inc.
Computation of Ratio of Earnings to Fixed Charges

	
																					
 	 	Years Ended December 31,	
 	 	2017	 	2016	 	2015	 	2014	 	2013	
 	 	(Millions)	
Earnings:	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations before income taxes	 	$	(104	)	 	$	(1,032	)	 	$	91		 	$	347		 	$	(1,575	)	
Less: Equity earnings, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees	 	1		 	1		 	1		 	1		 	1		
Income (loss) from continuing operations before income taxes and equity earnings	 	(103	)	 	(1,031	)	 	92		 	348		 	(1,574	)	
Add:	 	 	 	 	 	 	 	 	 	 	
Fixed charges:	 	 	 	 	 	 	 	 	 	 	
Interest accrued, including proportionate share from 50% owned investees and unconsolidated majority-owned investees (a)	 	188		 	207		 	187		 	123		 	108		
Capitalized Interest	 	(1	)	 	—		 	1		 	—		 	—		
Rental expense representative of interest factor	 	3		 	5		 	4		 	4		 	4		
Total fixed charges	 	190		 	212		 	192		 	127		 	112		
Distributed income of equity-method investees, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees	 	—		 	—		 	—		 	—		 	—		
Less:	 	 	 	 	 	 	 	 	 	 	
Capitalized interest	 	1		 	—		 	(1	)	 	—		 	—		
Total earnings as adjusted	 	$	88		 	$	(819	)	 	$	283		 	$	475		 	$	(1,462	)	
 	 	 	 	 	 	 	 	 	 	 	
Ratio of earnings to fixed charges	 	0.46		 	(b)		 	1.47		 	3.74		 	(d)		
Preferred stock dividend requirement	 	$	24		 	$	29		 	$	15		 	$	—		 	$	—		
Combined fixed charges and preferred dividends	 	$	214		 	$	241		 	$	207		 	$	127		 	$	112		
Ratio of earnings to combined fixed charges and preferred dividends	 	0.41		 	(c)		 	1.37		 	3.74		 	(d)		
 __________
		
(a)	Does not include interest related to income taxes, including interest related to liabilities for uncertain tax positions, which is included in provision (benefit) for income taxes in our Consolidated Statements of Operations.	
		
(b)	Earnings are inadequate to cover fixed charges by $1,031 million.	
		
(c)	Earnings are inadequate to cover combined fixed charges and preferred dividends by $1,060 million.	
		
(d)	Earnings are inadequate to cover fixed charges by $1,574 million.	

Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the following Registration Statements:
		
(1)	Registration Statement (Form S-3 No 333-208552) of WPX Energy, Inc.,	
		
(2)	Registration Statement (Form S-8 No 333-204355) pertaining to the WPX Energy, Inc. 2013 Incentive Plan, as amended effective May 21, 2015,	
		
(3)	Registration Statement (Form S-3 No 333-221301) of WPX Energy, Inc.,	
		
(4)	Registration Statement (Form S-3 No 333-197905) of WPX Energy, Inc.,	
		
(5)	Registration Statement (Form S-8 No 333-188767) pertaining to the WPX Energy, Inc. 2013 Incentive Plan, and	
		
(6)	Registration Statement (Form S-8 No 333-178388) and the related post-effective amendment No. 1 pertaining to the WPX Energy, Inc. 2011 Incentive Plan and the WPX Energy, Inc. 2011 Employee Stock Purchase Plan	
of our reports dated February 22, 2018, except for the effects of discontinued operations as discussed in Note 3 and Note 17, as to which the date is May 7, 2018, with respect to the consolidated financial statements and schedule of WPX Energy, Inc. and our report dated February 22, 2018, with respect to the effectiveness of internal control over financial reporting of WPX Energy, Inc., included in this Current Report on Form 8-K.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
May 7, 2018

Exhibit 99.1

		
Item 6.	Selected Financial Data	
                                
The following financial data at December 31, 2017 and 2016 , and for each of the three years ended December 31, 2017 , 2016 and 2015 should be read in conjunction with the other financial information included in this Exhibit 99.1 of this Form 8-K. All other financial data has been prepared from our accounting records.

																				
 	Years Ended December 31,	
 	2017	 	2016	 	2015	 	2014	 	2013	
Statement of operations data:	(Millions, except per share amounts)	
Product revenues	$	1,016		 	$	507		 	$	403		 	$	708		 	$	584		
Net gain (loss) on derivatives	$	3		 	$	(207	)	 	$	418		 	$	434		 	$	(124	)	
Commodity management revenue	$	25		 	$	177		 	$	286		 	$	1,110		 	$	882		
Total revenues	$	1,045		 	$	478		 	$	1,113		 	$	2,260		 	$	1,344		
 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations(a)	$	24		 	$	(672	)	 	$	40		 	$	219		 	$	(1,007	)	
Income (loss) from discontinued operations(b)	(40	)	 	71		 	(1,766	)	 	(48	)	 	(184	)	
Net income (loss)	$	(16	)	 	$	(601	)	 	$	(1,726	)	 	$	171		 	$	(1,191	)	
Less: Net income (loss) attributable to noncontrolling interests	—		 	—		 	1		 	7		 	(6	)	
Net income (loss) attributable to WPX Energy, Inc.	$	(16	)	 	$	(601	)	 	$	(1,727	)	 	$	164		 	$	(1,185	)	
Less: Dividends on preferred stock	15		 	18		 	9		 	—		 	—		
Less: Loss on induced conversion of preferred stock	—		 	22		 	—		 	—		 	—		
Net income (loss) available to WPX Energy, Inc. common stockholders	$	(31	)	 	$	(641	)	 	$	(1,736	)	 	$	164		 	$	(1,185	)	
Amounts available to WPX Energy, Inc. common stockholders:	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	$	9		 	$	(712	)	 	$	31		 	$	219		 	$	(995	)	
Income (loss) from discontinued operations	$	(40	)	 	$	71		 	$	(1,767	)	 	$	(55	)	 	$	(190	)	
Basic earnings (loss) per common share:	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	$	0.02		 	$	(2.28	)	 	$	0.13		 	$	1.08		 	$	(4.96	)	
Income (loss) from discontinued operations	$	(0.10	)	 	$	0.23		 	$	(7.55	)	 	$	(0.27	)	 	$	(0.95	)	
Diluted earnings (loss) per common share:	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	$	0.02		 	$	(2.28	)	 	$	0.13		 	$	1.06		 	$	(4.96	)	
Income (loss) from discontinued operations	$	(0.10	)	 	$	0.23		 	$	(7.50	)	 	$	(0.26	)	 	$	(0.95	)	

	
																				
 	As of December 31,	
 	2017	 	2016	 	2015	 	2014	 	2013	
Balance sheet data:	(Millions)	
Total assets	$	8,207		 	$	7,264		 	$	8,393		 	$	8,896		 	$	8,508		
Long-term debt	$	2,575		 	$	2,575		 	$	3,189		 	$	2,260		 	$	1,895		
Total stockholders’ equity	$	4,127		 	$	3,466		 	$	3,535		 	$	4,319		 	$	4,109		
Total equity, including noncontrolling
interests	$	4,127		 	$	3,466		 	$	3,535		 	$	4,428		 	$	4,210		
  __________

1

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

																				
 	Years Ended December 31,	
 	2017	 	2016	 	2015	 	2014	 	2013	
 	(Millions)	
Net (gain) loss on sales of assets, divestment of transportation contracts or impairment of producing properties	$	(161	)	 	$	239		 	$	(349	)	 	$	15		 	$	772		
Impairment of unproved leasehold property	$	—		 	$	—		 	$	—		 	$	41		 	$	317		

See Note 5 of Notes to Consolidated Financial Statements for further discussion of the impairments and asset sales in 2017 , 2016 and 2015 . In 2013, we recorded an impairment of $772 million of proved producing oil and gas properties in the Appalachian Basin and a $317 million impairment to estimated fair values of Appalachia leasehold.

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

																				
 	Years Ended December 31,	
 	2017	 	2016	 	2015	 	2014	 	2013	
 	(Millions)	
San Juan pre-tax impairment	$	60		 	$	—		 	$	—		 	$	—		 	$	—		
Net pre-tax gain on divestments	$	(10	)	 	$	(268	)	 	$	(26	)	 	$	—		 	$	—		
Piceance pre-tax impairments, including impairment of producing properties, costs of acquired unproved reserves and exploratory area well costs	$	—		 	$	—		 	$	2,334		 	$	72		 	$	88		
Powder River pre-tax impairments	$	—		 	$	—		 	$	16		 	$	45		 	$	192		
Powder River gain on sale of deep rights leasehold	$	—		 	$	—		 	$	—		 	$	—		 	$	(36	)	
Loss on sale of working interests in the Piceance Basin	$	—		 	$	—		 	$	—		 	$	196		 	$	—		

See Note 3 of Notes to Consolidated Financial Statements for further discussion of discontinued operations in 2017 , 2016 and 2015 .

2

	
		
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	
General and Basis of Presentation
We are an independent oil and natural gas exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting, developing and growing our oil positions in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Associated with our commodity production are sales and marketing activities, which include oil and natural gas purchased from working interest owners in operated wells and other area third-party producers and, to a lesser extent, the management of various natural gas related contracts such as transportation and storage. The revenues and expenses related to these sales and marketing activities are reported on a gross basis as part of commodity management revenues and costs and expenses.
On August 17, 2015, we completed the acquisition of privately-held RKI Exploration & Production, LLC (“RKI”) (the “RKI Acquisition”) expanding our operations into the Delaware Basin in New Mexico and Texas. We further expanded our operations in the Delaware Basin through the acquisition of certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”). See Note 2 of Notes to Consolidated Financial Statements for a further discussion regarding these acquisitions.
In December 2017, we sold our natural gas position in the San Juan Basin. In February 2018, we announced that we signed an agreement to sell our holdings in the San Juan Basin’s Gallup oil play for $700 million and the transaction closed on March 28, 2018. Subsequent to the closing of this transaction, we no longer have operations in the San Juan Basin. We previously had operations in the Piceance Basin in Colorado until April 8, 2016 and the Powder River Basin in Wyoming until September 1, 2015. For all periods presented, the results of the San Juan, Piceance and Powder River Basins are reported as discontinued operations. See Note 3 of Notes to Consolidated Financial Statements for further discussion of our discontinued operations. Unless indicated otherwise, the following discussion relates to continuing operations.
The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes in Item 8 also included in this Exhibit 99.1 of this Form 8-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 in our 2017 Annual Report on Form 10-K, particularly in “Risk Factors” and “Forward-Looking Statements.”
Overview
Composition of production (based on MBoe ) and product revenue

	
Years Ended December 31,	

3

The following table presents our production volumes and financial highlights for 2017 , 2016 and 2015 :

																					
 	Years Ended December 31,	 	 	
 	2017	 	2016	 	2015	
Production Sales Volume Data(a):	 	 	Per day	 	 	 	Per day	 	 	 	Per day	
Oil (Mbbls)	18,964		 	52.0		 	12,396		 	33.9		 	9,228		 	25.3		
Natural gas (MMcf)	35,311		 	97		 	27,115		 	74		 	19,094		 	52		
NGLs (Mbbls)	3,656		 	10.0		 	2,256		 	6.2		 	1,165		 	3.2		
Combined equivalent volumes (Mboe)	28,505		 	78.1		 	19,172		 	52.4		 	13,574		 	37.2		
Financial Data (millions):	 	 	 	 	 	 	 	 	 	 	 	
Total product revenues	$	1,016		 	 	 	$	507		 	 	 	$	403		 	 	
Total revenues	$	1,045		 	 	 	$	478		 	 	 	$	1,113		 	 	
Operating income (loss)	$	98		 	 	 	$	(826	)	 	 	 	$	345		 	 	
Capital expenditure activity(b)	$	(1,232	)	 	 	 	$	(584	)	 	 	 	$	(865	)	 	 	
  __________
		
(a)	Excludes production from our discontinued operations.	
		
(b)	Includes capital expenditures related to discontinued operations of $176 million, $113 million and $512 million for the years ended December 31, 2017, 2016 and 2015 respectively, and excludes capital expenditures related to acquisitions.	
Our 2017 operating results were $924 million favorable compared to 2016. The primary items impacting 2017 results compared to 2016 results include:
		
•	$509 million increase in product revenues, primarily oil sales, of which $239 million related to higher oil volumes and $189 million related to higher oil prices;	
		
•	$210 million favorable change in net gain (loss) on derivatives;	
		
•	$161 million net gain on sales of assets, including leasehold exchanges, for 2017 compared to $239 million net loss on primarily related to divestment of transportation contracts for 2016 (see Note 5 of Notes to Consolidated Financial Statements); and	
		
•	$36 million decrease in general and administrative expenses.	
Offset by:
		
•	$199 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and	
		
•	$61 million higher exploration costs (see Note 5 of Notes to Consolidated Financial Statements).	

Our 2016 operating results were $1,171 million unfavorable compared to 2015. The primary items impacting 2016 results compared to 2015 results include:
		
•	$625 million unfavorable change in net gain (loss) on derivatives from a gain of $418 million in 2015 to a loss of $207 million in 2016. Increases in forward prices during 2016 drove the 2016 loss;	
		
•	$56 million unfavorable change in net commodity management margin;	
		
•	$91 million higher depreciation expense; and	
		
•	the absence of $349 million of gain on sale of assets and divestment of transportation contracts and impairment of producing properties in 2015 compared to $239 million net loss for 2016 (see Note 5 of Notes to Consolidated Financial Statements).	
Offset by:
		
•	$104 million increase in product revenues;	
		
•	$41 million decrease in exploration expense;	
		
•	the absence in 2016 of a $22 million charge associated with a contract termination included in 2015 expenses;	
		
•	the absence in 2016 of a $23 million charge included in 2015 expenses associated with gathering obligations in an area of the Appalachian Basin where we plugged and abandoned our remaining wells in the fourth quarter of 2015 (see Note 5 of Notes to Consolidated Financial Statements); and	
		
•	the absence in 2016 of $23 million of acquisition costs included in 2015 expenses.	
Outlook
In 2017, we reached two major milestones for our company: oil production of 50,000 barrels per day and then 75,000 barrels per day inclusive of San Juan Gallup production. Also in 2017, we closed a transaction with Howard Energy Partners (“Howard”) to jointly develop midstream infrastructure in the Delaware Basin specifically focused on crude oil gathering and

4

natural gas processing; and we received $349 million in cash (see Note 6 of Notes to Consolidated Financial Statements). As previously noted, we sold our remaining interests in the San Juan Basin on March 28, 2018. The sale of our San Juan assets signals our confidence in the two remaining core positions in the Delaware (Permian) and Williston Basins . We believe we are well positioned for prudent growth assuming a near-term commodity environment of approximately $40 to $60 per barrel. Our growth plan through the end of 2018, both volumes and cash flow, is another important step in the transformation of the company in an effort to improve our leverage metrics along with other per Boe metrics. In addition, we plan to be cash-flow positive in 2019. However, the oil and gas industry is a challenging environment and appropriate adjustments would be made if we foresee market conditions change and that future commodity prices will remain at or outside the boundaries of the range mentioned above for an extended period of time.
Our capital budget for 2018 is $1,160 million to $1,310 million, including amounts for land, midstream and equity investments. Planned capital for drilling and completions is $1,040 million to $1,110 million. The plan contemplates deploying a comparable rig count compared to 2017, completing an inventory of 38 DUCs at year-end 2017, adding a third frac crew in the Delaware Basin and drilling longer laterals in the Delaware. The 2018 budget is designed to fund 7 rigs and 3 rigs in the Delaware and Williston Basins, respectively.
Our December 31, 2017 liquidity totaled approximately $1.3 billion, reflecting amounts available under the Credit Facility and cash on hand. Excluding any future borrowings on the Credit Facility, our next debt maturity of $350 million is not due until 2020. We believe our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a downturn. In April 2018, we amended certain terms of our Credit Facility including an increase in the Borrowing Base to $1.8 billion and an increase in commitments to $1.5 billion. Also in April 2018, we used proceeds from the sale of our San Juan Gallup properties to tender for $500 million of our long-term debt. See Note 17 of Notes to Consolidated Financial Statements for additional discussion of the Credit Facility amendment and the tender of our senior notes.    
As we execute on our long-term strategy, we continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:
		
•	continuing to grow our oil production and reserves through the development of our positions in the Delaware and Williston Basins;	
		
•	continuing to pursue cost improvements and efficiency gains;	
		
•	employing new technology and operating methods;	
		
•	continuing to invest in projects to assess resources and add new development opportunities to our portfolio;	
		
•	retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and	
		
•	continuing to maintain an active economic hedging program around our commodity price risks.	
Potential risks or obstacles that could impact the execution of our plan include:
		
•	lower than anticipated energy commodity prices;	
		
•	increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation;	
		
•	lower than expected results from acquisitions;	
		
•	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.	
With the exception of potential impairments, we continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are significantly volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel for a brief time over the past five years. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. If forecasted oil and natural gas prices were to decline, we would need to review the

5

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 $4.5 billion. In addition, the net book value associated with unproved leasehold is approximately $2.2 billion and is primarily associated with our Delaware Basin properties. See our discussion of impairment of long-lived assets in our Critical Accounting Estimates discussion later in this section.
Results of Operations
2017 vs. 2016
Revenue Analysis

															
 	Years ended December 31,	 	Favorable (Unfavorable) $ Change	 	Favorable (Unfavorable) % Change	
 	2017	 	2016	 				
 	(Millions)	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	
Oil sales	$	879		 	$	451		 	$	428		 	95	 %	
Natural gas sales	67		 	35		 	32		 	91	 %	
Natural gas liquid sales	70		 	21		 	49		 	NM		
Total product revenues	1,016		 	507		 	509		 	100	 %	
Net gain (loss) on derivatives	3		 	(207	)	 	210		 	NM		
Commodity management	25		 	177		 	(152	)	 	(86	)%	
Other	1		 	1		 	—		 	—	 %	
Total revenues	$	1,045		 	$	478		 	$	567		 	119	 %	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant variances in the respective line items of revenues are comprised of the following:
		
•	$428 million increase in oil sales reflects $239 million related to higher production sales volumes and $189 million related to higher sales prices for 2017 compared to 2016. The Delaware and Williston Basin volumes were 22.0 and 30.0 Mbbls per day, respectively, for 2017 compared to 13.0 and 20.8 Mbbls per day , respectively, for 2016. The following table reflects oil production prices and volumes for 2017 and 2016.	

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

6

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

								
 	Years ended December 31,	
 	2017	 	2016	
 	 	
Natural gas sales (per Mcf)	$	1.89		 	$	1.30		
Impact of net cash received related to settlement of derivatives (per Mcf)(a)	0.28		 	4.13		
Natural gas net price including all derivative settlements (per Mcf)	$	2.17		 	$	5.43		
 	 	 	 	
Natural gas production sales volumes (MMcf)	35,311		 	27,115		
Per day natural gas production sales volumes (MMcf/d)	97		 	74		
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
		
•	$49 million increase in natural gas liquids sales is due to $36 million related to higher NGL sales prices and $13 million related to higher production sales volumes for 2017 compared to 2016. The increase in our production sales volumes is due to our Delaware Basin. The following table reflects NGL production prices and volumes for 2017 and 2016.	

								
 	Years ended December 31,	
 	2017	 	2016	
 	 	
NGL sales (per barrel)	$	19.26		 	$	9.43		
 	 	 	 	
NGL production sales volumes (Mbbls)	3,656		 	2,256		
Per day NGL production sales volumes (Mbbls/d)	10.0		 	6.2		
		
•	$210 million favorable change in net gain (loss) on derivatives primarily reflects a favorable change from a loss of $207 million in 2016 to a gain of $3 million in 2017. Settlements from our derivatives totaled $4 million for 2017 and $302 million for 2016.	
		
•	$152 million decrease in commodity management revenues primarily due to lower natural gas sales volumes. Our volumes were higher in 2016 due in part to a short-term marketing agreement with the buyer of the Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. A similar decrease is reflected in the $181 million decrease in related commodity management costs and expenses, discussed below. Currently, we do not expect commodity management revenue or expenses to be significant in the future.	

7

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

																			
 	Years ended December 31,	 	Favorable (Unfavorable) $ Change	 	Favorable (Unfavorable) % Change	 	Per Boe Expense	
 	2017	 	2016	 				 	2017	 	2016	
 	(Millions)	 	 	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization	$	542		 	$	441		 	$	(101	)	 	(23	)%	 	$19.03	 	$23.01	
Lease and facility operating	168		 	118		 	(50	)	 	(42	)%	 	$5.90	 	$6.16	
Gathering, processing and transportation	24		 	12		 	(12	)	 	(100	)%	 	$0.83	 	$0.61	
Taxes other than income	79		 	43		 	(36	)	 	(84	)%	 	$2.78	 	$2.24	
Exploration	87		 	26		 	(61	)	 	NM		 	 	 	 	
General and administrative:	 	 	 	 	 	 	 	 	 	 	 	
General and administrative expenses	138		 	171		 	33		 	19	 %	 	$4.79	 	$8.94	
Equity based compensation	28		 	31		 	3		 	10	 %	 	$1.01	 	$1.60	
Total general and administrative	166		 	202		 	36		 	18	 %	 	$5.80	 	$10.54	
Commodity management, including charges for unutilized pipeline capacity	27		 	208		 	181		 	87	 %	 	 	 	 	
Net (gain) loss—sales of assets and divestment of transportation contracts (Note 5)	(161	)	 	239		 	400		 	NM		 	 	 	 	
Other—net	15		 	15		 	—		 	—	 %	 	 	 	 	
Total costs and expenses	$	947		 	$	1,304		 	$	357		 	27	 %	 	 	 	 	
Operating income (loss)	$	98		 	$	(826	)	 	$	924		 	NM		 	 	 	 	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant components on our costs and expenses are comprised of the following:
		
•	$101 million increase in depreciation, depletion and amortization is due to increased production volumes partially offset by a $3.98 per Boe decrease in rate which was impacted by both an increase in the reserves due to an increase in the 12-month average price and the addition of new wells with lower relative cost per Boe.	
		
•	$50 million increase in lease and facility operating expenses primarily related to increased production volumes.	
		
•	$12 million increase in gathering, processing and transportation primarily due to higher volumes in the Delaware Basin.	
		
•	$36 million increase in taxes other than income primarily relates to increased product revenues.	
		
•	$61 million increase in exploration expenses is primarily due to unproved leasehold property impairment, amortization and expiration in 2017 which includes costs associated with certain expired leases in the Permian Basin in excess of the accumulated amortization balance recorded during first-quarter 2017. These leases were renewed in second-quarter 2017. See Note 5 of Notes to Consolidated Financial Statements.	
		
•	$36 million decrease in general and administrative expenses primarily due to workforce reductions. In addition, 2016 included $15 million for severance and relocation costs associated with workforce reductions in third-quarter 2016 and office consolidations. We will continually challenge our levels of general and administrative costs; however, we believe our organizational size is conducive for future growth. Excluding the severance and relocation costs, total general and administrative expenses would have averaged $9.78 per Boe for 2016.	
		
•	$181 million decrease in commodity management expenses is primarily due to lower natural gas purchase volumes for 2017 compared to 2016. The higher volumes in 2016 were due in part to the marketing of the volumes for the purchaser of our Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. Also included in commodity management expenses for 2016 is $27 million for unutilized pipeline capacity related to divested transportation contracts.	
		
•	$161 net gain on sales of assets in 2017 primarily related to $103 million of gains on exchanges of leasehold acreage in the Delaware Basin and $48 million from recognition of deferred gains related to completion of commitments from a prior year disposition. The $239 million net loss on sales of assets and divestment of transportation contracts in 2016 relates to the divestment of transportation obligations. See Note 5 of Notes to Consolidated Financial Statements for further discussion of these items.	

8

Results below operating income (loss)

															
 	Years ended December 31,	 	Favorable (Unfavorable) $ Change	 	Favorable (Unfavorable) % Change	
 	2017	 	2016	 				
 	(Millions)	 	 	 	 	
Operating income (loss)	$	98		 	$	(826	)	 	$	924		 	NM		
Interest expense	(188	)	 	(207	)	 	19		 	9	 %	
Loss on extinguishment of debt	(17	)	 	(1	)	 	(16	)	 	NM		
Investment income and other	3		 	2		 	1		 	50	 %	
Loss from continuing operations before income taxes	(104	)	 	(1,032	)	 	928		 	90	 %	
Benefit for income taxes	(128	)	 	(360	)	 	(232	)	 	(64	)%	
Income (loss) from continuing operations	24		 	(672	)	 	696		 	NM		
Income (loss) from discontinued operations	(40	)	 	71		 	(111	)	 	NM		
Net loss	$	(16	)	 	$	(601	)	 	$	585		 	97	 %	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
The decrease in interest expense primarily relates to lower level of debt outstanding in 2017 compared to 2016.
In the third quarter of 2017, we issued $150 million of debt onto our 2024 Notes and extinguished $150 million of the 2020 Notes. As a result, we recorded a loss on extinguishment of debt of $17 million in 2017.
The benefit for income taxes for 2017 was less than the benefit in 2016 primarily due to lower pretax loss from continuing operations before income taxes in 2017 compared to 2016 offset by the $97 million impact to our net deferred tax liability of the enacted tax law change reducing the federal statutory rate from 35 percent to 21 percent. See Note  10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods. Our effective rate in future periods may be impacted by a valuation allowance on federal NOL carryovers (see Note 10 of Notes to Consolidated Financial Statements).
Loss from discontinued operations in 2017 primarily relates to a $60 million impairment of San Juan Legacy assets partially offset by operating results from the San Juan Basin. Other items in 2017 include accretion on the previously accrued liability for the contracts discussed below, partially offset by $10 million of severance tax refunds in the Piceance Basin related to prior years . Income from discontinued operations in 2016 primarily related to activity from the San Juan Basin including the gain on the sale of the San Juan gathering system as well as activity from the Piceance Basin which was sold early in the second quarter of 2016. In conjunction with our exit from the Powder River Basin in 2015, we recorded a liability in 2015 related to retained future commitments under gathering, processing and transportation contracts in the Powder River Basin. In 2017, we increased the remaining liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 3 of Notes to Consolidated Financial Statements.

9

2016 vs. 2015
Revenue Analysis

															
 	Years ended December 31,	 	Favorable (Unfavorable) $ Change	 	Favorable (Unfavorable) % Change	
 	2016	 	2015	 				
 	(Millions)	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	
Oil sales	$	451		 	$	367		 	$	84		 	23	 %	
Natural gas sales	35		 	29		 	6		 	21	 %	
Natural gas liquid sales	21		 	7		 	14		 	200	 %	
Total product revenues	507		 	403		 	104		 	26	 %	
Net gain (loss) on derivatives	(207	)	 	418		 	(625	)	 	NM		
Commodity management	177		 	286		 	(109	)	 	(38	)%	
Other	1		 	6		 	(5	)	 	(83	)%	
Total revenues	$	478		 	$	1,113		 	$	(635	)	 	(57	)%	
__________
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:
		
•	$84 million increase in oil sales reflects $127 million related to higher production sales volumes partially offset by a $43 million related to lower sales prices for 2016 compared to 2015. The increase in production sales volumes relates to our Delaware Basin which was acquired on August 17, 2015. The Delaware Basin volumes were 13.0 Mbbls per day for 2016 compared to 3.5 Mbbls per day for 2015. Delaware Basin volumes from the RKI acquisition date to December 31, 2015 averaged 9.2 Mbbls per day. The following table reflects oil production prices and volumes for 2016 and 2015.	

								
 	Years ended December 31,	
 	2016	 	2015	
 	 	
Oil sales (per barrel)	$	36.36		 	$	39.84		
Impact of net cash received (paid) related to settlement of
derivatives (per barrel)(a)	15.30		 	42.21		
Oil net price including all derivative settlements (per barrel)	$	51.66		 	$	82.05		
 	 	 	 	
Oil production sales volumes (Mbbls)	12,396		 	9,228		
Per day oil production sales volumes (Mbbls/d)	33.9		 	25.3		
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
		
•	$6 million increase in natural gas sales reflects $12 million related to higher production sales volumes offset by $6 million related to lower sales prices for 2016 compared to 2015. The increase in our production sales volumes is due to our Delaware Basin which was acquired on August 17, 2015. The following table reflects natural gas production prices and volumes for 2016 and 2015.	

								
 	Years ended December 31,	
 	2016	 	2015	
 	 	
Natural gas sales (per Mcf)	$	1.30		 	$	1.52		
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)	4.13		 	13.62		
Natural gas net price including all derivative settlements (per Mcf)	$	5.43		 	$	15.14		
 	 	 	 	
Natural gas production sales volumes (MMcf)	27,115		 	19,094		
Per day natural gas production sales volumes (MMcf/d)	74		 	52		
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

10

		
•	$14 million increase in natural gas liquids sales is due to $8 million related to higher NGL sales prices and $6 million related to higher production sales volumes for 2016 compared to 2015. The following table reflects NGL production prices and volumes for 2016 and 2015.	

								
 	Years ended December 31,	
 	2016	 	2015	
 	 	
NGL sales (per barrel)	$	9.43		 	$	5.59		
 	 	 	 	
NGL production sales volumes (Mbbls)	2,256		 	1,165		
Per day NGL production sales volumes (Mbbls/d)	6.2		 	3.2		
		
•	$625 million unfavorable change in net gain (loss) on derivatives primarily reflects an unfavorable change from a gain of $418 million in 2015 to a loss of $207 million in 2016. Settlements from our derivatives totaled $302 million for 2016 and net settlements were $617 million for 2015.	
		
•	$109 million decrease in commodity management revenues primarily due to lower average prices on physical natural gas sales as well as lower natural gas and crude sales volumes. The decrease in volumes primarily resulted from reduced activity following the sale of a package of marketing contracts in the second quarter of 2015 and release of certain related firm transportation capacity in the first and second quarters of 2015 (see Note 5 of Notes to Consolidated Financial Statements). The decrease in volumes was partially offset by the sale of production volumes pursuant to a short-term marketing agreement with the buyer of the Piceance Basin operations. This agreement ended June 30, 2016. The decrease in the sales price was greater than the decrease in the purchase price as reflected in the $53 million decrease in related commodity management costs and expenses, discussed below.	
Cost and operating expense and operating income (loss) analysis:

																							
 	Years ended December 31,	 	Favorable (Unfavorable) $ Change	 	Favorable (Unfavorable) % Change	 	Per Boe Expense	
 	2016	 	2015	 				 	2016	 	2015	
 	(Millions)	 	 	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization	$	441		 	$	350		 	$	(91	)	 	(26	)%	 	$	23.01		 	$	25.79		
Lease and facility operating	118		 	87		 	(31	)	 	(36	)%	 	$	6.16		 	$	6.38		
Gathering, processing and transportation	12		 	22		 	10		 	45	 %	 	$	0.61		 	$	1.63		
Taxes other than income	43		 	42		 	(1	)	 	(2	)%	 	$	2.24		 	$	3.07		
Exploration	26		 	67		 	41		 	61	 %	 	 	 	 	
General and administrative:	 	 	 	 	 	 	 	 	 	 	 	
General and administrative expenses	171		 	171		 	—		 	—	 %	 	$	8.94		 	$	12.70		
Equity based compensation	31		 	30		 	(1	)	 	(3	)%	 	$	1.60		 	$	2.16		
Total general and administrative	202		 	201		 	(1	)	 	—	 %	 	$	10.54		 	$	14.86		
Commodity management, including charges for unutilized pipeline capacity	208		 	261		 	53		 	20	 %	 	 	 	 	
Net (gain) loss—sales of assets and divestment of transportation contracts(Note 5)	239		 	(349	)	 	(588	)	 	NM		 	 	 	 	
Acquisition costs	—		 	23		 	23		 	100	 %	 	 	 	 	
Other—net	15		 	64		 	49		 	77	 %	 	 	 	 	
Total costs and expenses	$	1,304		 	$	768		 	$	(536	)	 	(70	)%	 	 	 	 	
Operating income (loss)	$	(826	)	 	$	345		 	$	(1,171	)	 	NM		 	 	 	 	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant components on our costs and expenses are comprised of the following:
		
•	$91 million increase in depreciation, depletion and amortization is primarily due to higher volumes in our Delaware Basin, which was acquired on August 17, 2015, partially offset by a lower rate per Boe and lower volumes in the Williston Basin in 2016.	

11

		
•	$31 million increase in lease and facility operating expenses primarily related to our Delaware Basin which was acquired on August 17, 2015 partially offset by reduced costs in the Williston Basin. Lease and facility operating expenses for 2016 and 2015 included $67 million and $25 million, respectively, from our Delaware Basin.	
		
•	$10 million decrease in gathering, processing and transportation expenses is primarily due to the sale of our Williston Basin gathering system.	
		
•	$41 million decrease in exploration expenses is primarily due to 2015 dry hole costs, impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration related to a non-core exploratory play where we no longer intend to continue exploration activities.	
		
•	General and administrative expenses for both 2016 and 2015 include $15 million for severance and relocation costs associated with workforce reductions and office consolidations. Excluding the severance and relocation costs in 2016 and 2015, general and administrative expenses would have averaged $9.78 per Boe for 2016 and $13.72 per Boe for 2015.	
		
•	$53 million decrease in commodity management expenses is primarily due to lower purchase volumes, as well as lower average prices on physical natural gas cost of sales for 2016 compared to 2015. The decrease in volumes primarily resulted from reduced activity following the sale of a package of marketing contracts in the second quarter of 2015 and release of certain related firm transportation capacity in the first and second quarters of 2015 (see Note 5 of Notes to Consolidated Financial Statements). The decrease in volumes is partially offset by the sale of production volumes pursuant to our purchase agreement with the buyer of the Piceance Basin operations. This agreement ended June 30, 2016. Also included in commodity management expenses are $27 million and $38 million, respectively, for 2016 and 2015 for unutilized pipeline capacity.	
		
•	$239 million net loss on sales of assets and divestment of transportation contracts in 2016 primarily relates to the divestment of transportation obligations. The $349 million net gain in 2015 primarily related to a $209 million gain on the sale of a package of marketing contracts and release of certain related firm transportation capacity in the second quarter of 2015, $70 million from the sale of a North Dakota gathering system in the fourth quarter of 2015 and a net gain of $69 million on the sale of a portion of our Appalachian Basin assets in the first quarter of 2015. (See Note 5 of Notes to Consolidated Financial Statements for further discussion of these sales).	
		
•	$23 million of acquisition costs in 2015 related to the acquisition of RKI (see Note 2 of Notes to Consolidated Financial Statements).	
		
•	$49 million decrease in other expenses primarily relates to a $22 million charge associated with a contract termination in the first quarter of 2015 and a $23 million charge associated with gathering obligations in an area of the Appalachian Basin where we plugged and abandoned our remaining wells in the fourth quarter of 2015 (see Note 5 of Notes to Consolidated Financial Statements).	
Results below operating income (loss)

															
 	Years ended December 31,	 	Favorable (Unfavorable) $ Change	 	Favorable (Unfavorable) % Change	
 	2016	 	2015	 				
 	(Millions)	 	 	 	 	
Operating income (loss)	$	(826	)	 	$	345		 	$	(1,171	)	 	NM		
Interest expense	(207	)	 	(187	)	 	(20	)	 	(11	)%	
Loss on extinguishment of debt	(1	)	 	(65	)	 	64		 	98	 %	
Investment income and other	2		 	(2	)	 	4		 	NM		
Income (loss) from continuing operations before income taxes	(1,032	)	 	91		 	(1,123	)	 	NM		
Provision (benefit) for income taxes	(360	)	 	51		 	411		 	NM		
Income (loss) from continuing operations	(672	)	 	40		 	(712	)	 	NM		
Income (loss) from discontinued operations	71		 	(1,766	)	 	1,837		 	NM		
Net loss	(601	)	 	(1,726	)	 	1,125		 	65	 %	
Less: Net income (loss) attributable to noncontrolling interests	—		 	1		 	1		 	100	 %	
Net loss attributable to WPX Energy, Inc.	$	(601	)	 	$	(1,727	)	 	$	1,126		 	65	 %	
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

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The increase in interest expense primarily relates to a full year of interest on the notes issued in the third quarter of 2015, partially offset by the absence in 2016 of $16 million of fees expensed in 2015 associated with acquisition bridge financing arrangements related to the RKI Acquisition.
The loss on extinguishment of debt in 2015 related to the satisfaction and discharge of RKI’s senior notes, including a make whole premium, at the time of the closing of the RKI Acquisition (see Note 2 of Notes to Consolidated Financial Statements).
The provision (benefit) for income taxes changed favorably due to a pretax loss from continuing operations before income taxes in 2016 compared to income for 2015. See Note  10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
The change in income (loss) from discontinued operations was primarily due to the Piceance Basin operations, which includes a $2.3 billion impairment in 2015, lower operating results in the San Juan Basin, the completion of the sale of Apco in first-quarter 2015, a $15 million loss on the sale of the Powder River Basin and $187 million of expense recorded upon the exit of the Powder River Basin related to obligations under pipeline capacity, gathering and treating agreements, partially offset by $13 million received from the settlement of the escrow from a previous sales contract for the Powder River Basin assets for 2015. Income from discontinued operations in 2016 includes a gain of $217 million on the sale of a San Juan Basin gathering system. See Note 3 of Notes to Consolidated Financial Statements.
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 2018 are cash on hand, expected cash flows from operations, anticipated proceeds from the sales of the remaining San Juan Basin properties and 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 2018. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities. In addition, we will further reduce debt and/or interest expense by seeking to retire, purchase or exchange our outstanding debt through cash purchases and/or exchanges for equity or debt securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
We note the following assumptions for 2018 capital expenditures:
		
•	our planned capital expenditures, excluding acquisitions, are estimated to be approximately $1,160 million to $1,310 million of which $1,040 million to $1,110 million relates to drilling and completions, including facilities; and	
		
•	we have hedged a portion of our anticipated 2018 and 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
On March 18, 2016, the Company entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility is a senior secured revolving credit facility with $1.2 billion in commitments and a maturity date of October 28, 2019. The Borrowing Base was increased to $1.5 billion in October 2017 and is in excess of commitments which remained at $1.2 billion. This Borrowing Base will remain in effect until the next Redetermination Date as set forth in the Credit Facility. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. For additional information regarding the terms of our Credit Facility see Note 9 of Notes to Consolidated Financial Statements. As of December 31, 2017 , WPX had no borrowings outstanding, had

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$70 million of letters of credit issued under the Credit Facility and was in compliance with our financial covenants under the credit agreement. Our unused borrowing availability was $1,130 million as of December 31, 2017 . See Note 17 of Notes to Consolidated Financial Statements for information on an amendment to the Credit Facility Agreement that the Company entered into during April 2018.
Commodity Price Risk Management
To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 16 of Notes to Consolidated Financial Statements). We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. We have the following contracts as of February 21, 2018 shown at weighted average volumes and basin-level weighted average prices:

	
								
Crude Oil	2018	 	2019	
 	Volume
(Bbls/d)	 	Weighted Average
Price ($/Bbl)	 	Volume
(Bbls/d)	 	Weighted Average
Price ($/Bbl)	
Fixed Price Swaps—WTI	56,979	 	$52.72	 	34,000	 	$52.30	
Fixed Price Calls—WTI	13,000	 	$58.89	 	5,000	 	$54.08	
Basis Swaps— Midland	14,496	 	$(0.86)	 	20,000	 	$(0.93)	
Basis Swaps— Nymex Calendar Monthly Avg Roll	20,000	 	$0.03	 	20,000	 	$0.11	

								
Natural Gas	2018	 	2019	
 	Volume
(BBtu/d)	 	Weighted Average
Price ($/MMBtu)	 	Volume
(BBtu/d)	 	Weighted Average
Price ($/MMBtu)	
Fixed Price Swaps—Henry Hub	132	 	$2.99	 	50	 	$2.88	
Fixed Price Calls—Henry Hub	16	 	$4.75	 	—	 	$—	
Basis Swaps—San Juan	23	 	$(0.01)	 	—	 	$—	
Basis Swaps—Permian	48	 	$(0.31)	 	25	 	$(0.39)	
Basis Swaps—Waha	15	 	$0.93	 	45	 	$0.07	
Basis Swaps—Houston Ship Channel	43	 	$(0.08)	 	30	 	$(0.09)	

								
Natural Gas Liquids	2018	 	2019	
 	Volume (Bbls/d)	 	Weighted Average Price ($/Gal)	 	Volume (Bbls/d)	 	Weighted Average Price ($/Gal)	
Fixed Price Swaps—Ethane-Mont Belvieu	3,078	 	$0.29	 	—	 	$—	
Fixed Price Swaps—Propane-Conway	900	 	$0.79	 	—	 	$—	
Fixed Price Swaps—Propane-Mont Belvieu	3,604	 	$0.80	 	—	 	$—	
Fixed Price Swaps—Iso Butane-Mont Belvieu	651	 	$0.91	 	—	 	$—	
Fixed Price Swaps—Normal Butane-Mont Belvieu	1,701	 	$0.90	 	—	 	$—	
Fixed Price Swaps—Natural Gasoline-Mont Belvieu	1,401	 	$1.31	 	—	 	$—	

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Credit Ratings
Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analysis when assigning credit ratings. While not a current factor related to our credit facility, a downgrade of our current rating could increase our future cost of borrowing, thereby negatively affecting our available liquidity. The ratings as of February 22, 2018 were as follows:

			
Standard and Poor’s	 	 	
Corporate Credit Rating	 	BB-	
Senior Unsecured Debt Rating	 	BB-	
Outlook	 	Stable	
Moody’s Investors Service	 	 	
LT Corporate Family Rating	 	B2	
Senior Unsecured Debt Rating	 	B3	
Outlook	 	Stable	
Subsequent to February 22, 2018, Moody’s Investors Service LT Corporate Family Rating was upgraded from B2 to Ba3.
 
Sources (Uses) of Cash

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Net cash provided (used) by:	 	 	 	 	 	
Operating activities	$	507		 	$	268		 	$	819		
Investing activities	(1,436	)	 	311		 	(1,317	)	
Financing activities	624		 	(120	)	 	465		
Increase (decrease) in cash and cash equivalents and restricted cash	$	(305	)	 	$	459		 	$	(33	)	
Operating activities
Net cash provided by operating activities increased in 2017 from 2016 primarily due to higher commodity prices and higher production volumes in 2017, partially offset by lower realizations on our derivatives and higher operating costs.
Our net cash provided by operating activities decreased in 2016 from 2015 primarily due to decreases of $315 million in net settlements received on derivatives and a decrease in cash provided by discontinued operations.
Excluding changes in working capital, total cash provided by operating activities related to discontinued operations was approximately $143 million , $102 million and $299 million for 2017 , 2016 and 2015 , respectively. Cash outflows related to previous accruals for Powder River Basin gathering and transportation contracts retained were $53 million, $53 million and $14 million for 2017, 2016 and 2015, respectively.

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

													
 	 	Years Ended December 31,	
 	 	2017	 	2016	 	2015	
 	 	(Millions)	
Cash capital expenditures for drilling and completions:	 	 	 	 	 	 	
Continuing operations	 	$	815		 	$	343		 	$	442		
Discontinued operations	 	166		 	117		 	522		
Total	 	$	981		 	$	460		 	$	964		
 	 	 	 	 	 	 	
Capital expenditures incurred for drilling and completions:	 	 	 	 	 	 	
Continuing operations	 	$	880		 	$	369		 	$	307		
Discontinued operations	 	168		 	103		 	426		
Total	 	$	1,048		 	$	472		 	$	733		
 	 	 	 	 	 	 	
Land acquisitions	 	$	63		 	$	84		 	$	16		
Significant components related to proceeds from the sale of our domestic assets and international interests are comprised of the following:
2017
		
•	$155 million related to the sale of our natural gas-producing properties in the San Juan Basin (see Note 3 of Notes to Consolidated Financial Statements). We anticipate receiving approximately $21 million upon post-closings.	
2016
		
•	$862 million for the sale of WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations to Terra Energy Partners, LLC (see Note 3 of Notes to Consolidated Financial Statements); and	
		
•	$280 million for the sale of our San Juan Basin gathering system during the first quarter of 2016 (see Note 3 of Notes to Consolidated Financial Statements).	
2015
		
•	$291 million after selling expenses but before $17 million of cash on hand at Apco as of the closing date, for the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol (see Note 3 of Notes to Consolidated Financial Statements);	
		
•	$271 million for the sale of a portion of our Appalachian Basin operations and release of certain firm transportation capacity to Southwestern Energy Company during the first quarter of 2015 (see Note 5 of Notes to Consolidated Financial Statements);	
		
•	$182 million for the sale of a North Dakota gathering system that closed during the fourth quarter of 2015 (see Note 5 of Notes to Consolidated Financial Statements); and	
		
•	$67 million for the sale of our Powder River Basin assets during fourth quarter of 2015 (see Note 3 of Notes to Consolidated Financial Statements).	
Cash provided by investing activities in 2016 was impacted by a $238 million divestment of certain transportation contracts (see Note 5 of Notes to Consolidated Financial Statements). Cash used by investing activities in 2015 includes $209 million for the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast during May 2015 (see Note 5 of Notes to Consolidated Financial Statements).
Net cash used in investing activities for the year ended December 31, 2017 includes $798 million related to the Panther Acquisition. During 2015, we successfully closed the purchase of RKI and paid approximately $1.2 billion in cash, net of cash acquired and net of certain distributions. See Note 2 of Notes to Consolidated Financial Statements.
Investing activities in 2017 includes net proceeds of $338 million from the formation of the joint venture with Howard (see Note 6 of Notes to Consolidated Financial Statements).

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Financing activities
The following are significant financing activities by year:
2017
		
•	In January 2017, we completed an equity offering of 51.675 million shares for net proceeds of approximately $670 million in conjunction with the Panther Acquisition;	
		
•	$15 million of preferred stock dividends; and	
		
•	$148 million of net proceeds related to the issuance of additional notes due 2024 partially offset by a payment of $165 million, including premium, to repurchase some of our 2020 Senior Notes.	
2016
		
•	In June 2016, we completed an equity offering of 56.925 million shares of our common stock for net proceeds of approximately $538 million;	
		
•	net repayments under the Credit Facility of $265 million;	
		
•	$355 million repayment of our Senior Notes due 2017;	
		
•	$18 million of preferred stock dividends; and	
		
•	$10 million of cash paid as an inducement for the conversion of a portion of outstanding preferred stock to common stock.	
2015
		
•	Equity offerings of (a) 30 million shares of our common stock for net proceeds of approximately $292 million and (b) $350 million of aggregate liquidation preference of 6.25% series A mandatory convertible preferred stock for net proceeds of approximately $339 million (see Note 14 of Notes to Consolidated Financial Statements);	
		
•	debt offerings of (a) $500 million aggregate principal amount of 7.500% senior unsecured notes due 2020 and (b) $500 million aggregate principal amount of 8.250% senior unsecured notes due 2023 (see Note 9 of Notes to Consolidated Financial Statements);	
		
•	payment of long term debt includes cash used to retire $600 million of outstanding debt on RKI’s revolving credit facility and $455 million for the satisfaction and discharge of RKI’s senior notes which includes a $55 million make-whole premium;	
		
•	net payments under the Credit Facility of $15 million. In August 2015, we utilized borrowings under the Credit Facility for the RKI Acquisition; and	
		
•	$40 million in payments for debt issuance costs and acquisition bridge financing fees for the debt offerings and revolver amendments.	
Off-Balance Sheet Financing Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at December 31, 2017 and December 31, 2016 .

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Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2017 .

																				
 	2018	 	2019 –
2020	 	2021 –
2022	 	Thereafter	 	Total	
 	(Millions)	
Long-term debt, including current portion:	 	 	 	 	 	 	 	 	 	
Principal	$	—		 	$	350		 	$	1,100		 	$	1,150		 	$	2,600		
Interest	168		 	335		 	250		 	109		 	862		
Operating leases and associated service commitments:	 	 	 	 	 	 	 	 	 	
Drilling rig commitments(a)	16		 	—		 	—		 	—		 	16		
Other	15		 	10		 	5		 	—		 	30		
Transportation commitments(b)	55		 	117		 	77		 	279		 	528		
Oil and gas activities(c)	137		 	213		 	173		 	223		 	746		
Financial derivatives(d)	191		 	84		 	—		 	—		 	275		
Other	11		 	10		 	2		 	1		 	24		
Total obligations	$	593		 	$	1,119		 	$	1,607		 	$	1,762		 	$	5,081		
  __________
		
(a)	Includes materials and services obligations associated with our drilling rig contracts.	
		
(b)	Includes firm demand obligations of $75 million of which $67 million is recorded as a liability as of December 31, 2017. A liability was recorded in 2015 in conjunction with our exit from the Powder River Basin (see Note 3 of Notes to Consolidated Financial Statements). Excludes additional commitments totaling $137 million associated with exercise of an option to acquire additional pipeline capacity in the Delaware Basin subsequent to year end.	
		
(c)	Includes gathering, processing and other oil and gas related services commitments of which $34 million is recorded as a liability as of December 31, 2017. Liabilities were recorded in 2015 in conjunction with our exit from the Powder River Basin and associated with an abandoned area in the Appalachian Basin. Approximately $317 million associated with our San Juan Basin operations will be assumed by the purchasers; however, WPX has left in place a performance guarantee with respect to these commitments (see Note 3 of Notes to Consolidated Financial Statements). Excluded are liabilities associated with asset retirement obligations totaling $39 million as of December 31, 2017. The ultimate settlement and timing of asset retirement obligations cannot be precisely determined in advance; however, we estimate that approximately 35 percent of this liability will be settled in the next five years.	
		
(d)	Obligations for financial derivatives are based on market information as of December 31, 2017 , and assume contracts remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur.	
Effects of Inflation
Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Operating costs are influenced by both competition for specialized services and specific price changes in oil, natural gas, NGLs and other commodities. We tend to experience inflationary pressure on the cost of services and equipment when higher oil and gas prices cause an increase in drilling activity in our areas of operation. Likewise, lower prices and reduced drilling activity may lower the costs of services and equipment.
Environmental
Our operations are subject to governmental laws and regulations relating to the protection of the environment, and increasingly strict laws, regulations and enforcement policies, as well as future additional environmental requirements, could materially increase our costs of operation, compliance and any remediation that may become necessary.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are as follows:

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Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities
We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated oil and natural gas reserves and estimated market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:
		
•	an increase (decrease) in estimated proved oil, natural gas and NGL reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and	
		
•	changes in oil, natural gas, and NGL reserves and estimated market prices both impact projected future cash flows from our properties. This, in turn, can impact our periodic impairment analyses.	
The process of estimating oil and natural gas reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, approximately 99 percent of our reserves estimates are audited by independent experts. The data may change substantially over time as a result of numerous factors, including the historical 12 month weighted average price, additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserves estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $47 million and $58 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserves categories.
Estimates of future commodity prices, which are utilized in our impairment analyses, consider market information including published forward oil and natural gas prices. The forecasted price information used in our impairment analyses is consistent with that generally used in evaluating our drilling decisions and acquisition plans. Prices for future periods impact the production economics underlying oil and gas reserve estimates. In addition, changes in the price of oil and natural gas also impact certain costs associated with our underlying production and future capital costs. The prices of oil and natural gas are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil and gas properties. See impairments of long-lived assets below.
We record the cost of leasehold acquisitions as incurred. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. Changes in our assumptions regarding the estimates of the nonproductive portion of these leasehold acquisitions could result in impairment of these costs. Upon determination that specific acreage will not be developed, the costs associated with that acreage would be impaired. Additionally, our leasehold costs are evaluated for impairment if the proved property costs in the basin are impaired. Our capitalized lease acquisition costs totaled $2.2 billion at December 31, 2017 and is primarily associated with our Delaware Basin acreage.
Impairments of Long-Lived Assets
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. When an indicator of impairment has occurred, we compare our estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine if an impairment has occurred. If an impairment has occurred, we determine the amount of impairment by estimating the fair value of the assets. Our computations utilize judgments and assumptions that include estimates of the undiscounted future cash flows, discounted future cash flows, estimated fair value of the asset, and the current and future economic environment in which the asset is operated.
We assess our proved properties for impairment using estimates of future undiscounted cash flows. Significant judgments and assumptions are inherent in these assessments and include estimates of reserves quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), drilling plans, expected capital and lease operating costs. The assessment performed as of December 31, 2017 did not identify any properties with a carrying value in excess of those estimated undiscounted cash flows. Therefore, no impairment charges were recorded in 2017 based on this assessment.
The assessments described above included approximately $4.5 billion of net book value associated with our proved properties. Many judgments and assumptions are inherent and to some extent interdependent of one another in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. As previously noted within “Successful

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Efforts Method of Accounting for Oil and Gas Exploration and Production Activities”, estimated natural gas and oil reserves and estimated market prices for oil and gas are a significant part of our impairment analysis. Commodity prices are significantly volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel for a brief time over the past five years. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. Approximately 58 percent of our future production considered in the impairment assessment is in years 2023 and beyond. If the estimated commodity revenues (only one of the many estimates involved) of the predominately oil proved properties reviewed but for which impairment charges were not recorded were lower by 20 to 30 percent, these properties could be at risk for impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant.
Valuation of Deferred Tax Assets and Liabilities
We record deferred taxes for the differences between the tax and book basis of our assets and liabilities as well as loss or credit carryovers to future years. Included in our deferred taxes are deferred tax assets primarily resulting from certain federal and state tax loss carryovers generated in the current and prior years, capital loss carryovers and alternative minimum tax credits. We must periodically evaluate whether it is more likely than not we will realize these deferred tax assets and establish a valuation allowance for those that do not meet the more likely than not threshold. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent, we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets.
As of December 31, 2017, our assessment of federal net operating loss carryovers was that no valuation allowance was required, however, a future pretax loss or limitations due to an ownership change may result in the need for a valuation allowance on our deferred tax assets.
The determination of our state deferred tax requires judgment as our effective state deferred tax rate can change periodically based on changes in our operations. Our effective state deferred tax rate is based upon our current entity structure and the jurisdictions in which we operate.
Purchase Accounting
We periodically acquire assets and assume liabilities in transactions accounted for as business combinations, such as the RKI and Panther acquisitions. In connection with a business combination, we must allocate the fair value of consideration given to the assets acquired and liabilities assumed based on estimated fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of the acquired assets and assumed liabilities. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed. In addition, estimates of fair value may not be completed as of the filing date and therefore, adjustments to the purchase price allocation would be finalized in future periods, not to exceed one year from the acquisition date. 
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we must make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties and gathering assets. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates and/or engage the assistance of valuation experts. Significant judgments and assumptions are inherent in these estimates and include estimates of reserves quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), drilling plans, expected capital and lease operating costs and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates.
 In many cases, estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryovers at the acquisition date, although such estimates may change in the future as additional information becomes known.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher depreciation, depletion and amortization expense, which results in lower net earnings or a higher net loss. A lower fair value assigned to property and related deferred taxes may result in the recording of goodwill. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses

20

and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income or increase in net loss for the period in which the impairment is recorded. See Note 2 of Notes to Consolidated Financial Statements for additional information regarding our purchase price allocations.
Fair Value Measurements
A small portion of our energy derivative assets and liabilities trade in markets with limited availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value for our energy derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities, we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2017 , the credit reserve is $4 million on our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.
At December 31, 2017 , 75 percent of the fair value of our derivatives portfolio expires in the next 12 months and more than 99 percent expires in the next 24 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.
The were no instruments included in Level 3 at December 31, 2017 .
For the year ended December 31, 2017, we recognized an impairment in discontinued operations on natural gas-producing properties held for sale in the San Juan Basin as a result of comparing our book value to the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected sales proceeds. In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. See Note 15 of Notes to Consolidated Financial Statements.
For the year ended December 31, 2015 , we recognized impairments of certain assets that were measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. See Note  15 of Notes to Consolidated Financial Statements.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including royalty litigation, environmental and other contingent matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note  11 of Notes to Consolidated Financial Statements.

21

	
		
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	
Interest Rate Risk
Our interest rate risk exposure is related primarily to our debt portfolio. Our senior notes are fixed rate debt in order to mitigate the impact of fluctuations in interest rates. For our fixed rate debt, $350 million matures in 2020, $1,100 million matures in 2022, $500 million matures in 2023 and $650 million matures in 2024. Interest rates for each group are 7.50 percent, 6.00 percent, 8.25 percent and 5.25 percent, respectively. The aggregate fair value of the senior notes is $2,746 million. Borrowings under our credit facility are based on a variable interest rate and could expose us to the risk of increasing interest rates. As of December 31, 2017 , we had no amounts outstanding under the Credit Facility Agreement. See Note 9 of Notes to Consolidated Financial Statements.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of oil, natural gas and NGLs, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our marketing trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Notes 15 and  16 of Notes to Consolidated Financial Statements.
We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
Trading
We currently have entered into no other derivative contracts for purposes other than economically hedging our commodity price-risk exposure.
Nontrading
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our energy commodity purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net liability of $177 million at both December 31, 2017 and December 31, 2016 .
The value at risk for derivative contracts held for nontrading purposes was $56 million at December 31, 2017 , and $47 million at December 31, 2016 . During the year ended December 31, 2017 , our value at risk for these contracts ranged from a high of $56 million to a low of $33 million. The increase in value at risk from December 31, 2016 primarily reflects additional positions entered into to economically hedge our equity production.

22

	
		
Item 8.	Financial Statements and Supplementary Data	
Below is Management’s Annual Report on Internal Control Over Financial Reporting as of February 22, 2018 as reported in our Annual Report on Form 10-K for the year ended December 31, 2017.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a—15(f) and 15d—15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 , based on the criteria set forth in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2017 , our internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Current Report on Form 8-K.

23

Report of Independent Registered Public Accounting Firm on
Internal Control over Financial Reporting
To the Shareholders and Board of Directors of WPX Energy, Inc.,
Opinion on Internal Control over Financial Reporting
We have audited WPX Energy, Inc.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, WPX Energy, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of WPX Energy, Inc. as of December 31, 2017 and 2016, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedule listed in the Index at Item 15.(a) and our report dated February 22, 2018, except for the effects of discontinued operations as discussed in Note 3 and Note 17, as to which the date is May 7, 2018, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 22, 2018

24

Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of WPX Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of WPX Energy, Inc. (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedule listed in the Index at Item 15.(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2010.
Tulsa, Oklahoma
February22, 2018, except for the effects of discontinued operations as discussed in Note 3 and Note 17, as to which the date is May 7, 2018.

25

WPX Energy, Inc.
Consolidated Balance Sheets  

								
 	December 31,	
 	2017	 	2016	
 	(Millions)	
Assets	 	 	 	
Current assets:	 	 	 	
Cash and cash equivalents	$	189		 	$	496		
Accounts receivable, net of allowance of $2 million as of December 31, 2017 and $3 million as of December 31, 2016	307		 	168		
Derivative assets	36		 	26		
Inventories	30		 	22		
Assets classified as held for sale	811		 	22		
Other	28		 	20		
Total current assets	1,401		 	754		
Investments	70		 	—		
Properties and equipment, net (successful efforts method of accounting)	6,691		 	5,443		
Derivative assets	23		 	12		
Assets classified as held for sale	—		 	1,031		
Other noncurrent assets	22		 	24		
Total assets	$	8,207		 	$	7,264		
 	 	 	 	
Liabilities and Equity	 	 	 	
Current liabilities:	 	 	 	
Accounts payable	$	446		 	$	222		
Accrued and other current liabilities	209		 	300		
Liabilities associated with assets held for sale	20		 	2		
Derivative liabilities	171		 	152		
Total current liabilities	846		 	676		
Deferred income taxes	117		 	251		
Long-term debt, net	2,575		 	2,575		
Derivative liabilities	65		 	63		
Asset retirement obligations	32		 	35		
Liabilities associated with assets held for sale	—		 	69		
Other noncurrent liabilities	445		 	129		
Contingent liabilities and commitments (Note 11)			 			
Equity:	 	 	 	
Stockholders’ equity:	 	 	 	
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares outstanding at December 31, 2017 and 2016)	232		 	232		
Common stock (2 billion shares authorized at $0.01 par value; 398.3 million and 344.7 million shares issued and outstanding at December 31, 2017 and 2016)	4		 	3		
Additional paid-in-capital	7,479		 	6,803		
Accumulated deficit	(3,588	)	 	(3,572	)	
Total equity	4,127		 	3,466		
Total liabilities and equity	$	8,207		 	$	7,264		
See accompanying notes.

26

WPX Energy, Inc.
Consolidated Statements of Operations

	
												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
Revenues:	(Millions, except per share amounts)	
Product revenues:	 	 	 	 	 	
Oil sales	879		 	451		 	367		
Natural gas sales	67		 	35		 	29		
Natural gas liquid sales	70		 	21		 	7		
Total product revenues	1,016		 	507		 	403		
Net gain (loss) on derivatives	3		 	(207	)	 	418		
Commodity management	25		 	177		 	286		
Other	1		 	1		 	6		
Total revenues	1,045		 	478		 	1,113		
Costs and expenses:	 	 	 	 	 	
Depreciation, depletion and amortization	542		 	441		 	350		
Lease and facility operating	168		 	118		 	87		
Gathering, processing and transportation	24		 	12		 	22		
Taxes other than income	79		 	43		 	42		
Exploration	87		 	26		 	67		
General and administrative (including equity-based compensation of $28 million, $31 million and $30 million for the respective periods)	166		 	202		 	201		
Commodity management, including charges for unutilized pipeline capacity	27		 	208		 	261		
Net (gain) loss on sales of assets and divestment of transportation contracts (Note 5)	(161	)	 	239		 	(349	)	
Acquisition costs (Note 2)	—		 	—		 	23		
Other—net	15		 	15		 	64		
Total costs and expenses	947		 	1,304		 	768		
Operating income (loss)	98		 	(826	)	 	345		
Interest expense	(188	)	 	(207	)	 	(187	)	
Loss on extinguishment of debt (Note 2) (Note 9)	(17	)	 	(1	)	 	(65	)	
Investment income and other	3		 	2		 	(2	)	
Income (loss) from continuing operations before income taxes	(104	)	 	(1,032	)	 	91		
Provision (benefit) for income taxes	(128	)	 	(360	)	 	51		
Income (loss) from continuing operations	24		 	(672	)	 	40		
Income (loss) from discontinued operations	(40	)	 	71		 	(1,766	)	
Net loss	(16	)	 	(601	)	 	(1,726	)	
Less: Net income attributable to noncontrolling interests	—		 	—		 	1		
Net loss attributable to WPX Energy, Inc.	$	(16	)	 	$	(601	)	 	$	(1,727	)	
Less: Dividends on preferred stock	15		 	18		 	9		
       Less: Loss on induced conversion of preferred stock	—		 	22		 	—		
Net loss available to WPX Energy, Inc. common stockholders	$	(31	)	 	$	(641	)	 	$	(1,736	)	
 	 	 	 	 	 	
(continued on next page)	

27

WPX Energy, Inc.
Consolidated Statements of Operations—(Continued)

	
												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions, except per share amounts)	
Amounts available to WPX Energy, Inc. common stockholders:	 	 	 	 	 	
Income (loss) from continuing operations	$	9		 	$	(712	)	 	$	31		
Income (loss) from discontinued operations	(40	)	 	71		 	(1,767	)	
Net loss	$	(31	)	 	$	(641	)	 	$	(1,736	)	
Basic earnings (loss) per common share:	 	 	 	 	 	
Income (loss) from continuing operations	$	0.02		 	$	(2.28	)	 	$	0.13		
Income (loss) from discontinued operations	(0.10	)	 	0.23		 	(7.55	)	
Net loss	$	(0.08	)	 	$	(2.05	)	 	$	(7.42	)	
Basic weighted-average shares	395.1		 	313.3		 	234.2		
Diluted earnings (loss) per common share:	 	 	 	 	 	
Income (loss) from continuing operations	$	0.02		 	$	(2.28	)	 	$	0.13		
Income (loss) from discontinued operations	(0.10	)	 	0.23		 	(7.50	)	
Net loss	$	(0.08	)	 	$	(2.05	)	 	$	(7.37	)	
Diluted weighted-average shares	397.4		 	313.3		 	235.6		
See accompanying notes.

28

WPX Energy, Inc.
Consolidated Statements of Changes in Equity

	
																																
 	 	 	WPX Energy, Inc., Stockholders	 	 	 	 	
 	Preferred
Stock	 	Common
Stock	 	Capital in
Excess of
Par Value	 	Accumulated
Deficit	 	Accumulated
Other
Comprehensive
Income (Loss)	 	Total
Stockholders’
Equity	 	Noncontrolling
Interests(a)	 	Total	
 	(Millions)	
Balance at December 31, 2014	$	—		 	$	2		 	$	5,562		 	$	(1,244	)	 	$	(1	)	 	$	4,319		 	$	109		 	$	4,428		
Net income (loss) attributable to WPX Energy, Inc.	—		 	—		 	—		 	(1,727	)	 	 	 	(1,727	)	 	1		 	(1,726	)	
Stock based compensation, net of tax impact	—		 	—		 	26		 	 	 	—		 	26		 	—		 	26		
Dividends on preferred stock	 	 	 	 	(11	)	 	 	 	 	 	(11	)	 	—		 	(11	)	
Issuance of common stock to public, net of offering costs	 	 	 	 	292		 	 	 	 	 	292		 	—		 	292		
Issuance of common stock related to an acquisition	 	 	1		 	295		 	 	 	 	 	296		 	—		 	296		
Issuance of preferred stock to public, net of offering costs	339		 	 	 	 	 	 	 	 	 	339		 	—		 	339		
Impact of divestitures	 	 	 	 	 	 	 	 	1		 	1		 	(110	)	 	(109	)	
Balance at December 31, 2015	339		 	3		 	6,164		 	(2,971	)	 	—		 	3,535		 	—		 	3,535		
Net loss attributable to WPX Energy, Inc.	 	 	 	 	 	 	(601	)	 	 	 	(601	)	 	 	 	(601	)	
Stock based compensation, net of tax impact	 	 	 	 	23		 	 	 	 	 	23		 	 	 	23		
Issuance of common stock to public, net of offering costs	 	 	 	 	538		 	 	 	 	 	538		 	 	 	538		
Conversion of preferred stock to common stock	(107	)	 	 	 	118		 	 	 	 	 	11		 	 	 	11		
Loss on induced conversion of preferred stock and related conversion costs	 	 	 	 	(22	)	 	 	 	 	 	(22	)	 	 	 	(22	)	
Dividends on preferred stock	 	 	 	 	(18	)	 	 	 	 	 	(18	)	 	 	 	(18	)	
Balance at December 31, 2016	232		 	3		 	6,803		 	(3,572	)	 	—		 	3,466		 	—		 	3,466		
Net loss attributable to WPX Energy, Inc.	 	 	 	 	 	 	(16	)	 	 	 	(16	)	 	 	 	(16	)	
Stock based compensation, net of tax impact	 	 	 	 	22		 	 	 	 	 	22		 	 	 	22		
Issuance of common stock to public, net of offering costs	 	 	1		 	669		 	 	 	 	 	670		 	 	 	670		
Dividends on preferred stock	 	 	 	 	(15	)	 	 	 	 	 	(15	)	 	 	 	(15	)	
Balance at December 31, 2017	$	232		 	$	4		 	$	7,479		 	$	(3,588	)	 	$	—		 	$	4,127		 	$	—		 	$	4,127		
  
__________
		
(a)	Primarily represented the 31 percent of Apco Oil and Gas International Inc. owned by others.	
See accompanying notes.

29

WPX Energy, Inc.
Consolidated Statements of Cash Flows

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
Operating Activities(a)	(Millions)	
Net loss	$	(16	)	 	$	(601	)	 	$	(1,726	)	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	 	 	 	 	 	
Depreciation, depletion and amortization	673		 	631		 	940		
Deferred income tax benefit	(134	)	 	(281	)	 	(1,005	)	
Provision for impairment of properties and equipment (including certain exploration expenses) and investments	158		 	38		 	2,426		
Net (gain) loss on derivatives in continuing operations	(3	)	 	207		 	(418	)	
Net settlements related to derivatives in continuing operations	4		 	302		 	617		
Net loss on derivatives included in discontinued operations	—		 	46		 	—		
Amortization of stock-based awards	32		 	36		 	35		
Loss on extinguishment of debt and acquisition bridge financing fees	17		 	1		 	81		
Net gains on sales of assets and divestment of transportation contracts	(170	)	 	(29	)	 	(385	)	
Cash provided (used) by operating assets and liabilities:	 	 	 	 	 	
Accounts receivable	(153	)	 	126		 	233		
Inventories	(8	)	 	10		 	(2	)	
Margin deposits and customer margin deposits payable	1		 	(1	)	 	26		
Other current assets	(8	)	 	5		 	—		
Accounts payable	158		 	(72	)	 	(247	)	
Federal income taxes receivable (payable)	12		 	(19	)	 	—		
Accrued and other current liabilities	(31	)	 	(45	)	 	87		
Payments on liabilities accrued in 2015 for retained transportation and gathering contracts related to discontinued operations	(53	)	 	(53	)	 	(14	)	
Other, including changes in other noncurrent assets and liabilities	28		 	(33	)	 	171		
Net cash provided by operating activities(a)	507		 	268		 	819		
Investing Activities(a)	 	 	 	 	 	
Capital expenditures(b)	(1,161	)	 	(578	)	 	(1,124	)	
Proceeds from sales of assets	193		 	1,127		 	810		
Proceeds (payments) related to divestment of transportation contracts	—		 	(238	)	 	209		
Purchases of a business, net of cash acquired	(799	)	 	—		 	(1,212	)	
Net proceeds from the joint venture formation	338		 	—		 	—		
Purchases of investments	(8	)	 	—		 	—		
Other	1		 	—		 	—		
Net cash provided by (used in) investing activities(a)	(1,436	)	 	311		 	(1,317	)	
Financing Activities	 	 	 	 	 	
Proceeds from common stock	672		 	540		 	295		
Proceeds from preferred stock	—		 	—		 	339		
Dividends paid on preferred stock	(15	)	 	(18	)	 	(6	)	
Payments related to induced conversion of preferred stock to common stock	—		 	(10	)	 	—		
Borrowings on credit facility	661		 	380		 	841		
Payments on credit facility	(661	)	 	(645	)	 	(856	)	
Proceeds from long-term debt, net of discount	148		 	—		 	1,000		
Payments for retirement of long-term debt, including premium	(165	)	 	(356	)	 	(1,100	)	
Taxes paid for shares withheld	(12	)	 	(6	)	 	(8	)	
Payments for debt issuance costs, credit facility amendment fees and acquisition bridge financing fees	(2	)	 	(5	)	 	(40	)	
Other	(2	)	 	—		 	—		
Net cash provided by (used in) financing activities	624		 	(120	)	 	465		
Net increase (decrease) in cash and cash equivalents and restricted cash	(305	)	 	459		 	(33	)	
Cash and cash equivalents and restricted cash at beginning of period	506		 	47		 	80		
Cash and cash equivalents and restricted cash at end of period	$	201		 	$	506		 	$	47		
__________	 	 	 	 	 	
(a) Amounts reflect continuing and discontinued operations unless otherwise noted.	
(b)   Increase to properties and equipment	$	(1,232	)	 	$	(584	)	 	$	(865	)	
Changes in related accounts payable and accounts receivable	71		 	6		 	(259	)	
Capital expenditures	$	(1,161	)	 	$	(578	)	 	$	(1,124	)	
See accompanying notes.

30

WPX Energy, Inc.
Notes to Consolidated Financial Statements
Note 1 . Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3 ).    
We had operations in the San Juan Basin which were sold in 2017 and 2018 that are reported in discontinued operations as discussed below. We also had other operations sold in 2015 and 2016 which are reported as discontinued operations, as discussed below.
The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.”
Basis of Presentation and Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated. The Company has no other elements of comprehensive income other than net income.
Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations
On January 30, 2018, we signed an agreement to sell our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC for $700 million (subject to post-closing adjustments). This sale closed in March 2018. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million a portion of which closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. The assets and liabilities have been reclassified as held for sale on the Consolidated Balance Sheets and the results of operations of the San Juan Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3 ).
Our discontinued operations also include the results of previously owned properties in the Piceance and Powder River Basins and our previously owned 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia.
See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 11 for a discussion of contingencies related to the former power business of The Williams Companies, Inc. (“Williams”) (most of which was disposed of in 2007).    
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

31

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Significant estimates and assumptions which impact these financials include:
		
•	impairment assessments of long-lived assets;	
		
•	valuation of deferred tax assets and liabilities;	
		
•	valuations of derivatives;	
		
•	estimation of oil and natural gas reserves;	
		
•	assessments of litigation-related contingencies; and	
		
•	asset retirement obligations.	
 
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash was approximately $12 million and $10 million as of December 31, 2017 and 2016 , respectively, and is included in other current assets on the Consolidated Balance Sheets.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories.

								
 	Years ended December 31,	
 	2017	 	2016	
 	(Millions)	
Material, supplies and other	$	29		 	$	20		
Crude oil production in transit	1		 	2		
 	$	30		 	$	22		

During the third quarter of 2016, we recorded a $3 million impairment charge of certain material and supplies inventory.
Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense on the Consolidated Statements of Operations. If the unproved properties are determined to be productive, the appropriate

32

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs as unproved properties.
From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is

33

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

				
 	Derivative Treatment	  	Accounting Method	
 	Normal purchases and normal sales exception	  	Accrual accounting	
 	Designated in a qualifying hedging relationship	  	Hedge accounting	
 	All other derivatives	  	Mark-to-market accounting	
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
Certain gains and losses on derivative instruments included on the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
		
•	unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;	
		
•	unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to commodity management and for which we have not elected the normal purchases and normal sales exception;	
		
•	realized gains and losses on all derivatives that settle financially;	
		
•	realized gains and losses on derivatives held for trading purposes; and	
		
•	realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.	
Realized gains and losses on derivatives that require physical delivery are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product and commodity management revenues
Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.
Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to

34

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.
Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Payment is typically due 30 to 45 days following delivery of product to our customers.
Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2017 and 2016 was insignificant .
Commodity management expenses
Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million and $38 million in 2016 and 2015 , respectively.
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.
Employee stock-based compensation
Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three -year period from the date of grant and generally expire ten years after the grant.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units and awards (see Note 4 ).
Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $32 million and $37 million as of December 31, 2017 and 2016 , respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9 ) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets.    
Recently Adopted Accounting Standards
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting, as part of the Simplification Initiative. The areas for simplification in ASU 2016-09 involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash

35

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

flows. ASU 2016-09 is required for annual periods beginning after December 15, 2016. Under ASU 2016-09, on a prospective basis, companies will no longer record excess tax benefits and deficiencies in additional paid in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit on the statement of operations. Other portions of the standard are adopted using either a prospective, retrospective, or modified retrospective approach depending on the topic covered in the standard. The Company adopted this guidance effective January 1, 2017 which impacted (a) our income tax provision in 2017 due to the tax deficiency recognized for tax and (b) the operating and financing activities sections of our Consolidated Statement of Cash Flows to reflect tax payments related to shares withheld for taxes. Cash outflows of $12 million , $6 million and $8 million for the years ended December 31, 2017 , 2016 and 2015 respectively, would have been included in operating activities under previous guidance, but are now reflected in financing activities. Previously reported periods have been reclassified to conform with our presentation for the current period.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash , which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. We adopted this standard January 1, 2018. After adoption the impact of this ASU must be applied retrospectively and we have reflected the impact in the Consolidated Statements of Cash Flows. Restricted cash was approximately $12 million and $10 million as of December 31, 2017 and December 31, 2016 , respectively.
Accounting Standards Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, and has updated it with additional ASUs. The core principle of the guidance in ASU 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09, as amended, is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The FASB permits companies to adopt the new standard early, but not before the original effective date of annual reporting periods beginning after December 15, 2016. ASU 2014-09 can be applied using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.
In 2016, we performed an initial assessment of the impact of ASU 2014-09 with the assistance of an outside consultant. Our assessment was based on a bottoms-up approach, in which we analyzed our existing contracts and current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our contracts. In 2017, we documented our conclusions around the impact of the standard to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management.
We do not expect the impact of adopting ASU 2014-09 to be material to our total net revenues and operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. We will adopt this standard on January 1, 2018 using the modified retrospective method. We have finalized our documentation and assessment of the impact of the standard on our financial results and related disclosures and have incorporated disclosure changes in this document; therefore, we anticipate minimal adjustments to our disclosures in future filings from the adoption of this standard.
In February 2016, the FASB issued ASU 2016-02, Leases , to increase transparency and comparability among organizations by recognizing right-of-use assets and lease payment liabilities on the balance sheet and disclosing key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make policy elections to not recognize lease assets and liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize right-of-use assets and lease payment liabilities related to drilling rig commitments, certain equipment leases, and potentially other arrangements, the effects of which cannot be estimated at this time. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018,

36

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

including interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. The Company continues to evaluate the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements or related disclosures.
In January 2017, FASB issued ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. The Company will adopt this standard on January 1, 2018 and we do not expect a significant impact on our consolidated financial statements from the adoption of the standard.
In February 2017, the FASB issued ASU 2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This ASU clarifies the scope and application of ASC 610-20 on the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The amendments are effective at the same time as the new revenue standard. For public entities, the amendments are effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted. The Company does not expect a significant impact on consolidated financial statements from the adoption of this standard.
In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718). The amendments in this Update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in this Update are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period. The Company will adopt this standard on January 1, 2018 and we do not expect a significant impact on our consolidated financial statements from the adoption of the standard.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect a significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
Note 2 . Acquisitions
2017
On January 12, 2017, we signed an agreement to acquire certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”) for $775 million , subject to post-closing adjustments. The transaction closed in March 2017 for $798 million including estimated closing adjustments. The assets, as of the closing date, included 25 producing wells ( 18 horizontals), three drilled but uncompleted horizontal laterals, approximately 18,000 net acres and more than 900 gross undeveloped locations in the Delaware Basin. We estimated that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved developed properties and facilities. This estimate is based on discounted cash flow models, which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. These assumptions represent Level 3 inputs. At the time of the acquisition closing, production was approximately 10,000 Boe per day. The impact of this acquisition to prior periods is not material to our results of operations for those periods.
2015
On August 17, 2015, we completed the acquisition of privately held RKI Exploration & Production, LLC (“RKI”). Per the terms of the merger agreement, the purchase price was $2.75 billion , consisting of 40 million unregistered shares of WPX common stock and approximately $2.28 billion in cash (the “RKI Acquisition”). The cash consideration was subject to closing adjustments and was reduced by our assumption of $400 million of aggregate principal amount of RKI’s senior notes and amounts outstanding under RKI’s revolving credit facility along with other working capital items. We incurred approximately $23 million of acquisition-related costs, primarily related to legal and advisory fees which are reflected on a separate line item on the Consolidated Statements of Operations. In addition, we incurred $16 million of acquisition bridge facility fees, included in interest expense, and a $65 million loss on extinguishment of RKI’s senior notes, reflected in loss on extinguishment of debt on the Consolidated Statements of Operations.

37

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

WPX funded the RKI Acquisition with proceeds from a combination of debt, preferred stock and common stock offerings along with available cash on hand and borrowings under its revolving credit facility.
The following table presents the unaudited pro forma financial results for the year ended December 31, 2015 as if the RKI Acquisition and related financings had been completed January 1, 2014. The year ended December 31, 2015 has been adjusted to exclude $23 million of acquisition costs, $65 million loss on extinguishment of acquired debt and $16 million of acquisition bridge facility fees. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the RKI Acquisition occurred on the date assumed or for the period presented, nor is such information indicative of the Company’s expected future results of operations.

					
 	 	Year Ended December 31,	
 	 	2015	
 	 	(Millions)	
Revenues	 	$	1,578		
Net income from continuing operations attributable to WPX Energy, Inc.	 	$	81		
The RKI Acquisition qualified as a business combination, and as a result, we estimated the fair value of the underlying shares distributed, the assets acquired and the liabilities assumed as of the August 17, 2015 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. We used a combination of market data, discounted cash flow models and replacement estimates in determining the fair value of the oil and gas properties and the related midstream assets, all of which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs. Deferred taxes must also be recorded for any differences between the assigned values and the carryover tax bases of assets and liabilities. Deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and carryovers at the acquisition date (see Note 10 ). The following table summarizes the consideration paid for the RKI Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. The final purchase price allocation is presented below.

38

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

	
					
 	 	 Purchase Price Allocation	
 	 	(Millions)	
Consideration:	 	 	
Cash, net of an estimated post-close settlement	 	$	1,251		
Fair value of WPX common stock issued	 	296		
Total consideration	 	$	1,547		
Fair value of liabilities assumed:	 	 	
Accounts payable	 	$	104		
Accrued liabilities	 	74		
Deferred income taxes	 	752		
Long-term debt	 	990		
Asset retirement obligation	 	23		
Total liabilities assumed as of the acquisition date	 	1,943		
Fair value of assets acquired:	 	 	
Cash and cash equivalents	 	51		
Accounts receivable, net	 	80		
Derivative assets, current	 	97		
Derivative assets, noncurrent	 	34		
Inventories	 	12		
Other current assets	 	3		
Properties and equipment(a)	 	3,209		
Other noncurrent assets	 	4		
Total assets acquired as of the acquisition date	 	3,490		
Net fair value of assets and liabilities	 	$	1,547		
__________
(a) Properties and equipment reflect the following as of the acquisition date:

					
Proved properties	 	$	881		
Unproved properties	 	2,168		
Gathering, processing and other facilities	 	157		
Other	 	3		
Total	 	$	3,209		
Note 3 . Discontinued Operations
On January 30, 2018, we signed an agreement to sell our operations in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC (“Enduring”) for $700 million (subject to closing and post-closing adjustments). The transaction closed on March 28, 2018 and we received approximately $667 million (subject to post-closing adjustments) in first quarter 2018. In addition, the purchaser will assume approximately $309 million of gathering and processing commitments at the time of closing; however, WPX has left in place a performance guarantee with respect to these commitments. We believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and Enduring and the declining size of the obligations subject to the guarantee over time. In conjunction with the closing, we recorded a $147 million loss in March 2018 which includes $9 million associated with the fair value of the performance guarantee. The operations in the San Juan Gallup represented 12 percent of our total proved reserves at December 31, 2017 and 16 percent of our total production for 2017. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million and recorded a gain of approximately $2 million . A portion of the San Juan Legacy sale closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin.
Significant transactions for the San Juan Basin Operations reflected in the tables below are as follows:

39

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

•	In the third quarter of 2017, we began a process to market our San Juan Legacy properties and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value at September 30, 2017 which resulted in an impairment of $60 million recorded in third-quarter 2017. At the close of the sale, we recorded a gain of $2 million .	
		
•	On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million . The consideration reflected $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX’s development in the Gallup oil play. We were obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and additional gains of $18 million in the subsequent quarters of 2016 as certain in-progress construction was completed. As of December 31, 2017, the remaining deferred gain was approximately $3 million .	
On February 8, 2016, we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations for $910 million . The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million , subject to post-closing adjustments, resulting in a gain of $52 million . We performed certain transition services for the buyer which concluded during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in commodity management revenue and expenses.
The Piceance Basin represented 52 percent of our total proved reserves at December 31, 2015.
Significant transactions for the Piceance Basin Operations reflected in the tables below are as follows:
		
•	$52 million gain recorded on the sale of the Piceance Basin in 2016.	
		
•	As a result of market conditions including oil and natural gas prices in the fourth quarter of 2015, we performed impairment assessments of our proved producing properties. As a result of these assessments, which included the possibility of cash flows from a divestiture of the Piceance Basin, we recorded a total of $2,334 million in impairment charges associated with the Piceance Basin, of which approximately $2,308 million is recorded in impairment of assets in the table below and $26 million is included in exploration expenses.	
In August 2015, we signed agreements for the sale of our Powder River Basin for $80 million . On September 1, 2015, we completed a portion of the Powder River Basin divestiture. The remaining portion of the divestiture, which relates to our equity method investment in Fort Union Gas Gathering, LLC, closed on October 30, 2015. We recorded a pre-tax loss of $15 million related to this transaction during 2015. During the first and second quarters of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices for the Powder River Basin. In addition, we retained certain firm gathering and treating obligations with total commitments of $104 million through 2020 related to the Powder River properties sold. These commitments had been in excess of our production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company with total commitments through 2021 totaling $150 million , which were related to the Powder River operation. With the closing of the Powder River Basin sale and exiting this basin in 2015, we recorded $187 million of expense related to these contracts, which is included as a separate line below. This expense was the estimated present value of the $254 million in payments associated with these contracts remaining as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from third parties and discounting based on our risk adjusted borrowing rate. Liabilities of $54 million and $133 million were recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of the closing date. In 2017, we increased the remaining liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues.
During the third quarter of 2014, we had signed an agreement to sell our Powder River Basin holdings. This sales agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. During third-quarter 2015, we received $13 million in escrow funds as a result of the terminated contract and this amount is included in Other-net expense below.
On January 29, 2015 we completed the divestiture of our international interests and received net proceeds of $291 million after expenses but before $17 million of international’s cash on hand as of the closing date. We recorded a pretax gain of $41 million related to this transaction during first quarter 2015.

40

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Summarized Results of Discontinued Operations
The following table presents the results of discontinued operations for the years presented.

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	 	 	
Total revenues(a)	$	291		 	$	279		 	$	845		
Costs and expenses:	 	 	 	 	 	
Depreciation, depletion and amortization	$	131		 	$	191		 	$	590		
Lease and facility operating	50		 	63		 	161		
Gathering, processing and transportation	70		 	113		 	299		
Taxes other than income	23		 	19		 	41		
Exploration	14		 	16		 	44		
General and administrative	8		 	21		 	54		
Commodity management	—		 	—		 	1		
Accrual for contract obligations retained	5		 	—		 	187		
Net (gain) loss—sales of assets and impairments	50		 	(217	)	 	2,324		
Accretion of liabilities related to contract obligations retained	6		 	2		 	2		
Other—net(b)	(3	)	 	7		 	(10	)	
Total costs and expenses(c)	354		 	215		 	3,693		
Operating income (loss)	(63	)	 	64		 	(2,848	)	
Investment income and other	—		 	—		 	6		
Gain (loss) on sales of domestic assets	—		 	51		 	(15	)	
Gain (loss) on sale of international assets	—		 	—		 	41		
Income (loss) from discontinued operations before income taxes	(63	)	 	115		 	(2,816	)	
Provision (benefit) for income taxes	(23	)	 	44		 	(1,050	)	
Income (loss) from discontinued operations(d)	$	(40	)	 	$	71		 	$	(1,766	)	
__________
(a) Includes $15 million related to international activity for 2015.
(b) Includes severance tax refund received in 2017.
(c) Includes $8 million related to international activity for 2015.
(d) Includes $52 million related to international activity for 2015.

41

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

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

								
 	December 31,	
 	2017	 	2016	
 	(Millions)	
Assets classified as held for sale	 	 	 	
Inventories	$	14		 	$	14		
Investments	—		 	3		
Properties and equipment, net (successful efforts method of accounting)	797		 	1,036		
Total assets classified as held for sale on the Consolidated Balance Sheets	$	811		 	$	1,053		
 	 	 	 	
Liabilities associated with assets held for sale	 	 	 	
Current liabilities:	 	 	 	
Accounts payable	$	1		 	$	—		
Accrued and other current liabilities	1		 	2		
Total current liabilities	2		 	2		
Asset retirement obligations	15		 	66		
Other noncurrent liabilities	3		 	3		
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	20		 	$	71		
Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $53 million , $53 million and $14 million for 2017 , 2016 and 2015 , respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	 	 	(Millions)	
Cash provided by operating activities(a)	$	143		 	$	102		 	$	299		
Capital expenditures within investing activities	$	(175	)	 	$	(135	)	 	$	(632	)	
__________
(a) Excluding income taxes and changes to working capital.

42

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Note 4 . Earnings (Loss) Per Common Share from Continuing Operations
 The following table summarizes the calculation of earnings per share.

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions, except per-share amounts)	
Income (loss) from continuing operations attributable to WPX Energy, Inc.	$	24		 	$	(672	)	 	40		
Less: Dividends on preferred stock	15		 	18		 	9		
       Less: Loss on induced conversion of preferred stock	—		 	22		 	—		
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic   and diluted income (loss) per common share	$	9		 	$	(712	)	 	$	31		
Basic weighted-average shares	395.1		 	313.3		 	234.2		
Effect of dilutive securities(a):	 	 	 	 	 	
Nonvested restricted stock units and awards	2.1		 	—		 	1.3		
Stock options	0.2		 	—		 	0.1		
Diluted weighted-average shares(a)	397.4		 	313.3		 	235.6		
Income (loss) per common share from continuing operations:	 	 	 	 	 	
Basic	$	0.02		 	$	(2.28	)	 	$	0.13		
Diluted	$	0.02		 	$	(2.28	)	 	$	0.13		
  __________
(a) The following table includes amounts that have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders. The common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per share as their inclusion would be antidilutive due to application of the if-converted method.

									
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Weighted-average nonvested restricted stock units and awards	—		 	2.2		 	—		
Weighted-average stock options	—		 	0.1		 	—		
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)	19.8		 	23.8		 	15.5		
The table below includes information related to stock options that were outstanding at December 31, 2017, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.

												
 	December 31,	
 	2017	 	2016	 	2015	
Options excluded (millions)	1.5		 	2.0		 	2.6		
Weighted-average exercise price of options excluded	$	17.80		 	$	17.42		 	$	16.16		
Exercise price range of options excluded	$14.41 - $21.81		 	$14.41 - $21.81		 	$11.46 - $21.81		
Fourth quarter weighted-average market price	$	12.10		 	$	13.23		 	$	7.43		

The diluted weighted-average shares excludes the effect of approximately 0.6 million and 3.0 million nonvested restricted stock units for 2017 and 2015, respectively. These restricted stock units were antidilutive under the treasury stock method.

43

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Note 5 . Asset Sales, Other Expenses and Exploration Expenses
Asset Sales
2017
Net gain on sales of assets for the year ended December 31, 2017 primarily reflect total gains of $103 million from exchanges of leasehold acreage in the Permian Basin, $48 million from the recognition of deferred gains related to the completion of commitments from the sale of a North Dakota gathering system in 2015 as discussed below, and $8 million recognized on the sales of certain Green River Basin and Appalachian Basin assets.
In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs.
2016
During July 2016, we completed the divestment of the remaining transportation contracts primarily related to our Piceance Basin operations which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment to Terra. The total remaining commitments related to these contracts for the remainder of 2016 and thereafter were approximately $400 million . As a result of the divestments and net payment of $238 million , we recorded a net loss of $238 million in third-quarter 2016.
2015
During the fourth quarter of 2015, we completed the sale of a North Dakota gathering system for approximately $185 million , subject to closing adjustments. Under the terms of the agreement, a subsidiary of the buyer, Midstream Capital Partners, will manage the overall system and we will operate, at the direction of the owner, the system for a two year initial term and any renewal terms. Under the terms of the agreement, we are required to complete certain future construction obligations. As a result of this transaction, we recorded a net gain of $70 million in fourth-quarter 2015. See Note 8 for liabilities accrued for future construction and deferred gain related to these obligations.
During May 2015, WPX completed the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast for approximately $209 million in cash. The transaction released us from various long-term natural gas purchase and sales obligations and approximately $390 million in future demand payment obligations associated with the transport position. As a result of this transaction, we recorded a net gain of $209 million in second-quarter 2015 on these executory contracts.
During the first quarter of 2015, we sold a portion of our Appalachian Basin operations and released certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $288 million , subject to post-closing adjustments. Including an estimate of post-closing adjustments of $17 million , we recorded a net gain of $69 million in first-quarter 2015. The assets were primarily located in the Appalachian Basin in Susquehanna County, Pennsylvania. The transaction also included the release of firm transportation capacity that we had under contract in the Northeast, primarily with Millennium Pipeline. Upon the transfer of the firm capacity, we were released from approximately $24 million per year in annual demand obligations associated with the transport.
Other Expenses
In December 2015, we plugged and abandoned the remaining wells serviced by a certain natural gas gathering system in the Appalachian Basin. As a result, we recorded approximately $23 million associated with the net present value of future obligations under the gathering agreement which is included in other—net on the Consolidated Statements of Operations.
During the first quarter of 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in other—net on the Consolidated Statements of Operations.

44

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Exploration Expenses
The following table presents a summary of exploration expenses.

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Unproved leasehold property impairments, amortization and expiration	$	84		 	$	22		 	$	36		
Geologic and geophysical costs	3		 	$	3		 	7		
Impairments of exploratory area well costs and dry hole costs	—		 	1		 	24		
Total exploration expenses	$	87		 	$	26		 	$	67		
Unproved leasehold property impairment, amortization and expiration for 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Permian Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.
Impairments of exploratory well costs and dry hole costs for 2015 include $24 million related to a non-core exploratory play where we no longer intend to continue exploration activities.
Unproved leasehold property impairments, amortization and expiration in 2015 include impairments of $26 million related to non-core exploratory areas where we no longer intend to continue exploration activities.
Note 6 . Investments
In June 2017, we signed an agreement with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the agreement, WPX and Howard each have a 50 percent voting interest in the newly formed joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity will serve as operator. In addition to a $300 million cash contribution, Howard is obligated to fund the first $263 million of joint venture capital expenditures. At closing in October 2017, WPX contributed subsidiaries holding crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $53 million . WPX also paid $11 million for advisory services and legal fees on the transaction. Howard contributed $439 million in cash at closing, $139 million of which applies to the $263 million carry obligation of Howard including $49 million for capital expenditures from January 1, 2017 to closing. Concurrently, WPX received a $300 million special distribution plus the $49 million for capital expenditures from Catalyst. We will account for our investment in Catalyst as an equity method investment. In connection with the joint venture, a consolidated subsidiary of WPX dedicated production from its current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to 20 year fixed-fee oil gathering and natural gas processing agreements with subsidiaries of Catalyst. The agreements do not include any minimum volume commitments. As of December 31, 2017, our investment in Catalyst is $64 million . We have deferred recognition of the $349 million and will recognize it over the 20 years based on production volumes as a deduction to gathering, processing and transportation expense. The $349 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.

45

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Note 7 . Properties and Equipment
Properties and equipment is carried at cost and consists of the following:

	
										
 	Estimated
Useful
Life(a)
(Years)	 	December 31,	
 			2017	 	2016	
 	 	 	(Millions)	
Proved properties	(b)	 	$	5,815		 	$	4,577		
Unproved properties	(c)	 	2,194		 	1,892		
Gathering, processing and other facilities	15-25	 	242		 	183		
Construction in progress	(c)	 	305		 	144		
Other	3-40	 	118		 	113		
Total properties and equipment, at cost	 	 	8,674		 	6,909		
Accumulated depreciation, depletion and amortization	 	 	(1,983	)	 	(1,466	)	
Properties and equipment—net	 	 	$	6,691		 	$	5,443		
__________
		
(a)	Estimated useful lives are presented as of December 31, 2017 .	
		
(b)	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note  1 ).	
		
(c)	Unproved properties and construction in progress are not yet subject to depreciation and depletion.	
Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.
Asset Retirement Obligations  
Our asset retirement obligations relate to producing wells, gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
A rollforward of our asset retirement obligations for the years ended 2017 and 2016 is presented below.

	
								
 	2017	 	2016	
 	(Millions)	
Balance, January 1	$	40		 	$	39		
Liabilities incurred	5		 	5		
Liabilities settled	(11	)	 	(6	)	
Estimate revisions	3		 	—		
Accretion expense(a)	2		 	2		
Balance, December 31	$	39		 	$	40		
Amount reflected as current	$	7		 	$	5		
__________
		
(a)	Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.	

46

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Note 8 . Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
The following table presents a summary of our accounts payable as of the dates indicated below.

								
 	December 31,	
 	2017	 	2016	
 	(Millions)	
Trade	$	120		 	$	64		
Accrual for capital expenditures	151		 	72		
Royalties	150		 	69		
Other	25		 	17		
 	$	446		 	$	222		
Accrued and other current liabilities
The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.

								
 	December 31,	
 	2017	 	2016	
 	(Millions)	
Taxes other than income taxes	$	14		 	$	15		
Accrued interest	69		 	72		
Compensation and benefit related accruals	39		 	51		
Gathering and transportation	11		 	14		
Gathering and transportation related to exited areas	53		 	57		
Deferred gain and future construction obligations related to sales of gathering systems	—		 	66		
Other, including other loss contingencies	23		 	25		
 	$	209		 	$	300		
Note 9 . Debt and Banking Arrangements
The following table presents a summary of our debt as of the dates indicated below.

								
 	December 31,	
 	2017 (a)	 	2016 (a)	
 	(Millions)	
Credit facility agreement	$	—		 	$	—		
7.500% Senior Notes due 2020	350		 	500		
6.000% Senior Notes due 2022	1,100		 	1,100		
8.250% Senior Notes due 2023	500		 	500		
5.250% Senior Notes due 2024	650		 	500		
Other	—		 	1		
Total debt	$	2,600		 	$	2,601		
Less: Current portion of long-term debt	—		 	—		
Total long-term debt	$	2,600		 	$	2,601		
Less: Debt issuance costs(b)	25		 	26		
Total long-term debt, net(b)	$	2,575		 	$	2,575		
__________
		
(a)	Interest paid on debt totaled $178 million , $194 million and $120 million for 2017 , 2016 and 2015 , respectively.	
		
(b)	Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.	

47

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Credit Facility
On March 18, 2016, the Company entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, is now a $1.2 billion senior secured revolving credit facility with a maturity date of October 28, 2019 . Based on our current credit ratings, a Collateral Trigger Period applies making the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2017 , WPX had no borrowings outstanding, had $70 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement.
Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. In October 2017, the Borrowing Base was increased to $1.5 billion and will remain in effect until the next Redetermination Date as set forth in the Credit Facility. At this time, the Credit Facility Agreement is limited by the total commitments on the Credit Facility which remained at $1.2 billion . The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.
Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.
The Collateral Trigger Termination Date is the first date following the date of the closing of the Credit Facility and the first date following any Collateral Trigger Date, as applicable, on which:
		
(1)	(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or	
		
(2)	both (i) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) is less than or equal to 3.00 to 1.00 and (ii) the Corporate Rating is (A) at least Ba1 by Moody’s and at least BB by S&P or (B) at least Ba2 by Moody’s and at least BB+ by S&P.	
Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings.
Significant Financial Covenants.
Currently, the Company is required to maintain:
		
•	ratio of Consolidated Secured Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 3.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and 3.00 to 1.00 thereafter; and	
		
•	a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.	
If a Collateral Trigger Termination Date occurs, other financial covenants would apply.
Covenants. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit,

48

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties.
Events of Default. The Credit Facility includes customary events of default, including events of default relating to:
		
•	non-payment of principal, interest or fees;	
		
•	inaccuracy of representations and warranties in any material respect when made or when deemed made;	
		
•	violation of covenants;	
		
•	cross payment-defaults;	
		
•	cross acceleration;	
		
•	bankruptcy and insolvency events;	
		
•	certain unsatisfied judgments;	
		
•	a change of control; and	
		
•	during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.	
If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2017. 

											
Senior Note	 	Face Value (Millions)	 	Maturity Date	 	Interest Payment Dates	 	Optional Redemption Period(a)	
7.500% Senior Notes due 2020 (the “2020 Notes”)	 	$	350		 	August 1, 2020	 	February 1, August 1	 	July 1, 2020	
6.000% Senior Notes due 2022 (the “2022 Notes”)	 	$	1,100		 	January 15, 2022	 	January 15, July 15	 	October 15, 2021	
8.250% Senior Notes due 2023 (the “2023 Notes”)	 	$	500		 	August 1, 2023	 	February 1, August 1	 	June 1, 2023	
5.250% Senior Notes due 2024 (the “2024 Notes”)	 	$	650		 	September 15, 2024	 	March 15, September 15	 	June 15, 2024	
  __________
		
(a)	At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.	
During third-quarter 2017, we issued an additional $150 million of our 5.25% senior notes due 2024. The proceeds were used to fund the tender offer of $150 million of our 7.50% senior notes due 2020.  As a result, we recorded a loss on extinguishment of debt of $17 million .
The terms of the indentures governing our 2020 Notes, 2022 Notes, 2023 Notes and 2024 Notes are substantially identical.
Change of Control.  If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.

49

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Covenants.  The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default.  Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:
(1) a default in the payment of interest on the notes when due that continues for 30 days ;
(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity,
upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in
clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days , or, in the case of the reporting
covenant under the indenture, which failure continues for a period of 90 days , after the date on which written notice of
such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within
such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be
automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using
commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
See Note 17 for a discussion of updates to our Credit Facility Agreement and senior notes subsequent to December 31, 2017.
Note 10 . Provision (Benefit) for Income Taxes
The following table includes the provision (benefit) for income taxes from continuing operations.

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Provision (benefit):	 	 	 	 	 	
Current:	 	 	 	 	 	
Federal	$	(18	)	 	$	(26	)	 	$	(4	)	
State	1		 	(7	)	 	8		
 	(17	)	 	(33	)	 	4		
Deferred:	 	 	 	 	 	
Federal	(100	)	 	(333	)	 	36		
State	(11	)	 	6		 	11		
 	(111	)	 	(327	)	 	47		
Total provision (benefit)	$	(128	)	 	$	(360	)	 	$	51		

50

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

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

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Provision (benefit) at statutory rate	$	(36	)	 	$	(361	)	 	$	32		
Increases (decreases) in taxes resulting from:	 	 	 	 	 	
State income taxes (net of federal benefit)	(12	)	 	(42	)	 	3		
Valuation allowance on current year state income taxes (net of federal benefit)	17		 	18		 	1		
Valuation allowance on state income taxes resulting from sale (net of federal benefit)	—		 	8		 	—		
Effective state income tax rate change (net of federal benefit)	(12	)	 	15		 	8		
Provisional impact of Tax Cuts and Jobs Act	(92	)	 	—		 	—		
Other	7		 	2		 	7		
Provision (benefit) for income taxes	$	(128	)	 	$	(360	)	 	$	51		
As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years. As a result of the sale of our Piceance Basin operations in Colorado in the second quarter of 2016, we recorded $8 million of valuation allowances against Colorado NOL and credit carryovers generated in prior years.
Significant changes to our operations during 2017 , 2016 and 2015 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we recorded an additional $12 million deferred tax benefit in 2017. We also accrued an additional $15 million and $8 million of deferred tax expense in 2016 and 2015, respectively.
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Act”). The income tax effects of changes in tax laws are recognized in the period when enacted. While the Company continues to assess the impact of the tax reform legislation on its business and consolidated financial statements, the legislation does reduce the U.S. corporate tax rate from the current rate of 35 percent to 21 percent effective January 1, 2018. This rate reduction results in a provisional estimate of a $97 million benefit offset by $5 million impact of equity based executive compensation to income tax expense in continuing operations and a corresponding reduction in the deferred tax liability. The Act provides for other significant tax law changes and modifications such as the repeal of the alternative minimum tax (“AMT”). Accordingly, AMT credits can be used to offset regular tax liability and/or can be refundable over tax years 2018-2021.
Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allows us to provide a provisional estimate of the impacts of the Act in our earnings for the year ending December 31, 2017. Our estimate does not reflect the impact of potential reductions of AMT credit refunds, changes in current interpretations of performance based executive compensation deduction limitations, effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform. The Company will continue to analyze the effects of the Act on its financial statements and operations. Additional impacts from the enactment of the Act will be recorded as they are identified during the one-year measurement period as provided for in SAB 118.

51

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

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

								
 	December 31,	
 	2017	 	2016	
 	(Millions)	
Deferred tax liabilities:	 	 	 	
Properties and equipment	$	792		 	$	1,295		
Derivatives, net	—		 	—		
Other, net	1		 	2		
Total deferred tax liabilities	793		 	1,297		
Deferred tax assets:	 	 	 	
Accrued liabilities and other	79		 	178		
Alternative minimum tax credits	78		 	104		
Loss carryovers	672		 	849		
Derivatives, net	42		 	66		
Total deferred tax assets	871		 	1,197		
Less: valuation allowance	195		 	151		
Total net deferred tax assets	676		 	1,046		
Net deferred tax liabilities	$	117		 	$	251		
As of December 31, 2017, the Company has not completed its accounting for the tax effects of enactment of the Act; however, the Company has made a reasonable estimate of the effects on its existing deferred tax balances.
Net cash payments (refunds) for income taxes were $(39) million , $21 million and $(8) million in 2017 , 2016 and 2015 , respectively.
The Company has federal NOL carryovers of approximately $2,132 million at December 31, 2017 , including a $353 million RKI NOL, that will not begin to expire until 2032 . In addition, we have $46 million of federal capital loss carryovers at December 31, 2017 , that will begin to expire in 2020 .
The Company has state NOL carryovers, including the RKI carryovers, of approximately $3.8 billion and $3.1 billion at 2017 and 2016 , respectively, of which more than 99 percent expire after 2029 .
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. As of December 31, 2017 , our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss may result in the need for a valuation allowance on our deferred tax assets.
The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three -year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of December 31, 2017 , we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for RKI effective with the RKI Acquisition. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the RKI Acquisition.
Pursuant to our tax sharing agreement with Williams, we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. The IRS has recently proposed an adjustment related to our business for which a payment

52

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

to Williams could be required. We are currently evaluating the issue and expect to protest 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 deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement.
The Company files a consolidated federal income tax return and several state income tax returns. The Company’s federal income tax returns for tax years 2014 through 2016 remain open for examination. The statute of limitations for most states expires one year after expiration of the IRS statute. During the year ended December 31, 2017, the IRS began an examination of the Company’s 2014 and 2015 federal income tax returns. In addition, the IRS began an examination of RKI’s 2014 and short-period 2015 federal income tax returns. These examinations remain in the preliminary stage and no additional taxes or refunds have been recorded at this time.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are less than $1 million for 2017. The impact of this accrual is included within Other in our reconciliation of the provision (benefit) at statutory rate to recorded provision (benefit) for income taxes.
As of December 31, 2017 , the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million . During the next 12 months , we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.
Note 11 . Contingent Liabilities and Commitments
Contingent Liabilities
Royalty litigation
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and oral argument before the Tenth Circuit was held on January 17, 2018. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico and violation of the New Mexico Oil and Gas Proceeds Payment Act, and seek declaratory judgment, accounting and injunctive relief. On August 16, 2016, the court denied plaintiffs’ motion for class certification. On September 15, 2016, plaintiffs filed their motion for reconsideration and filed a second motion for class certification, and on September 30, 2017, the Court issued its memorandum opinion and order denying the plaintiffs motion for reconsideration and their Second Motion for Class Certification. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to 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

53

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor.
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. The parties have filed numerous motions for summary judgment, reconsideration and remand, and there are currently two appeals before the Ninth Circuit. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreement pursuant to which we divested our Piceance Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. 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.
The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.
As of December 31, 2017 , we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a

54

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of December 31, 2017 and December 31, 2016 , the Company had accrued approximately $11 million and $13 million , respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our natural gas production and third-party purchases of natural gas to other locations in an attempt to obtain more favorable pricing differentials. During 2015 and 2016 we divested most of our contracted pipeline capacity in conjunction with our exits from the Piceance and Appalachian Basins. During 2017, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. Amounts below also include obligations totaling $317 million associated with our San Juan Basin operations that will be assumed by the purchaser, however, a performance guarantee will remain in place (see Note 3 ). As of December 31, 2017 , commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:

	
												
 	Midstream Services	 	Transportation	 	Total	
 	(Millions)	
2018	$	106		 	$	55		 	$	161		
2019	101		 	57		 	158		
2020	103		 	60		 	163		
2021	91		 	44		 	135		
2022	81		 	33		 	114		
Thereafter	219		 	279		 	498		
Total commitments	$	701		 	$	528		 	$	1,229		
 	 	 	 	 	 	
Accrued liabilities	$	34		 	$	67		 	$	101		
Our midstream service commitments will be settled over approximately eight years .

55

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Future minimum annual rentals under noncancelable operating leases as of December 31, 2017 , are payable as follows:

				
 	(Millions)	
2018	$	7		
2019	5		
2020	5		
2021	4		
2022	1		
Thereafter	—		
 	 	
Total	$	22		
Total rent expense, excluding amounts capitalized, was $19 million , $23 million and $20 million in 2017, 2016 and 2015, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
Note 12 . Employee Benefit Plans
WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $11 million , $13 million and $15 million for 2017 , 2016 and 2015 , respectively. Approximately $7 million , $7 million and $9 million were included in accrued and other current liabilities at December 31, 2017 , 2016 and 2015 , respectively, related to the non-matching annual employer contribution.
Note 13 . Stock-Based Compensation
We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units and awards for purposes of this footnote). At December 31, 2017, 14 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 6 million shares were available for future grants. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.
Total stock-based compensation expense was $28 million , $31 million and $30 million for of the years ended December 31, 2017 , 2016 and 2015 , respectively, and is reflected in general and administrative expense. Measured but unrecognized stock-based compensation expense related to restricted stock units and awards at December 31, 2017 was $36 million and is expected to be recognized over a weighted-average period of 1.8 years. There was no unrecognized stock-based compensation expense related to stock options at December 31, 2017 .
The ESPP allows employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. Offering periods are from January through June and from July through December. Employees purchased 122 thousand shares at an average price of $8.34 per share during 2017 .

56

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Nonvested Restricted Stock Units and Awards
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2017 .

							
Restricted Stock Units	Shares	 	Weighted-
Average
Fair Value(a)	
 	(Millions)	 	 	
Nonvested at December 31, 2016	6.5		 	$	11.92		
Granted	2.4		 	$	13.76		
Forfeited	(0.7	)	 	$	12.72		
Vested	(2.5	)	 	$	13.18		
Nonvested at December 31, 2017	5.7		 	$	12.06		
__________
		
(a)	Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.	
Other restricted stock unit information

												
 	2017	 	2016	 	2015	
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	13.76		 	$	10.99		 	$	10.24		
Total fair value of restricted stock units vested during the year (millions)	$	33		 	$	37		 	$	40		
Performance-based shares granted represent 31 percent of nonvested restricted stock units outstanding at December 31, 2017 . These grants may be earned at the end of a three -year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2017 .

													
Stock Options	Options	 	Weighted-
Average
Exercise
Price	 	Weighted-Average Remaining Contractual Life	 	Aggregate
Intrinsic
Value	
 	(Millions)	 	 	 	(Years)	 	(Millions)	
Outstanding at December 31, 2016	2.7		 	$	15.31		 	 	 	$	4		
Granted	—		 	$	—		 	 	 	 	
Exercised	(0.1	)	 	$	8.06		 	 	 	 	
Forfeited	(0.4	)	 	$	15.96		 	 	 	 	
Outstanding at December 31, 2017	2.2		 	$	15.35		 	2.2	 	$	3		
Exercisable at December 31, 2017	2.2		 	$	15.35		 	2.2	 	$	3		

The total intrinsic value of options exercised was $224 thousand , $160 thousand and $319 thousand for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Cash received from stock option exercises was $0.4 million , $0.4 million and $2 million during 2017 , 2016 and 2015 , respectively.
The Company did not grant stock options during the years ended 2017, 2016 and 2015.

57

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Note 14 . Stockholders’ Equity
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding. As of December 31, 2017 , there were 4.8 million shares of our 6.25% series A Mandatory Convertible Preferred Stock (“Preferred Stock”) issued and outstanding (as described below).
Series A Mandatory Convertible Preferred Stock
On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our Preferred Stock at $50 per share, for gross proceeds of approximately $350 million , before underwriting discounts and commissions.
Dividends on our Preferred Stock will be payable on a cumulative basis when, as and if declared by our Board of Directors, or an authorized committee of our Board of Directors, at an annual rate of 6.25% of the liquidation preference of $50 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018.
Each share of our Preferred Stock has a liquidation preference of $50 and, unless converted or redeemed earlier, each share of our Preferred Stock will automatically convert on July 31, 2018 into between 4.1254 and 4.9504 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the average volume weighted average price per share of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding July 31, 2018, which we refer to as the “final averaging period.” At any time prior to July 31, 2018, a holder may convert one share of our Preferred Stock into a number of shares of our common stock equal to the minimum conversion rate of 4.1254 , subject to anti-dilution adjustments.
On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our Preferred Stock, pursuant to which each of the Preferred Holders agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders agreed to convert an aggregate of approximately 2.2 million shares of Preferred Stock into approximately 10.2 million shares of our common stock in the Conversion, and we made an aggregate cash payment to the Preferred Holders of approximately $10 million . Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million in 2016.
By entering into the Conversion and associated transactions early, we reduced cash dividend payments and continued simplifying our capital and cost structure.
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2017 , 2016 or 2015 . No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Subject to certain exceptions, so long as any share of our Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Preferred Stock.

58

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

On July 22, 2015, we completed an equity offering of 30 million shares of our common stock for gross proceeds of approximately $292 million , net of underwriter discounts and commissions, at the public offering price of $10.10 per share.
On August 17, 2015, we issued 40 million unregistered shares of our common stock to RKI shareholders as part of the consideration under our merger agreement. The estimated fair value of the shares on the RKI Acquisition date was $296 million . These shares were registered in December 2015. See Note 2 for further discussion of the RKI Acquisition.
On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
On January 12, 2017, we completed an underwritten public offering of 51.675 million shares of our common stock, which included 6.675 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $12.97 per share and we received proceeds of approximately $670 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. We used these proceeds, and cash on hand, to close the Panther Acquisition.
Note 15 . Fair Value Measurements
Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
		
•	Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.	
		
•	Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars, calls or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.	
		
•	Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.	
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash and margin deposits approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

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WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

	
																																
 	December 31, 2017	 	December 31, 2016	
 	Level 1	 	Level 2	 	Level 3	 	Total	 	Level 1	 	Level 2	 	Level 3	 	Total	
 	(Millions)	 	(Millions)	
Energy derivative assets	$	—		 	$	59		 	$	—		 	$	59		 	$	—		 	$	38		 	$	—		 	$	38		
Energy derivative liabilities	$	—		 	$	236		 	$	—		 	$	236		 	$	—		 	$	215		 	$	—		 	$	215		
Total debt(a)	$	—		 	$	2,746		 	$	—		 	$	2,746		 	$	—		 	$	2,702		 	$	—		 	$	2,702		
__________
		
(a)	The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,600 million as of December 31, 2017 and 2016 .	
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, calls or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil and natural gas swaps entered into, we granted swaptions and calls to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio extends through the end of 2020. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. There were no instruments included in Level 3 at December 31, 2017.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2017 or 2016.
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues on our Consolidated Statements of Operations.
Other

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WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

In addition to the items discussed below, we performed other nonrecurring fair value assessments as discussed in Note 2.
2017
In conjunction with the $103 million of gains from exchanges of leasehold during 2017, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs. The total fair value of leasehold exchanges in 2017 approximated $200 million . See Note 5 for additional discussion related to leasehold exchanges.
In addition, during the third quarter of 2017, we began a process to market our natural gas-producing properties in the San Juan Basin and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value which resulted in an impairment of $60 million recorded in the third-quarter of 2017. See Note 3 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin reported as discontinued operations.
2015
As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas, oil and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In the year ended December 31, 2015 , our assessment identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

							
 	Total losses for the year ended December 31,	
 	 	 	2015 (a)	 	
 	 	 	
Impairments:	 	 	 	 	
Producing properties and costs of acquired unproved reserves (Note 3 and Note 5)	 	 	$	2,308		 	
Unproved leasehold	 	 	26		 	
 	 	 	$	2,334		 	
__________
		
(a)	As a result of our impairment assessment in 2015, we recorded the following significant impairment charges that are reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately $880 million :	
		
•	$2,308 million impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment.	
		
•	$26 million impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment.	
Note 16 . Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to

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WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

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

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WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2017 .

														
Commodity	 	Period	 	Contract Type (a)	 	Location	 	Notional Volume (b)	 	Weighted Average
Price (c)	
Crude Oil	 	 	 	 	 	 	 	 	 	 	
Crude Oil	 	2018	 	Fixed Price Swaps	 	WTI	 	(57,500)	 	$	52.82		
Crude Oil	 	2018	 	Basis Swaps	 	Midland	 	(17,521)	 	$	(0.91	)	
Crude Oil	 	2018	 	Basis Swaps	 	Nymex	 	(20,000)	 	$	0.03		
Crude Oil	 	2018	 	Fixed Price Calls	 	WTI	 	(13,000)	 	$	58.89		
Crude Oil	 	2019	 	Fixed Price Swaps	 	WTI	 	(32,000)	 	$	51.99		
Crude Oil	 	2019	 	Basis Swaps	 	Midland	 	(20,000)	 	$	(0.93	)	
Crude Oil	 	2019	 	Basis Swaps	 	Nymex	 	(20,000)	 	$	0.11		
Crude Oil	 	2019	 	Fixed Price Calls	 	WTI	 	(5,000)	 	$	54.08		
Crude Oil	 	2020	 	Basis Swaps	 	Midland	 	(5,000)	 	$	(1.16	)	
 	 	 	 	 	 	 	 	 	 	 	
Natural Gas	 	 	 	 	 	 	 	 	 	 	
Natural Gas	 	2018	 	Fixed Price Swaps	 	Henry Hub	 	(140)	 	$	2.97		
Natural Gas	 	2018	 	Basis Swaps	 	San Juan	 	(40)	 	$	(0.30	)	
Natural Gas	 	2018	 	Basis Swaps	 	Permian	 	(48)	 	$	(0.31	)	
Natural Gas	 	2018	 	Basis Swaps	 	Waha	 	(15)	 	$	0.93		
Natural Gas	 	2018	 	Basis Swaps	 	Houston Ship	 	(43)	 	$	(0.08	)	
Natural Gas	 	2018	 	Fixed Price Calls	 	Henry Hub	 	(16)	 	$	4.75		
Natural Gas	 	2019	 	Fixed Price Swaps	 	Henry Hub	 	(50)	 	$	2.88		
Natural Gas	 	2019	 	Basis Swaps	 	Permian	 	(25)	 	$	(0.39	)	
Natural Gas	 	2019	 	Basis Swaps	 	Waha	 	(45)	 	$	0.07		
Natural Gas	 	2019	 	Basis Swaps	 	Houston Ship	 	(30)	 	$	(0.09	)	
 	 	 	 	 	 	 	 	 	 	 	
Natural Gas Liquids	 	 	 	 	 	 	 	 	 	 	
Natural Gas Liquids	 	2018	 	Fixed Price Swaps	 	Ethane-Mont	 	(3,078	)	 	$	0.29		
Natural Gas Liquids	 	2018	 	Fixed Price Swaps	 	Propane	 	(900	)	 	$	0.79		
Natural Gas Liquids	 	2018	 	Fixed Price Swaps	 	Propane-Mont	 	(3,604	)	 	$	0.80		
Natural Gas Liquids	 	2018	 	Fixed Price Swaps	 	Iso Butane	 	(651	)	 	$	0.91		
Natural Gas Liquids	 	2018	 	Fixed Price Swaps	 	Normal Butane	 	(1,701	)	 	$	0.90		
Natural Gas Liquids	 	2018	 	Fixed Price Swaps	 	Natural	 	(1,401	)	 	$	1.31		

__________
		
(a)	Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas liquids production are fixed price swaps. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions grant the counterparty the option to enter into future swaps with us.	
		
(b)	Crude oil volumes are reported in Bbl/day, natural gas volumes are reported in BBtu/day and natural gas liquids volumes are reported in Bbl/day.	
		
(c)	The weighted average price for crude oil is reported in $/Bbl, the natural gas is reported in $/MMBtu and the natural gas liquids is reported in $/Gallon.	

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WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Fair values and gains (losses)
Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, our derivatives do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
 
We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.

												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
 	 	
Gain (loss) from derivatives related to production(a)	$	3		 	$	(207	)	 	$	438		
Gain (loss) from derivatives related to physical marketing agreements(b)	—		 	—		 	(20	)	
Net gain (loss) on derivatives	$	3		 	$	(207	)	 	$	418		
__________
		
(a)	Includes settlements totaling $4 million , $301 million and $650 million for the years ended December 31, 2017 , 2016 and 2015, respectively.	
		
(b)	Includes settlements totaling $1 million for the year ended December 31, 2016 and payments totaling less than $1 million and $33 million for the years ended December 31, 2017 and 2015 , respectively.	
The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows.
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities. 

												
 	Gross Amount Presented on Balance Sheet	 	Netting Adjustments (a)	 	Net Amount	
December 31, 2017	(Millions)	
Derivative assets with right of offset or master netting agreements	$	59		 	$	(42	)	 	$	17		
Derivative liabilities with right of offset or master netting agreements	$	(236	)	 	$	42		 	$	(194	)	
 	 	 	 	 	 	
December 31, 2016	 	 	 	 	 	
Derivative assets with right of offset or master netting agreements	$	38		 	$	(33	)	 	$	5		
Derivative liabilities with right of offset or master netting agreements	$	(215	)	 	$	33		 	$	(182	)	
__________
		
(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

64

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of December 31, 2017 , we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $194 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $4 million to our liability balance for our own nonperformance risk. As of December 31, 2016 , we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $182 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $5 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $194 million and $187 million at December 31, 2017 and 2016 , respectively.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
The following table summarizes concentration of receivables, net of allowances, by product or service as of dates indicated below.

								
 	December 31,	
 	2017	 	2016	
 	(Millions)	
Receivables by product or service:	 	 	 	
Sale of natural gas, crude and related products and services	$	251		 	$	122		
Joint interest owners	54		 	23		
Other	2		 	23		
Total	$	307		 	$	168		
Oil and natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the southwestern United States and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by creditworthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2017 , 2016 and 2015 , we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
Our gross and net credit exposure from our derivative contracts were $59 million and $17 million , respectively, as of December 31, 2017 . All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We consider counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.
At December 31, 2017 , all of our net credit exposure is with a single counterparty. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

65

WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Other
At December 31, 2017 , we held collateral support of $10 million , either in the form of cash, letters of credit or surety bond, related to our commodity management agreements.
Collateral support for our commodity agreements could include margin deposits, letters of credit, and guarantees of payment by credit worthy parties.
Revenues
The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

						
 	Year ended December 31,	
 	2017	 	2016	 	2015	
Crestwood Midstream Partners LP	21%	 	(a)	 	(a)	
St. Paul Refining	16%	 	13%	 	(a)	
NGL Crude Logistics	13%	 	(a)	 	(a)	
Delek Refining, Ltd	10%	 	(a)	 	(a)	
Plains Marketing	(a)	 	15%	 	(a)	
Marathon Petroleum	(a)	 	(a)	 	12%	
__________
		
(a)	Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives.	

One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course
of business, we sell crude oil to NGL Energy. For the year ended 2017, sales to NGL Energy were approximately 13 percent of our total consolidated revenues adjusted for gain (loss) on derivatives.
Note 17 . Subsequent Events
San Juan Sale
Subsequent to December 31, 2017, we sold our San Juan Gallup properties. See Note 3 for further discussion.
Credit Facility
On April 17, 2018, the Company entered into a Second Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, increases total commitments to $1.5 billion , increases the Borrowing Base to $1.8 billion , and extends the maturity date to April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million . Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time.
Borrowing Base . During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. The $1.8 billion Borrowing Base will remain in effect until the next Redetermination Date as set forth in the Credit Facility and at this time, availability under the Credit Facility Agreement is limited by the total commitments of $1.5 billion . The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.
Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding

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WPX Energy, Inc.
Notes to Consolidated Financial Statements—(Continued)

Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.
The Collateral Trigger Termination Date is the first date following the date of the closing of the Credit Facility and the first date following any Collateral Trigger Date, as applicable, on which (i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s.
Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. As amended and during a Collateral Trigger Period, the applicable margin ranges from 0.25% to 1.25% per annum in the case of the alternate base rate, and from 1.25% to 2.25% per annum in the case of LIBOR. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. As amended and during a Collateral Trigger Period, the commitment fee ranges from 0.375% to 0.500% per annum. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to the Company’s senior unsecured debt ratings.
Significant Financial Covenants.
Pursuant to the amendment, the Company is required to maintain:
		
•	a ratio of Net Indebtedness to Consolidated EBITDAX for the most recent ended four consecutive fiscal quarters (excluding the first three quarters of 2018 which will use an Annualized Consolidated EBITDAX) of not greater than 4.25 to 1.00 as of the last day of the most recently ended Rolling Period; and	
		
•	a ratio of consolidated current assets (including the unused amount of the Aggregate Commitments) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.	
If a Collateral Trigger Termination Date occurs, other financial covenants would apply and replace those listed above.
See Note 9 for additional information on covenants related to our Credit Facility that were unchanged under the new amendment.
Debt Tender
During April 2018, we commenced cash tender offers to purchase up to $500 million aggregate principal amount of our outstanding 7.500% Senior Notes due 2020 , 6.000% Senior Notes due 2022 and 8.250% Senior Notes due 2023 . On April 17, 2018, using $540 million of proceeds from our San Juan Gallup disposition, we redeemed $329 million aggregate principal amount of the 2020 Notes and $171 million aggregate principal amount of the 2022 Notes.
See Note 9 for additional discussion related to our senior notes.

67

WPX Energy, Inc.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

																
 	First
Quarter	 	Second
Quarter	 	Third
Quarter	 	Fourth
Quarter	
2017	(Millions, except per-share amounts)	
Product revenues	$	187		 	$	226		 	$	247		 	$	356		
Net gain (loss) on derivatives	$	203		 	$	116		 	$	(106	)	 	$	(210	)	
Commodity management	$	5		 	$	8		 	$	4		 	$	8		
Total revenues	$	395		 	$	350		 	$	145		 	$	155		
Operating costs and expenses	$	208		 	$	231		 	$	223		 	$	265		
Operating income	$	187		 	$	119		 	$	(78	)	 	$	(110	)	
Income (loss) from continuing operations	$	95		 	$	327		 	$	(378	)	 	$	(20	)	
Income (loss) from discontinued operations	(3	)	 	(251	)	 	232		 	(18	)	
Net income (loss)	$	92		 	$	76		 	$	(146	)	 	$	(38	)	
Amounts available to WPX Energy, Inc. common stockholders:	 	 	 	 	 	 	 	
   Income (loss) from continuing operations	$	91		 	$	323		 	$	(381	)	 	$	(24	)	
   Income (loss) from discontinued operations	(3	)	 	(251	)	 	232		 	(18	)	
Net income (loss)	$	88		 	$	72		 	$	(149	)	 	$	(42	)	
Basic earnings (loss) per common share:	 	 	 	 	 	 	 	
   Income (loss) from continuing operations	$	0.24		 	$	0.81		 	$	(0.96	)	 	$	(0.06	)	
   Income (loss) from discontinued operations	(0.01	)	 	(0.63	)	 	0.58		 	(0.04	)	
Net income (loss)	$	0.23		 	$	0.18		 	$	(0.38	)	 	$	(0.10	)	
Diluted earnings (loss) per common share:	 	 	 	 	 	 	 	
   Income (loss) from continuing operations	$	0.23		 	$	0.77		 	$	(0.96	)	 	$	(0.06	)	
   Income (loss) from discontinued operations	(0.01	)	 	(0.60	)	 	0.58		 	(0.04	)	
Net income (loss)	$	0.22		 	$	0.17		 	$	(0.38	)	 	$	(0.10	)	
2016	 	 	 	 	 	 	 	
Product revenues	$	86		 	$	130		 	$	131		 	$	160		
Net gain (loss) on derivatives	$	57		 	$	(154	)	 	$	38		 	$	(148	)	
Commodity management	$	31		 	$	116		 	$	25		 	$	5		
Total revenues	$	175		 	$	91		 	$	194		 	$	18		
Operating costs and expenses	$	189		 	$	302		 	$	187		 	$	170		
Operating income	$	(14	)	 	$	(211	)	 	$	7		 	$	(152	)	
Income (loss) from continuing operations	$	(100	)	 	$	(201	)	 	$	(209	)	 	$	(162	)	
Income (loss) from discontinued operations	88		 	3		 	(10	)	 	(10	)	
Net loss	$	(12	)	 	$	(198	)	 	$	(219	)	 	$	(172	)	
Amounts available to WPX Energy, Inc. common stockholders:	 	 	 	 	 	 	 	
   Loss from continuing operations	$	(105	)	 	$	(207	)	 	$	(235	)	 	$	(165	)	
   Income (loss) from discontinued operations	88		 	3		 	(10	)	 	(10	)	
Net loss	$	(17	)	 	$	(204	)	 	$	(245	)	 	$	(175	)	
Basic earnings (loss) per common share:	 	 	 	 	 	 	 	
   Loss from continuing operations	$	(0.38	)	 	$	(0.69	)	 	$	(0.69	)	 	$	(0.48	)	
   Income (loss) from discontinued operations	0.32		 	0.01		 	(0.03	)	 	(0.03	)	
Net loss	$	(0.06	)	 	$	(0.68	)	 	$	(0.72	)	 	$	(0.51	)	
Diluted earnings (loss) per common share:	 	 	 	 	 	 	 	
   Loss from continuing operations	$	(0.38	)	 	$	(0.69	)	 	$	(0.69	)	 	$	(0.48	)	
   Income (loss) from discontinued operations	0.32		 	0.01		 	(0.03	)	 	(0.03	)	
Net loss	$	(0.06	)	 	$	(0.68	)	 	$	(0.72	)	 	$	(0.51	)	

68

Net income or loss for each respective quarter include the following pre-tax items:
First-quarter 2017:
		
•	$31 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5 ).	
		
•	$23 million loss on write-off of expired leases in the Permian Basin (see Note 5 ).	
Third-quarter 2017:
		
•	$111 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5 ).	
		
•	$60 million impairment on San Juan Legacy included in discontinued operations (see Note 3 ).	
		
•	$17 million loss on extinguishment of debt (see Note 9 ).	
		
•	$10 million severance tax refunds for prior years related to the Piceance Basin (see Note 3 ).	
Fourth-quarter 2017:
		
•	$11 million gain on leasehold exchanges (see Note 5 ).	
		
•	$5 million increase on future commitments under gathering, processing and transportation liability related to the Powder River Basin in discontinued operations (see Note 3 ).	
		
•	$92 million income tax benefit related to the impact of new income tax legislation (see Note 10 ).	
First-quarter 2016:
		
•	$199 million gain included in discontinued operations for the sale of our San Juan Basin gathering system (see Note 3 ).	
		
•	$14 million increase of our deferred tax liability as of the beginning of the year resulting from an increase to our state effective rate.	
Second-quarter 2016:
		
•	$52 million gain included in discontinued operations for the sale of the Piceance Basin (see Note 3 ).	
		
•	$5 million recognition of a deferred gain on the sale of our San Juan Basin gathering system included in discontinued operations (see Note 3 ).	
Third-quarter 2016:
		
•	$238 million net loss on divestment of the remaining transportation contracts (see Note 5 ).	
		
•	$11 million recognition of a deferred gain on the sale of our San Juan Basin gathering system included in discontinued operations (see Note 3 ).	

69

WPX Energy, Inc.
Supplemental Oil and Gas Disclosures
(Unaudited)

We have significant continuing oil and gas producing activities primarily in the Delaware Basin in Texas and New Mexico, the Williston Basin in North Dakota and the San Juan Basin in the Rocky Mountain region, all of which are located in the United States. Subsequent to December 31, 2017, we entered into an agreement for the sale of our remaining San Juan Basin properties (see Note 3 of Notes to Consolidated Financial Statements). These properties represented approximately 12 percent of our reserves at December 31, 2017.
With the exception of Capitalized Costs, the following information includes activity through the completion of the respective asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan, Piceance and Powder River Basins, all of which have been reported as discontinued operations in our consolidated financial statements. The Piceance Basin properties were sold in April 2016 and represented approximately 52 percent of our reserves as of December 31, 2015. The Powder River Basin properties were sold in late 2015 and represented less than 5 percent of our total domestic proved reserves at December 31, 2014. Capitalized Costs do not include amounts which are classified as assets held for sale on the Consolidated Balance Sheets.
Capitalized Costs

								
 	As of December 31,	
 	2017	 	2016	
 	(Millions)	
Proved Properties	$	6,113		 	$	4,714		
Unproved properties	2,194		 	1,892		
 	8,307		 	6,606		
Accumulated depreciation, depletion and amortization and valuation provisions	(1,860	)	 	(1,358	)	
Net capitalized costs	$	6,447		 	$	5,248		
__________
		
•	Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $223 million and $170 million , net, as of December 31, 2017 and 2016 , respectively.	
		
•	Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.	
		
•	Unproved properties consist primarily of unproved leasehold costs.	

Cost Incurred

	
												
 	For the years ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Acquisition	$	864		 	$	84		 	$	3,208		
Exploration	5		 	5		 	84		
Development	1,048		 	471		 	657		
 	$	1,917		 	$	560		 	$	3,949		
__________
		
•	Costs incurred include capitalized and expensed items.	
		
•	Acquisition costs are as follows: Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) in March 2017 that included $195 million and 23.8 MMboe of proved developed reserves and facilities. Costs in 2016 primarily relates to purchases of additional acreage in the Delaware Basin and included approximately 2.5 MMboe of proved reserves. Costs in 2015 primarily relate to the allocated purchase price of RKI properties in the Permian-Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) and includes 53 MMboe of proved developed reserves.	
		
•	Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds. The 2015 amount primarily related to the drilling of Piceance Niobrara wells.	
		
•	Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our Piceance Basin operations were $27 million and $106 million for 2016 and 2015 , respectively.	

70

  Proved Reserves
The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.

71

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

												
 	Oil (MMbbls)	 	Natural Gas (Bcf)	 	NGLs (MMbbls)	 	All Products (MMboe)	
Proved reserves at December 31, 2014	130.8		 	3,149.6		 	70.8		 	726.6		
Revisions	(31.9	)	 	(624.6	)	 	(14.0	)	 	(150.0	)	
Purchases	39.8		 	205.6		 	20.7		 	94.7		
Divestitures	—		 	(380.3	)	 	—		 	(63.4	)	
Extensions and discoveries	17.1		 	116.9		 	5.1		 	41.6		
Production	(13.1	)	 	(277.0	)	 	(7.3	)	 	(66.5	)	
Proved reserves at December 31, 2015	142.7		 	2,190.2		 	75.3		 	583.0		
Revisions	(3.8	)	 	(50.2	)	 	(2.9	)	 	(15.2	)	
Purchases	1.6		 	4.4		 	0.4		 	2.8		
Divestitures	(5.5	)	 	(1,505.9	)	 	(38.3	)	 	(294.8	)	
Extensions and discoveries	54.9		 	214.6		 	19.8		 	110.5		
Production	(15.3	)	 	(118.6	)	 	(4.8	)	 	(39.9	)	
Proved reserves at December 31, 2016	174.6		 	734.5		 	49.5		 	346.4		
Revisions	4.7		 	(8.4	)	 	(1.1	)	 	2.3		
Purchases	21.8		 	58.8		 	7.8		 	39.4		
Divestitures	(1.7	)	 	(312.5	)	 	(0.8	)	 	(54.6	)	
Extensions and discoveries	86.7		 	194.5		 	23.6		 	142.7		
Production	(22.4	)	 	(75.9	)	 	(5.0	)	 	(40.0	)	
Proved reserves at December 31, 2017	263.7		 	591.0		 	74.0		 	436.2		
 	 	 	 	 	 	 	 	
Proved developed reserves:	 	 	 	 	 	 	 	
December 31, 2015	83.0		 	1,618.2		 	49.5		 	402.2		
December 31, 2016	84.4		 	440.2		 	24.1		 	181.8		
December 31, 2017	130.3		 	321.2		 	38.8		 	222.7		
 	 	 	 	 	 	 	 	
Proved undeveloped reserves:	 	 	 	 	 	 	 	
December 31, 2015	59.7		 	572.0		 	25.8		 	180.8		
December 31, 2016	90.2		 	294.2		 	25.4		 	164.6		
December 31, 2017	133.4		 	269.8		 	35.2		 	213.5		
__________
		
•	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit .	
		
•	Revisions in 2017 primarily reflect 24.1 MMboe of positive revision due to an increase in the 12 month average price offset by 21.8 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells. Revisions in 2016 primarily reflect 49 MMboe of negative revisions due to the decrease in the 12-month average price partially offset by 34 MMboe of positive revisions due to decreased costs and well improvements. Revisions in 2015 primarily reflect 209 MMboe of negative revisions related to the decrease in the 12-month average prices partially offset by 59 MMboe of positive revisions due to decreased costs and well improvements. The 2015 revisions comprised 108 MMboe net negative revisions related to proved undeveloped locations and 42 MMboe net negative revisions related to proved developed locations.	
		
•	Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed. Purchases in 2015 reflects the RKI Acquisition of which 53.4 MMboe is proved developed and 41.3 MMboe is associated with proved undeveloped locations.	
		
•	Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves. Divestitures in 2016 relate to the sale of the Piceance Basin which included proved developed reserves and proved undeveloped reserves of 222 MMboe and 67 MMboe, respectively. Divestitures in 2015 relate to sales of properties in the Powder River Basin ( 28 MMboe) and the Appalachian Basin ( 35 MMboe).	
		
•	Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins. Extensions and discoveries in 2016 reflect 26 MMboe added for proved developed locations and 84 MMboe for proved undeveloped locations primarily in the Delaware Basin. Extensions and discoveries in 2015 reflect 21 MMboe added for proved developed locations and 21 MMboe for proved undeveloped locations primarily related to our San Juan Gallup and Williston Basins.	

72

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves. Prices were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. The average domestic oil price used in the estimates for the years ended December 31, 2017 , 2016 and 2015 was $46.39 , $35.91 and $43.84 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2017, 2016 and 2015 was $1.67 , $1.74 and $2.26 per Mcf, respectively. The average NGL price per barrel was $21.16 , $10.57 and $15.84 for the same periods. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows

								
 	As of December 31,	
 	2017	 	2016	
 	(Millions)	
Future cash inflows	$	14,785		 	$	8,072		
Less:	 	 	 	
Future production costs	6,112		 	4,076		
Future development costs	2,070		 	1,518		
Future income tax provisions	408		 	—		
Future net cash flows	6,195		 	2,478		
Less 10 percent annual discount for estimated timing of cash flows	3,034		 	1,440		
Standardized measure of discounted future net cash inflows	$	3,161		 	$	1,038		
__________
		
•	Our historical tax basis, including carryforwards, (i.e. future deductions for taxable income calculation) of proved properties at December 31, 2016 are greater than the total standardized measure of future net cash flows before taxes; therefore, future taxable income as calculated in the standardized measure of cash flows would be less than zero.	
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

												
 	For the years ended December 31,	
 	2017	 	2016	 	2015	
 	(Millions)	
Beginning of year	$	1,038		 	$	1,284		 	$	3,883		
Sales of oil and gas produced, net of operating costs	(894	)	 	(458	)	 	(541	)	
Net change in prices and production costs	1,385		 	(261	)	 	(5,231	)	
Extensions, discoveries and improved recovery, less estimated future costs	816		 	735		 	254		
Development costs incurred during year	345		 	142		 	276		
Changes in estimated future development costs	105		 	(211	)	 	1,213		
Purchase of reserves in place, less estimated future costs	305		 	20		 	657		
Sale of reserves in place, less estimated future costs	20		 	(253	)	 	(397	)	
Revisions of previous quantity estimates	30		 	(78	)	 	(374	)	
Accretion of discount	104		 	136		 	489		
Net change in income taxes	(83	)	 	—		 	1,073		
Other	(10	)	 	(18	)	 	(18	)	
Net changes	2,123		 	(246	)	 	(2,599	)	
End of year	$	3,161		 	$	1,038		 	$	1,284		

73

Exhibit 99.2

WPX Energy, Inc.
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

	
																				
 	Beginning
Balance	 	Charged
(Credited)
to Costs and
Expenses	 	Other	 	Deductions	 	Ending
Balance	
 	 	
2017:	 	 	 	 	 	 	 	 	 	
Allowance for doubtful accounts—accounts and notes receivable(a)	$	3		 	$	—		 	$	—		 	$	(1	)	 	$	2		
Deferred tax asset valuation(b)(f)	151		 	44		 	—		 	—		 	195		
Price-risk management credit reserves—liabilities(c)(d)	5		 	—		 	(1	)	 	—		 	4		
2016:	 	 	 	 	 	 	 	 	 	
Allowance for doubtful accounts—accounts and notes receivable(a)	$	6		 	$	—		 	$	—		 	$	(3	)	 	$	3		
Deferred tax asset valuation(b)	124		 	26		 	1		 	—		 	151		
Price-risk management credit reserves—assets(a)(d)	1		 	—		 	(1	)	 	—		 	—		
Price-risk management credit reserves—liabilities(c)(d)	—		 	—		 	5		 	—		 	5		
2015:	 	 	 	 	 	 	 	 	 	
Allowance for doubtful accounts—accounts and notes receivable(a)	$	6		 	$	5		 	$	—		 	$	(5	)	 	$	6		
Deferred tax asset valuation(b)(e)	118		 	3		 	3		 	—		 	124		
Price-risk management credit reserves—assets(a)(d)	1		 	—		 	—		 	—		 	1		
  __________
		
(a)	Deducted from related assets.	
		
(b)	Deducted from related assets with a portion included in assets held for sale.	
		
(c)	Deducted from related liabilities.	
		
(d)	Included in revenues.	
		
(e)	Includes RKI Acquisition.	
		
(f)	Includes impact of the Tax Cuts and Jobs Act enacted rate reduction.