10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2019

OR

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

For the transition period from to

Commission file number 1-35322

WPX Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		45-1836028
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
3500 One Williams Center
Tulsa,	Oklahoma	74172-0172
(Address of Principal Executive Offices)		(Zip Code)

855-979-2012

(Registrant’s Telephone Number, Including Area Code)

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

Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	WPX	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

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

Large accelerated filer	þ	Accelerated filer	☐
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	☐
		Emerging growth company	☐

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

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

The number of shares outstanding of the registrant’s common stock at August 5, 2019 were 422,395,102.

WPX Energy, Inc.

Index

			Page
Part I.	Financial Information
	Item 1.	Financial Statements (Unaudited)
		Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	4
		Consolidated Statements of Operations for the three and six months ended June 30, 2019 and 2018	5
		Consolidated Statements of Changes in Equity for the three and six months ended June 30, 2019 and 2018	6
		Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018	7
		Notes to Consolidated Financial Statements	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
	Item 4.	Controls and Procedures	36
Part II.	Other Information
	Item 1.	Legal Proceedings	38
	Item 1A.	Risk Factors	38
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
	Item 3.	Defaults Upon Senior Securities	38
	Item 4.	Mine Safety Disclosures	38
	Item 5.	Other Information	38
	Item 6.	Exhibits	39

Certain matters contained in this report include forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

•amounts and nature of future capital expenditures;

•expansion and growth of our business and operations;

•financial condition and liquidity;

•business strategy;

•estimates of proved oil and natural gas reserves;

•reserve potential;

•development drilling potential;

•cash flow from operations or results of operations;

•acquisitions or divestitures;

•seasonality of our business; and

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

2

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

•availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of commodity prices and the availability and cost of capital;

•inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

•the strength and financial resources of our competitors;

•development of alternative energy sources;

•the impact of operational and development hazards;

•costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;

•changes in maintenance and construction costs;

•changes in the current geopolitical situation;

•our exposure to the credit risk of our customers;

•risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

•risks associated with future weather conditions;

•acts of terrorism;

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

•additional risks described in our filings with the Securities and Exchange Commission (“SEC”).

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth above. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. Forward-looking statements speak only as of the date they are made. We disclaim any obligation to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018.

3

WPX Energy, Inc.

Consolidated Balance Sheets

(Unaudited) 

	June 30, 2019		December 31, 2018
	(Millions)
Assets
Current assets:
Cash and cash equivalents	$	109	$	3
Accounts receivable, net of allowance	505		405
Derivative assets	81		174
Inventories	45		48
Assets classified as held for sale	—		79
Other	34		30
Total current assets	774		739
Investments	55		167
Properties and equipment (successful efforts method of accounting)	10,713		9,949
Less—accumulated depreciation, depletion and amortization	(3,158)		(2,683)
Properties and equipment, net	7,555		7,266
Derivative assets	42		4
Other noncurrent assets (Note 1)	127		27
Total assets	$	8,553	$	8,203
Liabilities and Equity
Current liabilities:
Accounts payable	$	721	$	514
Accrued and other current liabilities (Note 1)	225		178
Derivative liabilities	80		23
Total current liabilities	1,026		715
Deferred income taxes	270		201
Long-term debt, net	2,157		2,485
Derivative liabilities	29		14
Other noncurrent liabilities (Note 1)	510		487
Contingent liabilities and commitments (Note 8)
Equity:
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding)	—		—
Common stock (2 billion shares authorized at $0.01 par value; 422.3 million and 420.6 million shares issued and outstanding at June 30, 2019 and December 31, 2018)	4		4
Additional paid-in-capital	7,737		7,734
Accumulated deficit	(3,180)		(3,437)
Total stockholders’ equity	4,561		4,301
Total liabilities and equity	$	8,553	$	8,203

See accompanying notes.

4

WPX Energy, Inc.

Consolidated Statements of Operations

(Unaudited) 

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
Revenues:	(Millions, except per-share amounts)
Product revenues:
Oil sales	$	511	$	468	$	960	$	828
Natural gas sales	16		16		41		33
Natural gas liquid sales	31		36		64		66
Total product revenues	558		520		1,065		927
Net gain (loss) on derivatives	78		(154)		(129)		(223)
Commodity management	58		64		117		100
Other	1		—		1		—
Total revenues	695		430		1,054		804
Costs and expenses:
Depreciation, depletion and amortization	221		197		440		358
Lease and facility operating	94		59		180		114
Gathering, processing and transportation	40		20		82		38
Taxes other than income	43		41		82		71
Exploration (Note 4)	24		17		48		36
General and administrative (including equity-based compensation of $8 million, $10 million, $16 million and $17 million for the respective periods)	48		44		95		87
Commodity management	41		54		90		93
Other—net	3		1		5		4
Total costs and expenses	514		433		1,022		801
Operating income (loss)	181		(3)		32		3
Interest expense	(40)		(39)		(81)		(85)
Loss on extinguishment of debt	—		(71)		—		(71)
Gains on equity method investment transactions	247		—		373		—
Investment income (loss) and other	1		1		3		—
Income (loss) from continuing operations before income taxes	389		(112)		327		(153)
Provision (benefit) for income taxes	84		(33)		70		(48)
Income (loss) from continuing operations	305		(79)		257		(105)
Income (loss) from discontinued operations	—		(2)		—		(91)
Net income (loss)	305		(81)		257		(196)
Less: Dividends on preferred stock	—		4		—		8
Net income (loss) available to WPX Energy, Inc. common stockholders	$	305	$	(85)	$	257	$	(204)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations	$	305	$	(83)	$	257	$	(113)
Income (loss) from discontinued operations	—		(2)		—		(91)
Net income (loss)	$	305	$	(85)	$	257	$	(204)
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.72	$	(0.21)	$	0.61	$	(0.28)
Income (loss) from discontinued operations	—		—		—		(0.23)
Net income (loss)	$	0.72	$	(0.21)	$	0.61	$	(0.51)
Basic weighted-average shares	422.5		400.0		421.8		399.3
Diluted weighted-average shares	423.5		400.0		423.6		399.3

See accompanying notes.

5

WPX Energy, Inc.

Consolidated Statements of Changes in Equity

(Unaudited)

	Three months ended June 30,
	Preferred Stock		Common Stock		Additional Paid-In- Capital		Accumulated Deficit		Total Stockholders’ Equity
	(Millions)
Balance at March 31, 2019	$	—	$	4	$	7,729	$	(3,485)	$	4,248
Net income	—		—		—		305		305
Stock-based compensation, net of tax impact	—		—		8		—		8
Balance at June 30, 2019	$	—	$	4	$	7,737	$	(3,180)	$	4,561
Balance at March 31, 2018	$	232	$	4	$	7,473	$	(3,703)	$	4,006
Net loss	—		—		—		(81)		(81)
Stock-based compensation, net of tax impact	—		—		14		—		14
Dividends on preferred stock	—		—		(4)		—		(4)
Balance at June 30, 2018	$	232	$	4	$	7,483	$	(3,784)	$	3,935

	Six months ended June 30,
	Preferred Stock		Common Stock		Additional Paid-In- Capital		Accumulated Deficit		Total Stockholders’ Equity
	(Millions)
Balance at December 31, 2018	$	—	$	4	$	7,734	$	(3,437)	$	4,301
Net income	—		—		—		257		257
Stock-based compensation, net of tax impact	—		—		3		—		3
Balance at June 30, 2019	$	—	$	4	$	7,737	$	(3,180)	$	4,561
Balance at December 31, 2017	$	232	$	4	$	7,479	$	(3,588)	$	4,127
Net loss	—		—		—		(196)		(196)
Stock-based compensation, net of tax impact	—		—		12		—		12
Dividends on preferred stock	—		—		(8)		—		(8)
Balance at June 30, 2018	$	232	$	4	$	7,483	$	(3,784)	$	3,935

See accompanying notes.

6

WPX Energy, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Six months ended June 30,
	2019		2018
Operating Activities(a)	(Millions)
Net income (loss)	$	257	$	(196)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	440		365
Deferred income tax provision (benefit)	69		(75)
Provision for impairment of properties and equipment (including certain exploration expenses)	41		37
Gains related to equity method investment transactions	(373)		—
Net (gain) loss on derivatives	129		223
Net settlements related to derivatives	(1)		(133)
Amortization of stock-based awards	17		18
Loss on extinguishment of debt	—		71
Net (gain) loss on sales of assets including discontinued operations	—		151
Cash provided by (used in) operating assets and liabilities:
Accounts receivable	(145)		(16)
Inventories	2		(11)
Other current assets	(1)		4
Accounts payable	203		73
Federal income taxes receivable	38		—
Accrued and other current liabilities	(17)		(59)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	(15)		(28)
Other, including changes in other noncurrent assets and liabilities	(10)		4
Net cash provided by operating activities(a)	634		428
Investing Activities(a)
Capital expenditures(b)	(774)		(660)
Proceeds from sales of assets and equity method investment transactions	590		686
Contributions to or purchases of equity method investments	(18)		(23)
Distributions from equity method investments	7		—
Net cash provided by (used in) investing activities(a)	(195)		3
Financing Activities
Proceeds from common stock	1		5
Dividends paid on preferred stock	—		(8)
Borrowings on credit facility	1,002		303
Payments on credit facility	(1,332)		(303)
Proceeds from long-term debt, net of discount	—		494
Payments for retirement of long-term debt, including premium	—		(986)
Taxes paid for shares withheld	(15)		(12)
Payments for debt issuance costs and credit facility amendment fees	—		(10)
Other	14		1
Net cash used in financing activities	(330)		(516)
Net increase (decrease) in cash and cash equivalents and restricted cash	109		(85)
Cash and cash equivalents and restricted cash at beginning of period	18		201
Cash and cash equivalents and restricted cash at end of period	$	127	$	116
__________
(a) Amounts reflect continuing and discontinued operations unless otherwise noted.
(b) Increase to properties and equipment	$	(766)	$	(705)
Changes in related accounts payable and accounts receivable	(8)		45
Capital expenditures	$	(774)	$	(660)

See accompanying notes.

7

WPX Energy, Inc.

Notes to Consolidated Financial Statements

Note 1. Description of Business and Basis of Presentation

Description of Business

Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from other third-parties in our operating areas in conjunction with the management of various commodity related contracts such as transportation.

We have sold certain operations which are reported as discontinued operations and are discussed in Note 2 of Notes to Consolidated Financial Statements.

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

Basis of Presentation

The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2018 in the Company's Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2019, results of operations for the three and six months ended June 30, 2019 and 2018, changes in equity for the three and six months ended June 30, 2019 and 2018, and cash flows for the six months ended June 30, 2019 and 2018. The Company has no element of comprehensive income (loss) other than net income (loss).

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

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

Discontinued Operations

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

Recently Adopted Accounting Standards

The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases, effective January 1, 2019. The standard requires the recognition of right of use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right of use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess:

•whether existing contracts are or contain leases;

•lease classification for any expired or existing leases;

•initial direct costs for any existing lease; and

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

See Note 9 for additional information related to our contracts that are or contain leases.

We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019. This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging

8

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period.

Accounting Standards Not Yet Adopted

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

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

Note 2. Discontinued Operations

In first-quarter 2018, we sold our properties in the San Juan Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. We believed and continue to believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and the purchaser, and the declining size of the obligations subject to the guarantee over time. As part of the divestiture, we had to determine the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018.

Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years associated with our exit from the Powder River Basin.

9

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Summarized Results of Discontinued Operations

The following table presents the results of our discontinued operations for the six months ended June 30, 2018. For the three and six months ended June 30, 2019 and the three months ended June 30, 2018, our discontinued operations activity was minimal and therefore is not included in the table below.

	Six months ended June 30,
	2018
Total revenues	$	75
Costs and expenses:
Depreciation, depletion and amortization	$	8
Lease and facility operating	7
Gathering, processing and transportation	12
Taxes other than income	5
General and administrative	1
Exploration	3
Accretion for transportation and gathering obligations retained	3
Other—net	4
Total costs and expenses	43
Operating income	32
Loss on sale of assets	(150)
Loss from discontinued operations before income taxes	(118)
Income tax benefit	(27)
Loss from discontinued operations	$	(91)

Cash Flows Attributable to Discontinued Operations

Cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $15 million and $28 million for the six months ended June 30, 2019 and 2018, respectively. In addition, cash flows related to San Juan Gallup includes $45 million of cash provided by operating activities, excluding income taxes and changes in working capital items, and $29 million of cash capital expenditures within investing activities for the six months ended June 30, 2018.

10

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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

The following table summarizes the calculation of earnings per share.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions, except per-share amounts)
Income (loss) from continuing operations	$	305	$	(79)	$	257	$	(105)
Less: Dividends on preferred stock	—		4		—		8
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share	$	305	$	(83)	$	257	$	(113)
Basic weighted-average shares	422.5		400.0		421.8		399.3
Effect of dilutive securities(a)	1.0		—		1.8		—
Diluted weighted-average shares	423.5		400.0		423.6		399.3
Earnings (loss) per common share from continuing operations:
Basic	$	0.72	$	(0.21)	$	0.61	$	(0.28)
Diluted	$	0.72	$	(0.21)	$	0.61	$	(0.28)

__________

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

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
	(Millions)
Weighted-average nonvested restricted stock units and awards	—	2.9	—	3.0
Weighted-average stock options	—	0.2	—	0.2
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock	Not Applicable	19.8	Not Applicable	19.8
Nonvested restricted stock units and awards antidilutive under the treasury stock method	2.6	0.7	2.6	0.7

Stock options of approximately 0.9 million and 0.6 million that were outstanding at June 30, 2019 and 2018, respectively, have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the respective second quarter weighted-average market price of our common shares.

11

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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

Asset Sale

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

Equity Method Investment Transactions

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

During the second quarter of 2019, we received a distribution of approximately $357 million related to our 25 percent equity interest in the Oryx pipeline partnership after the underlying assets were sold. This transaction is subject to post-closing adjustments. The net book value of this equity method investment was approximately $110 million as of the closing date. As a result of this transaction, we recorded a gain of $247 million.

Exploration Expenses

The following table presents a summary of exploration expenses.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions)
Unproved leasehold property amortization	$	21	$	16	$	44	$	33
Geologic and geophysical costs	3		1		4		3
Total exploration expenses	$	24	$	17	$	48	$	36

Note 5. Inventories

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

	June 30, 2019		December 31, 2018
	(Millions)
Material, supplies and other	$	41	$	46
Commodity production in transit or storage	4		2
Total inventories	$	45	$	48

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 6. Debt and Banking Arrangements

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

	June 30, 2019		December 31, 2018
	(Millions)
Credit facility agreement	$	—	$	330
6.000% Senior Notes due 2022	529		529
8.250% Senior Notes due 2023	500		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		500
Total long-term debt	$	2,179	$	2,509
Less: Debt issuance costs on long-term debt(a)	22		24
Total long-term debt, net(a)	$	2,157	$	2,485

__________

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

Credit Facility 

As of June 30, 2019, we had no borrowings outstanding and $42 million of letters of credit issued under the Credit Facility and we were in compliance with our financial covenants with full access to the Credit Facility.

On April 22, 2019, the Company entered into a Third Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, the Swingline Lender and each of the issuing banks party thereto (the "Credit Facility"). The Credit Facility, as amended, gives the Company the option, if certain conditions are met, to elect during any Collateral Trigger Period that scheduled redeterminations of the Borrowing Base be made annually on April 1 instead of semi-annually.

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

See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information on covenants related to our Credit Facility. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended.

Senior Notes

See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional discussion related to our senior notes.

Note 7. Provision (Benefit) for Income Taxes

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

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions)
Current:
Federal	$	—	$	—	$	—	$	—
State	2		—		1		—
	2		—		1		—
Deferred:
Federal	75		(28)		63		(37)
State	7		(5)		6		(11)
	82		(33)		69		(48)
Total provision (benefit)	$	84	$	(33)	$	70	$	(48)

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

The effective income tax rate for the three months ended June 30, 2019, differs slightly from the federal statutory rate of 21 percent due to to the effect of state income taxes and equity-based compensation, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gain from a 2019 transaction involving an equity interest in a partnership.

The effective income tax rate for the three months ended June 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of state income taxes.

The effective income tax rate for the six months ended June 30, 2019, differs slightly from the federal statutory rate of 21 percent due to to the effect of state income taxes and equity-based compensation, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gains from the 2019 transactions involving equity interests in partnerships.

The effective income tax rate for the six months ended June 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of an adjustment to state deferred taxes as a result of a decrease in the blended state income tax rate due to changes in state apportionment factors resulting from the divestment of our San Juan Basin assets.

We have recorded valuation allowances against deferred tax assets attributable primarily to certain state net operating loss (“NOL”) carryovers. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. We have not recorded a valuation allowance against our federal NOL carryover, but a valuation allowance could be required in future periods if the federal NOL carryover continues to increase or circumstances change.

The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three-year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of June 30, 2019, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015 (“RKI”). Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the acquisition.

Pursuant to our tax sharing agreement with The Williams Companies, Inc. ("Williams"), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre-spin-off period for which we continue to have exposure to audit adjustments as part of Williams. In 2017, the IRS proposed an adjustment related to our business for which a payment to Williams could be required. We, along with Williams, have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS.

As of June 30, 2019, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. Currently, we do not expect ultimate resolution of our uncertain tax position during the next 12 months.

Note 8. Contingent Liabilities and Commitments

Contingent Liabilities

Royalty litigation

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

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and on September 21, 2018 the Tenth Circuit dismissed the appeal for lack of jurisdiction. On January 22, 2019, plaintiffs’ filed a petition for certiorari to the United States Supreme Court, which was denied on April 1, 2019. At this time, we believe that our royalty calculations were properly determined in accordance with the appropriate contractual arrangements and applicable laws.

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

Environmental matters

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

Matters related to Williams’ former power business

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

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. In February, 2019, settlement agreements with the Kansas and Missouri class claimants were executed. A final fairness hearing seeking the court's approval of the settlement is set for August 5, 2019. In the Wisconsin class action, defendants' motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs' motion to remand the case to the originally filed district court.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered

15

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court, and the MDL Court has now remanded the case to the United States District Court for the District of Kansas. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.

Other Indemnifications

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

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

As of June 30, 2019, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

As of June 30, 2019 and December 31, 2018, the Company had accrued approximately $11 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

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

Commitments

During 2019, primarily in the second quarter, we contracted for additional oil and natural gas transportation capacity to other locations in attempts to avoid location constraints and obtain more favorable pricing differentials. This capacity is associated with projects for which the counterparties have not yet begun construction. Related minimum commitments, when construction is complete and facilities are in service, total approximately $800 million over a five to ten year period with annual demand payments, beginning in 2021, ranging from approximately $38 million to $97 million.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 9. Leases

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

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

Certain of our leases include rental payments adjusted periodically for inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. From time to time we may enter into lease contracts that commence in future periods. Lease contracts that will commence subsequent to June 30, 2019 are not significant.

The following tables include quantitative disclosures related to our leases.

	Six months ended June 30, 2019
	(Millions)
Lease Costs:
Leases recorded on the Consolidated Balance Sheet:
Operating lease cost—drilling rigs(a)	$	20
Operating lease cost—other(a)	9
Variable lease cost—drilling rigs(a)	3
Variable lease cost—other(a)	2
Short-term leases:
Drilling rigs(b)	20
Other(b)	59
Total lease cost	$	113
Other Information:
Cash paid for amount included in the measurement of lease liabilities:
Operating cash flows used for operating leases(a)	$	9
Investing cash flows used for operating leases(a)	$	20
Right-of-use assets obtained in exchange for new operating lease liabilities	$	32
Weighted-average remaining lease term (in years)	1.81 years
Weighted-average discount rate—operating leases	5		%

__________

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

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

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

The following tables include quantitative disclosures related to our leases as of June 30, 2019.

	Drilling Rigs		Real Estate, Compression and Other		Total Undiscounted Cash Flows
	(Millions)
Maturity of Lease Liabilities:
July 2019 through December 2019	$	20	$	10	$	30
2020	36		17		53
2021	4		10		14
2022	—		1		1
2023	—		—		—
Thereafter	—		—		—
					$	98
Current lease liabilities	$	36	$	18	$	54
Noncurrent lease liabilities	21		19		40
Total lease liabilities	$	57	$	37	$	94
Difference between undiscounted cash flows and discounted cash flows					$	4
Total right-of-use assets on Consolidated Balance Sheet					$	94

Note 10. Fair Value Measurements

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

	June 30, 2019								December 31, 2018
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	123	$	—	$	123	$	—	$	175	$	3	$	178
Energy derivative liabilities	$	—	$	109	$	—	$	109	$	—	$	37	$	—	$	37
Total debt(a)	$	—	$	2,296	$	—	$	2,296	$	—	$	2,414	$	—	$	2,414

__________

(a)The carrying value of total debt, excluding debt issuance costs, was $2,179 million and $2,509 million as of June 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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

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

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

Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

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

Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a quarterly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million and $3 million included in Level 3 as of June 30, 2019 and December 31, 2018, respectively.

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended June 30, 2019 and 2018.

There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

Note 11. Derivatives and Concentration of Credit Risk

Energy Commodity Derivatives

Risk Management Activities

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

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

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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 June 30, 2019.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	Jul - Dec 2019	Fixed Price Swaps	WTI	(53,000)	$	54.62
Crude Oil	Jul - Dec 2019	Basis Swaps	Midland/Cushing	(22,000)	$	(1.37)
Crude Oil	Jul - Dec 2019	Basis Swaps	Nymex CMA Roll	(16,630)	$	0.11
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston	(1,663)	$	4.63
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston/Midland	(5,652)	$	6.47
Crude Oil	Jul - Dec 2019	Basis Swaps	Argus LLS/Midland	(1,663)	$	8.60
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston/Argus LLS	(1,663)	$	0.75
Crude Oil	Jul - Dec 2019	Basis Swaps	Clearbrook	(8,000)	$	(3.23)
Crude Oil	Jul - Dec 2019	Fixed Price Calls	WTI	(5,000)	$	54.08
Crude Oil	Jul - Dec 2019	Fixed Price Collars	WTI	(8,000)	$50.00 - $60.19
Crude Oil	2020	Fixed Price Swaps	WTI	(20,000)	$	59.03
Crude Oil	2020	Basis Swaps	Midland/Cushing	(7,486)	$	(1.31)
Crude Oil	2020	Basis Swaps	Brent/WTI Spread	(5,000)	$	8.36
Crude Oil	2020	Fixed Price Collars	WTI	(20,000)	$53.33 - $63.48
Crude Oil	2021	Basis Swaps	Brent/WTI Spread	(1,000)	$	8.00
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75
Natural Gas
Natural Gas	Jul - Dec 2019	Fixed Price Swaps	Henry Hub	(110)	$	3.07
Natural Gas	Jul - Dec 2019	Basis Swaps	Permian	(25)	$	(0.39)
Natural Gas	Jul - Dec 2019	Basis Swaps	Waha	(15)	$	2.94
Natural Gas	Jul - Dec 2019	Basis Swaps	Houston Ship Channel	(30)	$	(0.09)
Natural Gas	2020	Basis Swaps	Waha	(60)	$	(0.79)
Natural Gas	2021	Basis Swaps	Waha	(70)	$	(0.59)
Natural Gas	2022	Basis Swaps	Waha	(70)	$	(0.57)
Natural Gas	2023	Basis Swaps	Waha	(70)	$	(0.51)

__________

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

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

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

Fair values and gains (losses)

Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. Net gain (loss) on derivatives on the Consolidated Statements of Operations includes net settlements to be paid of $10 million and $1 million for the three and six months ended June 30, 2019, respectively, and $78 million and $133 million for the three and six months ended June 30, 2018, respectively.

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

Offsetting of derivative assets and liabilities

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

	Gross Amount Presented on Balance Sheet		Netting Adjustments (a)		Net Amount
June 30, 2019	(Millions)
Derivative assets with right of offset or master netting agreements	$	123	$	(72)	$	51
Derivative liabilities with right of offset or master netting agreements	$	(109)	$	72	$	(37)
December 31, 2018
Derivative assets with right of offset or master netting agreements	$	178	$	(37)	$	141
Derivative liabilities with right of offset or master netting agreements	$	(37)	$	37	$	—

__________

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

Credit-risk-related features

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

As of June 30, 2019, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $37 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. Assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, the additional collateral that we would have been required to post at June 30, 2019 was $37 million. 

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

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

21

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2019 and 2018, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

Our gross and net credit exposure from our derivative contracts were $123 million and $51 million, respectively, as of June 30, 2019. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.

Our six largest net counterparty positions represent approximately 99 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course of business, we sell crude oil to NGL Energy. For the first six months of 2019, sales to NGL Energy were approximately 14 percent of our total consolidated revenues adjusted for loss on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent approximately 1 percent of operating expenses.

Other

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

Note 12. Subsequent Event

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

22

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes included elsewhere in this Form 10-Q and our 2018 Annual Report on Form 10-K. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Form 10-Q and our 2018 Annual Report on Form 10-K.

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

Overview

Composition of production (based on MBoe) and product revenue

Three months ended June 30, Six months ended June 30,

Overall quarter volumes increased 28 percent with oil leading the increase at 21 percent for the quarter. Our oil production as a percent of total production declined compared to 2018 due to Delaware production growth which has a higher natural gas component than our Williston production. The following table presents our production volumes and financial highlights for the three and six months ended June 30, 2019 and 2018:

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
Production Sales Volume Data(a):			Per day			Per day			Per day			Per day
Oil (MBbls)	8,905		97.9	7,352		80.8	17,552		97.0	13,271		73.3
Natural gas (MMcf)	18,736		205.9	13,854		152.2	36,947		204.1	25,763		142.3
NGLs (MBbls)	2,493		27.4	1,713		18.8	4,781		26.4	3,053		16.9
Combined equivalent volumes (MBoe)(b)	14,520		159.6	11,374		125.0	28,491		157.4	20,618		113.9
Financial Data (millions):
Total product revenues	$	558		$	520		$	1,065		$	927
Total revenues	$	695		$	430		$	1,054		$	804
Operating income (loss)	$	181		$	(3)		$	32		$	3
Capital expenditure activity(c)	$	341		$	355		$	766		$	705

 __________

(a)Excludes production from our discontinued operations.

(b)MBoe are calculated using the ratio of six Mcf to one barrel of oil.

(c)Includes capital expenditures activity related to discontinued operations of $1 million and $27 million for the three and six months ended June 30, 2018, respectively.

23

Our second quarter 2019 operating results were $184 million favorable compared to second quarter 2018. The primary items impacting the three months ended June 30, 2019 compared to the same period in 2018 include:

•$38 million increase in product revenues, primarily oil sales, of which $98 million related to higher production sales volumes offset by $55 million related to lower sales prices; and

•$232 million favorable change in net gain (loss) on derivatives.

Offset by:

•$81 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income.

Our year-to-date 2019 operating results were $29 million favorable compared to year-to-date 2018. The primary items impacting the six months ended June 30, 2019 compared to the same period in 2018 include:

•$138 million increase in product revenues, primarily oil sales, of which $267 million related to higher oil volumes, offset by $135 million related to lower oil prices; and

•$94 million favorable change in net gain (loss) on derivatives.

Offset by:

•$203 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income.

Outlook

After our multi-year transformation of WPX, our oil-prone positions in the Delaware (Permian) and Williston Basins now form the foundation of WPX. Our acreage positions in each of these basins contains some of the top geology in the plays and in North America. Over the same period, we have also assembled an attractive infrastructure portfolio in the Permian which will help flow our production out of the basin and will create additional value either through monetization of our midstream investments or lower operating costs. In addition to our joint venture with Howard Energy Partners LLC, we made additional investments during 2018 in our equity positions in Whitewater and Oryx pipeline systems. In 2019, we closed on transactions and monetized the value in Whitewater and Oryx totaling approximately $500 million. Overall, we believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. For 2019, we currently expect our operating cash flows to exceed our base capital expenditures plan. However, the challenging and dynamic environment of oil and gas industry, along with future market conditions, may alter these expectations or plans. We would make appropriate adjustments to our plans if we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices.

Our expected base capital budget for full-year 2019 is $1.1 billion to $1.275 billion excluding land purchases. Planned capital for drilling and completions, including non-operated wells, is $1.050 billion to $1.175 billion for the full year 2019, with an additional $50 million to $100 million in midstream opportunities in the Delaware Basin.

Our June 30, 2019 liquidity totaled approximately $1.6 billion, reflecting amounts available under the Credit Facility Agreement and cash on hand. Our next Senior Note maturity of $529 million is not due until 2022. As of this filing, our Credit Facility Agreement is subject to a $2.1 billion borrowing base with aggregate elected commitments of $1.5 billion and a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 (see Note 6 of Notes to Consolidated Financial Statements for further discussion). We believe our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a downturn. 

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

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

•continuing to pursue cost improvements and efficiency gains;

•employing new technology and operating methods;

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

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

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

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

24

•lower than anticipated energy commodity prices;

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

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

•lower than expected levels of cash flow from operations;

•counterparty credit and performance risk;

•general economic, financial markets or industry downturn;

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

•changes in the political and regulatory environments; and

•decreased drilling success.

We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel over the past five years. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. If forecasted oil and natural gas prices were to decline, we would need to review the producing properties net book value for possible impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant. The net book value of our proved properties is $5.8 billion. In addition, the net book value associated with unproved leasehold is approximately $1.7 billion and is primarily associated with our Delaware Basin properties. See our discussion of impairment of long-lived assets in our Critical Accounting Estimates discussion in our 2018 Annual Report on Form 10-K.

25

Results of Operations

Three Month-Over-Three Month Results of Operations

Revenue analysis 

	Three months ended June 30,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2019		2018
	(Millions)
Revenues:
Oil sales	$	511	$	468	$	43	9	%
Natural gas sales	16		16		—		—	%
Natural gas liquid sales	31		36		(5)		(14)	%
Total product revenues	558		520		38		7	%
Net gain (loss) on derivatives	78		(154)		232		NM
Commodity management	58		64		(6)		(9)	%
Other	1		—		1		NM
Total revenues	$	695	$	430	$	265	62	%

__________

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:

•$43 million increase in oil sales reflects $98 million related to higher production sales volumes partially offset by $55 million related to lower sales prices for the three months ended June 30, 2019 compared to 2018. The increase in production sales volumes was driven by both our Delaware and Williston Basins. The Delaware Basin volumes were 46.5 MBbls per day compared to 39.1 MBbls per day for the three months ended June 30, 2019 and 2018, respectively. The Williston Basin volumes were 51.4 MBbls per day compared to 41.7 MBbls per day for the three months ended June 30, 2019 and 2018, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for the three months ended June 30, 2019 and 2018:

	Three months ended June 30,
	2019		2018
Oil sales (per barrel)	57.42		$	63.63
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	(2.98)		(11.47)
Oil net price including derivative settlements (per barrel)	$	54.44	$	52.16
Oil production sales volumes (MBbls)	8,905		7,352
Per day oil production sales volumes (MBbls/d)	97.9		80.8

__________

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

26

•Natural gas sales reflects $5 million related to higher production sales volumes offset by $5 million related to lower sales prices for the three months ended June 30, 2019 compared to 2018. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 170.9 Mmcf per day compared to 126.7 Mmcf per day for the three months ended June 30, 2019 and 2018, respectively. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for the three months ended June 30, 2019 and 2018:

	Three months ended June 30,
	2019		2018
Natural gas sales (per Mcf)	$	0.88	$	1.12
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)	0.88		0.75
Natural gas net price including derivative settlements (per Mcf)	$	1.76	$	1.87
Natural gas production sales volumes (MMcf)	18,736		13,854
Per day natural gas production sales volumes (MMcf/d)	205.9		152.2

__________

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

•$5 million decrease in natural gas liquids sales primarily reflect $21 million related to lower sales price partially offset by $16 million related to higher production sales volumes for the three months ended June 30, 2019 compared to 2018. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 21.7 MBbls per day compared to 14.2 MBbls per day for the three months ended June 30, 2019 and 2018, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for the three months ended June 30, 2019 and 2018:

	Three months ended June 30,
	2019		2018
NGL sales (per barrel)	$	12.21	$	20.94
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	—		(2.06)
NGL net price including derivative settlements (per barrel)	$	12.21	$	18.88
NGL production sales volumes (MBbls)	2,493		1,713
Per day NGL production sales volumes (MBbls/d)	27.4		18.8

__________

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

•$232 million favorable change in net gain (loss) on derivatives primarily reflects favorable change in crude oil derivatives which was a result of gains in 2019 due to decreases in 2019 of forward commodity prices relative to our hedge positions as opposed to losses in 2018 due to increases in 2018 of forward commodity prices relative to our hedge positions at that time. Settlements to be paid on derivatives totaled $10 million and $78 million for three months ended June 30, 2019 and June 30, 2018, respectively.

•$6 million decrease in commodity management revenues is primarily due to lower natural gas prices on downstream sales, as well as lower crude sales prices and sales volumes. These decreases are partially offset by higher natural gas sales volumes. Crude sales volumes in 2018 included crude purchases to fulfill certain sales commitments. The increase in 2019 natural gas volumes resulted from additional excess pipeline capacity in the Delaware Basin we utilized to purchase natural gas at depressed Delaware Basin pricing and transport to sales points outside the Basin. Related commodity management costs and expenses decreased $13 million and are discussed below.

27

Cost and operating expense and operating income (loss) analysis

	Three months ended June 30,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change		Per Boe Expense
	2019		2018						2019	2018
	(Millions)
Costs and expenses:
Depreciation, depletion and amortization	$	221	$	197	$	(24)	(12)	%	$15.24	$17.31
Lease and facility operating	94		59		(35)		(59)	%	$6.50	$5.20
Gathering, processing and transportation	40		20		(20)		(100)	%	$2.78	$1.79
Taxes other than income	43		41		(2)		(5)	%	$2.95	$3.67
Exploration	24		17		(7)		(41)	%
General and administrative:
General and administrative expenses	40		34		(6)		(18)	%	$2.73	$3.06
Equity-based compensation	8		10		2		20	%	$0.56	$0.83
Total general and administrative	48		44		(4)		(9)	%	$3.29	$3.89
Commodity management	41		54		13		24	%
Other—net	3		1		(2)		(200)	%
Total costs and expenses	$	514	$	433	$	(81)	(19)	%
Operating income (loss)	$	181	$	(3)	$	184	NM

__________

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

Significant variances in our costs and expenses are comprised of the following:

•$24 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $2.07 per Boe decrease in rate which was impacted by higher estimated proved reserves as compared to June 30, 2018 primarily due to a higher 12-month average price and favorable technical revisions in the Willistion Basin. The decrease in rate was also a result of the addition of new wells in the Williston Basin with lower relative cost per Boe.

•$35 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs.

•$20 million increase in gathering, processing and transportation primarily due to growth in production volumes and the impact of new or modified contracts in the Delaware and Williston Basins.

•$7 million increase in exploration expense relates to higher unproved leasehold amortization in 2019.

•$13 million decrease in commodity management expenses is primarily due to depressed Delaware Basin pricing on physical natural gas cost of sales and lower crude oil purchase volumes. These decreases were partially offset by higher natural gas purchase volumes as discussed above.

28

Results below operating income (loss)

	Three months ended June 30,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2019		2018
	(Millions)
Operating income (loss)	$	181	$	(3)	$	184	NM
Interest expense	(40)		(39)		(1)		(3)	%
Loss on extinguishment of debt	—		(71)		71		100	%
Gain on equity method investment transaction	247		—		247		NM
Investment income and other	1		1		—		—	%
Income (loss) from continuing operations before income     taxes	389		(112)		501		NM
Provision (benefit) for income taxes	84		(33)		(117)		NM
Income (loss) from continuing operations	305		(79)		384		NM
Loss from discontinued operations	—		(2)		2		100	%
Net income (loss)	$	305	$	(81)	386		NM

__________

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

In the second-quarter of 2018, we used proceeds form the San Juan Gallup disposition and proceeds from the issuance of $500 million Senior Notes due in 2026 to retire $921 million aggregate principal amount of our Senior Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $71 million in second-quarter 2018.

During the second quarter of 2019, we recorded a gain related to our equity method investment in the Oryx pipeline. See Note 4 of Notes to Consolidated Financial Statements for detail of this transaction.

Provision for income taxes for the three months ended June 30, 2019 compared to benefit for income taxes for the same period for 2018. See Note 7 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

29

Six Month-Over-Six Month Results of Operations

Revenue analysis 

	Six months ended June 30,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2019		2018
	(Millions)
Revenues:
Oil sales	$	960	$	828	$	132	16	%
Natural gas sales	41		33		8		24	%
Natural gas liquid sales	64		66		(2)		(3)	%
Total product revenues	1,065		927		138		15	%
Net loss on derivatives	(129)		(223)		94		42	%
Commodity management	117		100		17		17	%
Other	1		—		1		NM
Total revenues	$	1,054	$	804	$	250	31	%

__________

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:

•$132 million increase in oil sales reflects $267 million related to higher production sales volumes offset by $135 million related to lower sales prices for the six months ended June 30, 2019 compared to 2018. The Delaware Basin volumes were 45.4 MBbls per day compared to 36.5 MBbls per day for the six months ended June 30, 2019 and 2018, respectively. The Williston Basin volumes were 51.6 MBbls per day compared to 36.8 MBbls per day for the six months ended June 30, 2019 and 2018, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for the six months ended June 30, 2019 and 2018:

	Six months ended June 30,
	2019		2018
Oil sales (per barrel)	$	54.71	$	62.42
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	(1.50)		(10.78)
Oil net price including derivative settlements (per barrel)	$	53.21	$	51.64
Oil production sales volumes (MBbls)	17,552		13,271
Per day oil production sales volumes (MBbls/d)	97.0		73.3

__________

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

30

•$8 million increase in natural gas sales reflects $14 million in higher production sales volumes partially offset by $6 million related to lower sales prices for the six months ended June 30, 2019 compared to 2018. The increase in our production sales volumes primarily relates to our Delaware Basin which had production volumes of 168.7 MMcf per day compared to 119.0 MMcf per day for the six months ended June 30, 2019 compared to 2018, respectively. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for the six months ended June 30, 2019 and 2018:

	Six months ended June 30,
	2019		2018
Natural gas sales (per Mcf)	$	1.12	$	1.27
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)	0.65		0.58
Natural gas net price including derivative settlements (per Mcf)	$	1.77	$	1.85
Natural gas production sales volumes (MMcf)	36,947		25,763
Per day natural gas production sales volumes (MMcf/d)	204.1		142.3

__________

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

•$2 million decrease in natural gas liquids sales primarily reflects $39 million related to lower sales prices offset by $37 million related to higher production sales volumes for the six months ended June 30, 2019 compared to 2018. The primary increase in natural gas liquids production volumes was in the Delaware Basin, the volumes were 20.8 MBbls per day compared to 12.6 MBbls per day for the six months ended June 30, 2019 and 2018, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for the six months ended June 30, 2019 and 2018:

	Six months ended June 30,
	2019		2018
NGL sales (per barrel)	$	13.29	$	21.47
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	—		(1.46)
NGL net price including derivative settlements (per barrel)	$	13.29	$	20.01
NGL production sales volumes (MBbls)	4,781		3,053
Per day NGL production sales volumes (MBbls/d)	26.4		16.9

__________

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

•$94 million favorable change in net gain (loss) on derivatives primarily reflects favorable change in crude oil derivatives which was a result of gains in 2019 due to decreases in 2019 of forward commodity prices relative to our hedge positions as opposed to losses in 2018 due to increases in 2018 of forward commodity prices relative to our hedge position at that time. Settlements to be paid on derivatives totaled $1 million and $133 million for the six months ended June 30, 2019 and 2018, respectively.

•$17 million increase in commodity management revenues primarily due to higher natural gas sales volumes. The increase in 2019 natural gas volumes resulted from additional excess pipeline capacity in the Delaware Basin we utilized to purchase natural gas at depressed Delaware Basin pricing and transport to sales points outside the Basin. Related commodity management costs and expenses decreased $3 million and are discussed below.

31

Cost and operating expense and operating income (loss) analysis

	Six months ended June 30,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change		Per Boe Expense
	2019		2018						2019	2018
	(Millions)
Costs and expenses:
Depreciation, depletion and amortization	$	440	$	358	$	(82)	(23)	%	$15.46	$17.34
Lease and facility operating	180		114		(66)		(58)	%	$6.32	$5.55
Gathering, processing and transportation	82		38		(44)		(116)	%	$2.88	$1.85
Taxes other than income	82		71		(11)		(15)	%	$2.87	$3.46
Exploration	48		36		(12)		(33)	%
General and administrative:
General and administrative expenses	79		70		(9)		(13)	%	$2.77	$3.41
Equity-based compensation	16		17		1		6	%	$0.56	$0.82
Total general and administrative	95		87		(8)		(9)	%	$3.33	$4.23
Commodity management	90		93		3		3	%
Other—net	5		4		(1)		(25)	%
Total costs and expenses	$	1,022	$	801	$	(221)	(28)	%
Operating income	$	32	$	3	$	29	NM

__________

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

Significant variances in our costs and expenses are comprised of the following:

•$82 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $1.88 per Boe decrease in rate which was impacted by higher estimated reserves as compared to June 30, 2018 due to a higher 12-month average price and favorable technical revisions in the Williston Basin. The decrease in rate was also a result of the addition of new wells with lower relative cost per Boe.

•$66 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs.

•$44 million increase in gathering, processing and transportation is due to growth in production volumes and the impact of new or modified contracts in the Delaware and Williston Basins.

•$11 million increase in taxes other than income related to increased product revenues, previously discussed.

•$12 million increase in exploration expense relates to higher unproved leasehold amortization in 2019.

•$8 million increase in general and administrative expenses for the six months ended June 30, 2019 compared to 2018. Our general and administrative expenses per BOE decreased to an average $3.33 for the six months ended June 30, 2019 compared to $4.23 for the same period in 2018.

•$3 million decrease in commodity management expenses is primarily due to depressed Delaware Basin pricing on physical natural gas cost of sales and lower average prices for crude oil. These decreases are substantially offset by higher natural gas purchase volumes as discussed above.

32

Results below operating income (loss)

	Six months ended June 30,				Favorable (Unfavorable) $ Change		Favorable (Unfavorable) % Change
	2019		2018
	(Millions)
Operating income	$	32	$	3	$	29	NM
Interest expense	(81)		(85)		4		5	%
Loss on extinguishment of debt	—		(71)		71		100	%
Gains on equity method investment transactions	373		—		373		NM
Investment income (loss) and other	3		—		3		NM
Income (loss) from continuing operations before income taxes	327		(153)		480		NM
Provision (benefit) for income taxes	70		(48)		(118)		NM
Income (loss) from continuing operations	257		(105)		362		NM
Loss from discontinued operations	—		(91)		91		100	%
Net income (loss)	$	257	$	(196)	453		NM

__________

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

The decrease in interest expense primarily relates to lower level of debt outstanding in 2019 compared to 2018.

In the second-quarter of 2018, we used proceeds form the San Juan Gallup disposition and proceeds from the issuance of $500 million Senior Notes due in 2026 to retire $921 million aggregate principal amount of our Senior Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $71 million in second-quarter 2018.

Gains on equity method investment transactions in 2019 related to the sales of our equity interest in the Whitewater natural gas pipeline and a distribution received related to our 25 percent equity interest in the Oryx pipeline. See Note 4 of Notes to Consolidated Financial Statements for details of these sales.

Provision for income taxes for the six months ended June 30, 2019 compared to benefit for income taxes for the same period for 2018. See Note 7 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for 2019 and 2018.

Loss from discontinued operations in 2018 included a $147 million pretax loss on the sale of our San Juan Gallup operations which was sold in the first quarter of 2018. See Note 2 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview and Liquidity

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

We note the following assumptions for 2019 capital expenditures:

•our planned capital expenditures for full-year 2019, excluding acquisitions, are estimated to be approximately $1.1 billion to $1.275 billion of which $1.050 billion to $1.175 billion relates to drilling and completions, including facilities. As of June 30, 2019, we have incurred $587 million of drilling and completion capital expenditures including facilities; and

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

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

33

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

•lower than anticipated proceeds from asset sales;

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

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

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

Credit Facility

Our Credit Facility, as amended, includes total commitments of $1.5 billion on a $2.1 billion Borrowing Base with a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million (see Note 6 of Notes to Consolidated Financial Statements). Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. For additional information regarding the terms of our Credit Facility see Note 9 of Notes to Consolidated Financial Statements on our Annual Report on Form 10-K for the year ended December 31, 2018. As of June 30, 2019, WPX had no borrowings outstanding and $42 million of letters of credit issued under the Credit Facility and we were in compliance with our covenants under the credit agreement. Our unused borrowing availability was $1,458 million as of June 30, 2019. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended.

Commodity Price Risk Management

To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 11 of Notes to Consolidated Financial Statements). We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. The following table sets forth, as of the date of this filing, the derivative notional volumes of the net (long) short positions for the remainder of 2019 and 2020 that are economic hedges of our production volumes:

Crude Oil	Jul - Dec 2019			2020
	Volume (Bbls/d)	Weighted Average Price ($/Bbl)		Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Fixed Price Swaps—WTI(a)	60,500	$	55.29	40,000	$	57.48
Fixed Price Calls—WTI	5,000	$	54.08	—	$	—
Fixed Price Costless Collars—WTI	8,000	$50.00 - $60.19		20,000	$53.33 - $63.48
Basis swaps—Midland/Cushing	22,000	$	(1.37)	7,486	$	(1.31)
Basis swaps—Nymex Calendar Monthly Avg Roll	16,630	$	0.11	—	$	—
Basis swaps—Magellan East Houston	1,663	$	4.63
Basis swaps—Magellan East Houston/Midland	5,652	$	6.47	—	$	—
Basis swaps—Argus LLS/Midland	1,663	$	8.60	—	$	—
Basis swaps—Magellan East Houston/Argus LLS	1,663	$	0.75	—	$	—
Basis swaps—Clearbrook	8,000	$	(3.23)	—	$	—
Basis swaps—Brent/WTI Spread	—	$	—	5,000	$	8.36

__________

(a)Average notional volumes for 2019 are 53,000 Bbls/day for third quarter and 68,000 Bbls/day for fourth quarter.

Natural Gas	Jul - Dec 2019			2020
	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)		Volume (BBtu/d)	Weighted Average Price ($/MMBtu)
Fixed Price Swaps—Henry Hub	110	$	3.07	—	$	—
Basis swaps—Permian	25	$	(0.39)	—	$	—
Basis swaps—Waha	15	$	2.94	60	$	(0.79)
Basis swaps—Houston Ship Channel	30	$	(0.09)	—	$	—

34

Sources (Uses) of Cash

	Six months ended June 30,
	2019		2018
	(Millions)
Net cash provided by (used in):
Operating activities	$	634	$	428
Investing activities	(195)		3
Financing activities	(330)		(516)
Net increase (decrease) in cash and cash equivalents and restricted cash	$	109	$	(85)

Operating activities

Net cash provided by operating activities increased for the six months ended June 30, 2019 compared to the same period in 2018 primarily due to higher production volumes in 2019 and realizations on our derivatives, partially offset by higher operating costs and lower commodity prices. Net cash provided by operating activities for the six months ended June 30, 2019 also includes the receipt of approximately $38 million related to an AMT credit refund which represents approximately half of our AMT credit carryforwards. Excluding changes in working capital, total cash provided by operating activities related to discontinued operations was approximately $45 million for the six months ended June 30, 2018. In addition, cash outflows related to Powder River Basin gathering and transportation contracts retained by WPX were $15 million and $28 million for the six months ended June 30, 2019 and 2018, respectively.

Investing activities

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

	Six months ended June 30,
	2019		2018
Cash capital expenditures for drilling and completions:
Continuing operations	$	600	$	588
Discontinued operations	—		25
Total	$	600	$	613
Capital expenditures incurred for drilling and completions:
Continuing operations	$	592	$	624
Discontinued operations	—		23
Total	$	592	$	647
Land acquisitions	$	103	$	10

Net cash provided by (used in) investing activities for the six months ended June 30, 2019 includes the proceeds from the sale of certain non-core properties and proceeds related to transactions involving our equity method investments including our 20 percent equity interest in Whitewater natural gas pipeline and our 25 percent equity interest in the Oryx pipeline (see Note 4 of Notes to Consolidated Financial Statements). Net cash provided by investing activities for the six months ended June 30, 2018 includes $648 million of net proceeds from the sale of San Juan Gallup (see Note 2 of Notes to Consolidated Financial Statements).

Financing activities

Net cash provided by (used in) financing activities for the six months ended June 30, 2019 and 2018 includes payment for shares withheld for taxes of $15 million and $12 million, respectively.

Net cash used in financing activities for the six months ended June 30, 2018 includes $986 million of payments for retirement of long-term debt, including approximately $63 million of premium partially offset by $494 million net proceeds from a debt issuance in the second quarter of 2018.

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Contractual Obligations

See Note 8 of Notes to Consolidated Financial Statements for a discussion of additional transportation commitments.

Off-Balance Sheet Financing Arrangements

We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at June 30, 2019 or at December 31, 2018. Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a divestment.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is primarily related to our debt portfolio and has not materially changed during the first six months of 2019.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of oil, natural gas and natural gas liquids as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our marketing trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Notes 10 and 11 of Notes to Consolidated Financial Statements.

An assumed increase in the forward prices used in the valuation of our crude oil and natural gas fixed price swap and option derivatives of $5.00 per Bbl and $0.25 per MMBtu would decrease our derivative valuation by approximately $125 million and $82 million at June 30, 2019 and December 31, 2018, respectively. Conversely, an assumed decrease in forward prices of $5.00 per Bbl and $0.25 per MMBtu would increase our derivative valuation by $122 and $81 million at June 30, 2019 and December 31, 2018, respectively. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production economically hedged by the derivative instruments. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from this sensitivity analysis.

We have previously disclosed the value-at-risk; however, a sensitivity analysis is predominately the disclosure used by our peers. The value-at-risk information below is included for comparative purposes to our 2018 Form 10-K disclosures.

Our portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our energy commodity purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $14 million and $141 million at June 30, 2019 and December 31, 2018, respectively.

The value at risk for derivative contracts held for nontrading purposes was $33 million at June 30, 2019 and $26 million at December 31, 2018. During the last 12 months, our value at risk for these contracts ranged from a high of $42 million to a low of $26 million. See Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2018 for additional discussion regarding our value at risk.

Item 4. Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (“Disclosure Controls”) or our internal control over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure

36

Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the first half of 2019, we implemented a major portion of a new enterprise resource planning ("ERP") accounting and reporting system in order to upgrade our technology and improve the timeliness and processing of our financial and operational information. The overall implementation will be ongoing throughout 2019 and will be substantially complete by December 31, 2019. Although the ERP functions as an integral part of our processes and system of internal controls, we concluded that, as of the end of the period covered in this report, there have been no changes that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

37

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

38

EXHIBITS

Exhibit No.	Description
2.1**	Agreement and Plan of Merger, dated as of July 13, 2015, by and among RKI Exploration & Production, LLC, WPX Energy, Inc. and Thunder Merger Sub LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
2.2**	Membership Interest Purchase Agreement by and Among WPX Energy Holdings, LLC, as Seller, WPX Energy, Inc., solely for purposes of Section 14.15, and Terra Energy Partners LLC, as Purchaser, dated February 8, 2016 (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2016)
2.3**	Purchase and Sale Agreement, dated as of January 12, 2017, by and among RKI Exploration & Production, LLC, Panther Energy Company II, LLC and CP2 Operating, LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 13, 2017)
3.1	Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
3.2	Certificate of Amendment of Amended and Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
3.3	Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 21, 2014)
3.4	Certificate of Designations for 6.25% Series A Mandatory Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
4.1	Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)
4.2	Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.3	First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.4	Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
4.5	Third Supplemental Indenture, dated as of May 23, 2018, between WPX Energy, Inc. and the Bank of New York Mellon Trust Company, N.A. as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.'s Current Report on Form 8-K filed with the SEC on May 23, 2018)
10.1	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)
10.2	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
10.3	Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
10.4	WPX Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 29, 2013) (1)
10.5	WPX Energy, Inc. Amended 2011 Employee Stock Purchase Plan (incorporated herein by reference to Appendix B to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A (File No. 001-35322) filed with the SEC on March 29, 2018) (1)

39

Exhibit No.	Description
10.6	Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011) (1)
10.7	Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.8	Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.14 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.9	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015) (1)
10.10	Form of Stock Option Agreement between WPX Energy, Inc. and Section 16 Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014) (1)
10.11	WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
10.12	WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
10.13	Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.14	Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.15	Form of 2014 Time-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.16	Form of 2014 Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.17	Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.18	Form of Performance-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.6 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.19	Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
10.20	Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)
10.21	First Amendment to the Amended and Restated Credit Agreement, dated as of July 16, 2015, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as existing Administrative Agent and existing Swingline Lender, and Wells Fargo Bank, National Association, as successor Administrative Agent and successor Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)

40

Exhibit No.	Description
10.22	Commitment Increase Agreement for Amended and Restated Credit Agreement, dated as of July 31, 2015, among WPX Energy, Inc., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, and the Issuing Banks thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on August 6, 2015)
10.23	Second Amendment to the Amended and Restated Credit Agreement, dated as of March 18, 2016, by and among WPX Energy, Inc., as the borrower thereunder, the financial institutions party thereto from time to time, as lenders, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 22, 2016)
10.24	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
10.25	Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and CEO (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 16, 2016) (1)
10.26	Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018) (1)
10.27	Amended and Restated WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018) (1)
10.28	Purchase and Sale Agreement by and Among WPX Energy Production, LLC and Enduring Resources IV, LLC dated January 30, 2018 (incorporated by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 5, 2018)
10.29	WPX Energy, Inc. 2013 Incentive Plan, as amended (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
10.30	Form of Amended and Restated Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
10.31	Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
10.32	Amendment No. 3 to the WPX Energy, Inc. 2013 Incentive Plan (incorporated by reference to Appendix A to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A (File No. 001-35322) filed with the SEC on March 29, 2018)
10.33	Second Amendment to the Second Amended and Restated Credit Agreement and First Amendment to Guaranty and Collateral Agreement dated April 17, 2018, by and among the Company and certain of its wholly-owned subsidiaries signatory thereto, Wells Fargo Bank, National Association, as lender, Swingline Lender and Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on April 20, 2018)
10.34	Form of Amendment to Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.40 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)(1)
10.35	Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (Incorporated by reference to Exhibit 10.35 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2018)
10.36	Third Amendment to the Second Amended and Restated Credit Agreement dated April 22, 2019, by and among the Company and certain of its wholly-owned subsidiaries signatory thereto, Wells Fargo Bank, National Association, as lender, Swingline Lender and Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on April 23, 2019)
10.37*	Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (1)
10.38*	Form of Restricted Stock Unit Award Agreement between WPX Energy, Inc. and Non-Employee Directors(1)
10.39*	Form of amended Exhibit B to Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers(1)

41

Exhibit No.	Description
31.1*	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the inline XBRL document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

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

42

SIGNATURE

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

WPX Energy, Inc. (Registrant)
By:	/s/ Stephen L. Faulkner
	Stephen L. Faulkner Controller (Principal Accounting Officer)

Date: August 6, 2019

43

EX-10.37

Exhibit 10.37

[Grant Date]

TO:  [Participant Name]

FROM: Richard E. Muncrief

SUBJECT: 2019Restricted Stock Award

For your service on the WPX Energy Board of Directors, you will receive part of your annual compensation as a restricted stock award. This award, which is subject to the 2019 Restricted Stock Award Agreement (the “Agreement), is granted and subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan, as amended and restated from time to time, and the Agreement.

Subject to all of the terms of the Agreement, you will become entitled to payment of this award if you are an active director of the Company one year after the date on which this award is made.

If you have any questions about this award, you may contact a dedicated Fidelity Investments Executive Services Representative at 1-800-823-0217.

2019 RESTRICTED STOCK AWARD AGREEMENT

THIS RESTRICTED STOCK AWARD AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Award (“Restricted Stock”) referred to in the 2019 Restricted Stock Award Letter delivered in hard copy or electronically to Participant (“2019 Award Letter”), is by and between WPX ENERGY, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1. Grant of Restricted Stock. Subject to the terms and conditions of WPX Energy, Inc. 2013 Incentive Plan, as amended and restated from time to time or any successor plan (the “Plan”), this Agreement, and the 2019 Award Letter, the Company hereby grants an award (the “Award”) to the Participant of [Number of Shares Granted] shares of Restricted Stock effective [Grant Date] (the “Effective Date”). The Award gives the Participant the right to receive the number ofshares of the Common Stock of the Company equal to the number of shares of Restricted Stock shown in the prior sentence, subject to adjustment under the terms of this Agreement. These shares are referred to in this Agreement as the “Shares.” From and after the Effective Date, the Participant shall have all rights as a stockholder of the Company with respect to the Shares. Any dividends paid on the Shares during the vesting period will be accumulated and paid to Participant upon the Maturity Date.

2. Incorporation of Plan and Acceptance of Documents. The Plan is hereby incorporated herein by reference and all capitalized terms used herein which are not defined in this Agreement shall have the respective meanings set forth in the Plan. The Participant acknowledges that he or she has received a copy of, or has online access to, the Plan and hereby automatically accepts the Restricted Stock subject to all the terms and provisions of the Plan and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the prospectus and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3. Board Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Board, its delegates, or agents, upon any questions or other matters arising under the Plan or this Agreement.

4. Vesting of Shares.

(a) The Award shall not be vested as of the Effective Date and shall be forfeitable unless and until otherwise vested pursuant to the terms of this Agreement. Except as otherwise provided in Subparagraph 4(b) and 4(c) below, the Shares shall become vested and no longer subject to forfeiture on the one-year anniversary of the Effective Date (the “Maturity Date”), but only if the Participant remains a Non-Management Director of the Company through the Maturity Date.

2

(b) If the Participant dies prior to the Maturity Date while serving as a Non-Management Director of the Company, the Participant shall vest in all Shares at the time of such death.

(c) If the Participant experiences a Separation from Service prior to the final Maturity Date and within two years following a Change in Control, the Participant shall vest in all unvested Shares of Restricted Stock upon such Separation from Service. Notwithstanding the foregoing, if the Separation from Service results from an involuntary removal from the Board for cause, as determined by a vote of a majority of the Board of Directors, or a voluntary resignation, then the Participant shall not vest in unvested Shares of Restricted Stock upon such Separation from Service.

5. Definitions. As used in this Agreement, the following terms shall have the definitions set forth below.

(a)“Affiliate” means all persons with whom the Company would be considered a single employer under Section 414(b) of the Code, and all persons with whom such person would be considered a single employer under Section 414(c) of the Code.

(b)“Separation from Service” means a Participant’s termination of services as a Director of the Company. The term “Separation from Service” shall be applied in conformance with Section 1.409A-1(h) of the Treasury Regulations. For the limited purpose of determining whether a Separation from Service has occurred, the term “Company” shall include the Company and all persons with whom the Company would be considered a single employer under Sections 414(b) and 414(c) of the Code, except that in applying Sections 1563(a)(1), (2), and (3) of the Code for purposes of determining a controlled group of corporations under Section 414(b) of the Code, the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Section 1563(a)(1), (2), and (3), and in applying Section 1.414(c)-2 of the Treasury Regulations for purposes of determining trades or businesses that are under common control for purposes of Section 414(c) of the Code, “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Section 1.414(c)-2 of the Treasury Regulations.

6. Other Provisions.

(a) The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

3

(b) The Participant agrees and understands that, upon receipt of Shares under this Agreement, stock certificates (or other indicia of ownership) issued may be held as collateral for monies he/she owes to Company or any of its Affiliates, including but not limited to personal loan(s) or Company credit card debt.

(c) Except as provided in Subparagraphs 4(b) and 4(c), in the event that the Participant experiences a Separation from Service prior to the Participant’s becoming vested in the Shares under this Agreement, the Award and the Shares subject to this Agreement shall be immediately forfeited and returned to the Company without payment of additional consideration.

(d) Restricted Stock, Shares and the Participant’s interest in Restricted Stock and Shares may not be sold, assigned, transferred, pledged or otherwise disposed of or encumbered at any time prior to the Shares becoming vested under this Agreement.

(e) The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Board, its delegates or agents.

(f) Nothing in this Agreement or the Plan shall confer upon the Participant the right to continue to serve as a director of the Company.

(g) The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Board or Committee to allow a Domestic Relations Order with respect to this Award.

7. Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to WPX Energy, Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner. To direct the sale of any Shares issued under this Agreement, the Participant must contact the plan administrator.

8. Section 83(b) Election for Restricted Stock Award; Tax Consultation. Under Section 83(a) of the Code, the Participant will generally be taxed on the Shares subject to this Award on the date such Shares vest and the forfeiture restrictions lapse, based on their fair market value on such date, at ordinary income rates. For this purpose, the term “forfeiture restrictions” means the right of the Company to receive back any Shares subject to this Award that have not vested upon a Separation from Service. Under Section 83(b) of the Code, the Participant may elect to be taxed on the Shares on the Effective Date, based upon their fair market value on such date, at ordinary income rates, rather than when and as the Shares that have not vested cease to be subject to the forfeiture restrictions. If the Participant elects to accelerate the date on which he or she is taxed on the Shares under Section 83(b), an election (an “83(b) Election”) to such effect must be filed with the Internal Revenue Service within 30 days from the Effective Date.

4

The Participant understands he or she will incur tax consequences as a result of acquisition or disposition of the Shares. The foregoing is only a summary of the federal income tax laws that apply to the Shares under this Agreement and does not purport to be complete. The actual tax consequences of receiving or disposing of the Shares are complicated and depend, in part, on the Participant’s specific situation and may also depend on the resolution of currently uncertain tax law and other variables not within the control of the Company. Therefore, the Participant agrees to consult with any tax consultants deemed advisable in connection with the acquisition of the Shares and acknowledges that he or she is not relying, and will not rely, on the Company for any tax advice.

If the Participant determines to make an 83(b) Election, the Participant must file such an election with the Internal Revenue Service within the 30-day period after the Effective Date, to deliver to the Company a signed copy of the 83(b) Election, and to file an additional copy of such election form with the Participant’s federal income tax return for the calendar year in which the Effective Date occurs.

        WPX ENERGY, INC.

         By:_________________________

Richard E. Muncrief

        Chairman and CEO

Participant: [Participant Name]

5

EX-10.38

Exhibit 10.38

                  [Grant Date]

TO:  [Participant Name]

FROM: Richard E. Muncrief

SUBJECT: 2019 Restricted Stock Unit Award

You have elected to receive part of your WPX Energy, Inc. Board of Directors annual compensation in the form of a restricted stock unit award. This award, which is subject to the 2018 Restricted Stock Unit Agreement between WPX Energy, Inc. and you (the “Agreement”), is granted and subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan, as amended and restated from time to time, and the WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, as amended and restated from time to time.

Subject to all of the terms of the Agreement, you will become entitled to payment of the shares represented by this award within 90 days of your termination of service as a member of the WPX Energy, Inc. Board of Directors if you continue to serve on the Board for at least one year after the date on which this award is made.

If you have any questions about this award, you may contact a dedicated Prudential Representative at 1-800-824-0040.

WPX ENERGY, INC.

2019 RESTRICTED STOCK UNIT AGREEMENT

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Units (“Restricted Stock Units” or “RSUs”) referred to in the 2019 Restricted Stock Unit Award Letter delivered in hard copy or electronically to the Participant (the “2019 Award Letter”), is by and between WPX ENERGY, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1. Grant of RSUs. Subject to the terms and conditions of the WPX Energy, Inc. 2013 Incentive Plan, as amended and restated from time to time (the “Incentive Plan”), the WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, as amended and restated from time to time (the “Deferred Compensation Plan”), this Agreement, and the 2019 Award Letter, the Company hereby grants an award (the “Award”) to the Participant of [Number of Awards Granted] RSUs effective [Grant Date] (the “Effective Date”). The Award gives the Participant the opportunity to earn the right to receive the number ofshares of the Common Stock of the Company equal to the number of RSUs shown in the prior sentence. These shares are referred to in this Agreement as the “Shares.” Until the Participant both becomes vested in the RSUs awarded pursuant to this Agreement under the terms of Paragraph 4 and is paid the Shares under the terms of Paragraph 5, the Participant shall have no rights as a stockholder of the Company with respect to the Shares.

2. Incorporation of Incentive Plan and Acceptance of Documents. The Incentive Plan is incorporated by reference, and all capitalized terms used herein which are not defined in this Agreement or in the attached Appendix A shall have the respective meanings set forth in the Incentive Plan. The Participant acknowledges that he or she has received a copy of, or has online access to, the Incentive Plan and the Deferred Compensation Plan and hereby automatically accepts the RSUs awarded pursuant to this Agreement subject to all the terms and provisions of the Incentive Plan, the Deferred Compensation Plan, and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the prospectus for the Incentive Plan and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3. Committee Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Committee, its delegates or agents, upon any questions or other matters arising under the Incentive Plan or this Agreement.

4. Vesting; Legally Binding Rights.

(a) Notwithstanding any other provision of this Agreement, the Participant shall not be entitled to any payment of Shares under this Agreement unless and until such Participant

2

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

(b) Except as otherwise provided in Subparagraph 4(c) and 4(d) below, the Participant shall vest in the RSUs awarded pursuant to this Agreement upon the Participant’s Separation from Service, if and only if such Separation from Service occurs on or after the one-year anniversary of the Effective Date. The date of the Participant’s Separation from Service that occurs on or after the one-year anniversary of the Effective Date shall be referred to herein as the “Maturity Date.”

(c) If a Participant dies prior to the Maturity Date while a Director of the Company, the Participant shall vest in the RSUs awarded pursuant to this Agreement at the time of such death.

(d) If the Participant experiences a Separation from Service prior to the final Maturity Date and within two years following a Change in Control, the Participant shall vest in all unvested Shares of Restricted Stock upon such Separation from Service. Notwithstanding the foregoing, if the Separation from Service results from an involuntary removal from the Board for cause, as determined by a vote of a majority of the Board of Directors, or a voluntary resignation, then the Participant shall not vest in unvested Shares of Restricted Stock upon such Separation from Service.

5. Payment of Shares.

(a) RSUs awarded pursuant to this Agreement that have become vested pursuant to Subparagraph 4(b) above shall be settled by delivery of the Shares to the Participant within the 90-day period beginning on the Maturity Date.

(b)  RSUs awarded pursuant to this Agreement that have become vested pursuant to Subparagraph 4(c) above shall be settled by delivery of the Shares to the Participant’s beneficiary within the 90-day period beginning on the date of the Participant’s death.

(c) Upon delivery of the Shares pursuant to Subparagraphs 5(a) or 5(b) above, the RSUs awarded pursuant to this Agreement shall be cancelled. Shares that become payable under this Agreement will be paid by the Company by the delivery to the Participant, or to his or her beneficiary in the case of the Participant’s death, of one or more certificates (or other indicia of ownership) representing shares of Common Stock equal in number to the number of Shares otherwise payable under this Agreement. Notwithstanding the foregoing, to the extent permitted by Section 409A of the Code and the guidance issued by the Internal Revenue Service thereunder, if federal employment or other taxes become due when the Participant becomes entitled to payment of Shares, the number of Shares necessary to cover minimum statutory withholding requirements may, in the discretion of the Company, be used to satisfy such requirements upon such entitlement.

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6. Other Provisions.

(a) The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice, or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives.

(b) Except as provided in Subparagraphs 4(c) and 4(d) above, in the event that the Participant experiences a Separation from Service prior to the Participant’s becoming vested in the RSUs awarded pursuant to this Agreement, such RSUs and any right to the Shares issuable hereunder shall be forfeited.

(c) RSUs, Shares, and the Participant’s interest in RSUs and Shares may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered at any time prior to both (i) the Participant’s becoming vested in such RSUs and (ii) payment of such Shares under this Agreement.

(d) If the Participant at any time forfeits any or all of the RSUs awarded pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in such RSUs and in the Shares issuable hereunder shall terminate upon forfeiture without payment of consideration.

(e) The Committee shall determine whether an event has occurred resulting in the forfeiture of the RSUs awarded pursuant to this Agreement and any right to the Shares issuable hereunder, in accordance with this Agreement, and all determinations of the Committee shall be final and conclusive.

(f) With respect to the right to receive payment of the Shares under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

(g) The obligations of the Company under this Agreement are unfunded and unsecured. The Participant shall have the status of a general creditor of the Company with respect to amounts due, if any, under this Agreement.

(h) The parties to this Agreement intend that this Agreement will satisfy the applicable requirements of Section 409A of the Code and recognize that it may be necessary to modify this Agreement, the Incentive Plan and/or the Deferred Compensation Plan to reflect guidance under Section 409A of the Code issued by the Internal Revenue Service. The Participant agrees that the Committee shall have sole discretion in determining (i) whether any such modification is desirable or appropriate and (ii) the terms of any such modification.

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(i) The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Committee, its delegates or agents.

(j) Nothing in this Agreement, the Incentive Plan or the Deferred Compensation Plan shall interfere with or limit in any way the right of the Company to terminate the Participant’s services as a Director of the Company at any time, nor confer upon the Participant the right to continued service as a Director of the Company.

(k) The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Committee to allow a domestic relations order with respect to this Award.

7. Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to WPX Energy, Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner.

8. Tax Consultation. The Participant understands he or she will incur tax consequences as a result of acquisition or disposition of the Shares. The Participant agrees to consult with any tax consultants deemed advisable in connection with the acquisition of the Shares and acknowledges that he or she is not relying, and will not rely, on the Company for any tax advice.

        WPX ENERGY, INC.

         By: _________________________

Richard E. Muncrief

Chairman and CEO

Participant: [Participant Name]

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APPDENDIX A

DEFINITIONS

“Affiliate” means all persons with whom the Company would be considered a single employer under Sections 414(b) and 414(c) of the Code.

“Separation from Service” means a Participant’s termination of services as a Director of the Company. The term “Separation from Service” shall be applied in conformance with Section 1.409A-1(h) of the Treasury Regulations. For the limited purpose of determining whether a Separation from Service has occurred, the term “Company” shall include the Company and all persons with whom the Company would be considered a single employer under Sections 414(b) and 414(c) of the Code, except that in applying Sections 1563(a)(1), (2), and (3) of the Code for purposes of determining a controlled group of corporations under Section 414(b) of the Code, the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Section 1563(a)(1), (2), and (3), and in applying Section 1.414(c)-2 of the Treasury Regulations for purposes of determining trades or businesses that are under common control for purposes of Section 414(c) of the Code, “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Section 1.414(c)-2 of the Treasury Regulations.

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EX-10.39

Exhibit 10.39

APPENDIX B

DETERMINATION OF TSR RANKING

As of the Effective Date, the Committee has established a peer group of companies for the purpose of determining the Company’s relative TSR ranking for the Performance Period or the CIC period.

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

Company TSR Ranking Within the Peer Group	Percentage of the Target Number of Shares
1st	200.0%
2nd	200.0%
3rd	187.5%
4th	175.0%
5th	150.0%
6th	125.0%
Target Peer Group Ranking 7th	100.0%
8th	76.7%
9th	53.3%
10th	30.0%
11th	0.0%
12th	0.0%
13th	0.0%
14th	0.0%

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Richard E. Muncrief, certify that:

1.I have reviewed this quarterly report on Form 10-Q of WPX Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2019

/s/ Richard E. Muncrief

Richard E. Muncrief
Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, J. Kevin Vann, certify that:

1.I have reviewed this quarterly report on Form 10-Q of WPX Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2019

/s/ J. Kevin Vann

J. Kevin Vann
Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of WPX Energy, Inc. (the “Company”) on Form 10-Q for the period ended June 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Richard E. Muncrief

Richard E. Muncrief
Chief Executive Officer

August 6, 2019

/s/ J. Kevin Vann

J. Kevin Vann
Executive Vice President and Chief Financial Officer

August 6, 2019

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 05, 2019
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-35322
Entity Registrant Name	WPX Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	45-1836028
Entity Address, Address Line One	3500 One Williams Center
Entity Address, City or Town	Tulsa,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74172-0172
City Area Code	855
Local Phone Number	979-2012
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	WPX
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		422,395,102
Document Fiscal Period Focus	Q2
Entity Central Index Key	0001518832
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Amendment Flag	false

XML

Consolidated Balance Sheet (Unaudited) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Current assets:
Cash and Cash Equivalents, at Carrying Value		$ 109	$ 3
Accounts receivable, net of allowance		505	405
Derivative assets, current		81	174
Inventories		45	48
Assets classified as held for sale		0	79
Other		34	30
Total current assets		774	739
Long-term Investments		55	167
Properties and equipment (successful efforts method of accounting)		10,713	9,949
Less—accumulated depreciation, depletion and amortization		(3,158)	(2,683)
Properties and equipment, net		7,555	7,266
Derivative assets, noncurrent		42	4
Other noncurrent assets		127	27
Total assets		8,553	8,203
Current liabilities:
Accounts payable		721	514
Accrued and other current liabilities		225	178
Derivative liabilities, current		80	23
Total current liabilities		1,026	715
Deferred income taxes		270	201
Long-term debt, net	[1]	2,157	2,485
Derivative liabilities, noncurrent		29	14
Other noncurrent liabilities		510	487
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding)		0	0
Common stock (2 billion shares authorized at $0.01 par value; 422.3 million and 420.6 million shares issued and outstanding at June 30, 2019 and December 31, 2018)		4	4
Additional paid-in-capital		7,737	7,734
Accumulated deficit		(3,180)	(3,437)
Total stockholders’ equity		4,561	4,301
Total liabilities and equity		$ 8,553	$ 8,203

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

XML

Consolidated Balance Sheet (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued and outstanding	422,300,000	420,600,000

XML

Consolidated Statement of Operations (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues:
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		$ 78	$ (154)	$ (129)	$ (223)
Other Income		1	0	1	0
Total revenues		695	430	1,054	804
Costs and expenses:
Depreciation, depletion and amortization		221	197	440	358
Lease and facility operating		94	59	180	114
Taxes other than income		43	41	82	71
Exploration (Note 4)		24	17	48	36
General and administrative (including equity-based compensation of $8 million, $10 million, $16 million and $17 million for the respective periods)		48	44	95	87
Other—net		3	1	5	4
Total costs and expenses		514	433	1,022	801
Operating income (loss)		181	(3)	32	3
Interest expense		(40)	(39)	(81)	(85)
Gain (Loss) on Extinguishment of Debt		0	(71)	0	(71)
Gains on equity method investment transactions		247	0	373	0
Investment income (loss) and other		1	1	3	0
Income (loss) from continuing operations before income taxes		389	(112)	327	(153)
Provision (benefit) for income taxes		84	(33)	70	(48)
Income (loss) from continuing operations		305	(79)	257	(105)
Income (loss) from discontinued operations		0	(2)	0	(91)
Net income (loss)		305	(81)	257	(196)
Preferred Stock Dividends, Income Statement Impact		0	4	0	8
Net income (loss) available to WPX Energy, Inc. common stockholders		305	(85)	257	(204)
Amounts available to WPX Energy, Inc. common stockholders:
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share		305	(83)	257	(113)
Income (loss) from discontinued operations		$ 0	$ (2)	$ 0	$ (91)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share		$ 0.72	$ (0.21)	$ 0.61	$ (0.28)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic and Diluted Share		0	0	0	(0.23)
Earnings Per Share, Basic and Diluted, Total		$ 0.72	$ (0.21)	$ 0.61	$ (0.51)
Weighted Average Number of Shares Outstanding, Basic		422.5	400.0	421.8	399.3
Weighted Average Number of Shares Outstanding, Diluted	[1]	423.5	400.0	423.6	399.3
Oil and Condensate [Member]
Revenues:
Revenue from Customers		$ 511	$ 468	$ 960	$ 828
Natural Gas, Production [Member]
Revenues:
Revenue from Customers		16	16	41	33
Natural Gas Liquids [Member]
Revenues:
Revenue from Customers		31	36	64	66
Oil and Gas [Member]
Revenues:
Revenue from Customers		558	520	1,065	927
Oil and Gas, Refining and Marketing [Member]
Revenues:
Revenue from Customers		58	64	117	100
Costs and expenses:
Cost of Goods and Services Sold		41	54	90	93
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Costs and expenses:
Cost of Goods and Services Sold		$ 40	$ 20	$ 82	$ 38

[1] Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application, in 2018, of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units and awards. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows: Three months
ended June 30,Six months
ended June 30,2019 2018 2019 2018 (Millions) Weighted-average nonvested restricted stock units and awards — 2.9 — 3.0 Weighted-average stock options— 0.2 — 0.2  Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock Not
Applicable 19.8 Not
Applicable 19.8  Nonvested restricted stock units and awards antidilutive under the treasury stock method 2.6 0.7 2.6 0.7 

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Consolidated Statement of Operations (parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Non-cash equity-based compensation expense	$ 8	$ 10	$ 16	$ 17

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Consolidated Statement of Changes in Equity (Unaudited) - USD ($) $ in Millions	Total	Preferred Stock	Common Stock	Additional Paid-In- Capital	Accumulated Deficit
Beginning Balance at Dec. 31, 2017	$ 4,127	$ 232	$ 4	$ 7,479	$ (3,588)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(196)				(196)
Stock-based compensation, net of tax impact	12			12
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings	8			8
Ending Balance at Jun. 30, 2018	3,935	232	4	7,483	(3,784)
Beginning Balance at Mar. 31, 2018	4,006	232	4	7,473	(3,703)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(81)				(81)
Stock-based compensation, net of tax impact	14			14
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings	4			4
Ending Balance at Jun. 30, 2018	3,935	232	4	7,483	(3,784)
Beginning Balance at Dec. 31, 2018	4,301	0	4	7,734	(3,437)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	257				257
Stock-based compensation, net of tax impact	3			3
Ending Balance at Jun. 30, 2019	4,561	0	4	7,737	(3,180)
Beginning Balance at Mar. 31, 2019	4,248	0	4	7,729	(3,485)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	305				305
Stock-based compensation, net of tax impact	8			8
Ending Balance at Jun. 30, 2019	$ 4,561	$ 0	$ 4	$ 7,737	$ (3,180)

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Consolidated Statements of Cash Flows - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018
Operating Activities(a)
Net income (loss)		$ 257	$ (196)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation Depletion And Amortization Including Discontinued Portion		440	365
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations		69	(75)
Provision For Impairment Of Properties And Equipment Including Certain Exploration Expenses And Equity Method Investment		41	37
Gains related to equity method investment transactions		373	0
Net (gain) loss on derivatives		129	223
Net settlements related to derivatives		1	133
Amortization of stock-based awards		17	18
Gain (Loss) on Extinguishment of Debt		0	(71)
Net (gain) loss on sales of assets including discontinued operations		0	151
Cash provided by (used in) operating assets and liabilities:
Accounts receivable		(145)	(16)
Inventories		2	(11)
Other current assets		(1)	4
Accounts payable		203	73
Federal income taxes receivable		38	0
Accrued and other current liabilities		(17)	(59)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations		(15)	(28)
Other, including changes in other noncurrent assets and liabilities		(10)	4
Net cash provided by operating activities(a)	[1]	634	428
Investing Activities(a)
Capital Expenditures	[2]	(774)	(660)
Proceeds from sales of assets		590	686
Purchase of or contributions to investments		(18)	(23)
Proceeds from Equity Method Investment, Distribution, Return of Capital		7	0
Net cash provided by (used in) investing activities(a)	[1]	(195)	3
Financing Activities
Proceeds from common stock		1	5
Dividends paid on preferred stock		0	(8)
Borrowings on credit facility		1,002	303
Payments on credit facility		(1,332)	(303)
Proceeds from long-term debt		0	494
Payments for retirement of long-term debt		0	986
Taxes paid for shares withheld		(15)	(12)
Payments for debt issuance costs and credit facility amendment fees		0	10
Proceeds from (Payments for) Other Financing Activities		14	1
Net cash provided by (used in) financing activities		(330)	(516)
Net decrease in cash and cash equivalents and restricted cash		109	(85)
Cash, cash equivalents and restricted cash at beginning of period		18	201
Cash and cash equivalents and restricted cash at end of period		127	116
Increase to properties and equipment		(766)	(705)
Changes In Related Accounts Payable		$ (8)	$ 45

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

[2] (b) Increase to properties and equipment(766)(705)Changes in related accounts payable and accounts receivable(8)45 Capital expenditures(774)(660)

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Basis of Presentation and Description of Business

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Basis of Presentation and Description of Business

Description of Business and Basis of Presentation

Description of Business

Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from other third-parties in our operating areas in conjunction with the management of various commodity related contracts such as transportation.

We have sold certain operations which are reported as discontinued operations and are discussed in Note 2 of Notes to Consolidated Financial Statements.

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

Basis of Presentation

The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2018 in the Company's Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2019, results of operations for the three and six months ended June 30, 2019 and 2018, changes in equity for the three and six months ended June 30, 2019 and 2018, and cash flows for the six months ended June 30, 2019 and 2018. The Company has no element of comprehensive income (loss) other than net income (loss).

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

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

Discontinued Operations

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

Recently Adopted Accounting Standards

The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases, effective January 1, 2019. The standard requires the recognition of right of use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right of use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess:

•whether existing contracts are or contain leases;

•lease classification for any expired or existing leases;

•initial direct costs for any existing lease; and

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

See Note 9 for additional information related to our contracts that are or contain leases.

We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019. This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging

strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period.

Accounting Standards Not Yet Adopted

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

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

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Discontinued Operations (Notes)

6 Months Ended

Jun. 30, 2019

Discontinued operations [Abstract]

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

Discontinued Operations

In first-quarter 2018, we sold our properties in the San Juan Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. We believed and continue to believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and the purchaser, and the declining size of the obligations subject to the guarantee over time. As part of the divestiture, we had to determine the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018.

Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years associated with our exit from the Powder River Basin.

Summarized Results of Discontinued Operations

The following table presents the results of our discontinued operations for the six months ended June 30, 2018. For the three and six months ended June 30, 2019 and the three months ended June 30, 2018, our discontinued operations activity was minimal and therefore is not included in the table below.

	Six months ended June 30,
	2018
Total revenues	$	75
Costs and expenses:
Depreciation, depletion and amortization	$	8
Lease and facility operating	7
Gathering, processing and transportation	12
Taxes other than income	5
General and administrative	1
Exploration	3
Accretion for transportation and gathering obligations retained	3
Other—net	4
Total costs and expenses	43
Operating income	32
Loss on sale of assets	(150)
Loss from discontinued operations before income taxes	(118)
Income tax benefit	(27)
Loss from discontinued operations	$	(91)

Cash Flows Attributable to Discontinued Operations

Cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $15 million and $28 million for the six months ended June 30, 2019 and 2018, respectively. In addition, cash flows related to San Juan Gallup includes $45 million of cash provided by operating activities, excluding income taxes and changes in working capital items, and $29 million of cash capital expenditures within investing activities for the six months ended June 30, 2018.

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Earnings (Loss) Per Common Share from Continuing Operations

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

Earnings (Loss) Per Common Share from Continuing Operations

The following table summarizes the calculation of earnings per share.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions, except per-share amounts)
Income (loss) from continuing operations	$	305	$	(79)	$	257	$	(105)
Less: Dividends on preferred stock	—		4		—		8
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share	$	305	$	(83)	$	257	$	(113)
Basic weighted-average shares	422.5		400.0		421.8		399.3
Effect of dilutive securities(a)	1.0		—		1.8		—
Diluted weighted-average shares	423.5		400.0		423.6		399.3
Earnings (loss) per common share from continuing operations:
Basic	$	0.72	$	(0.21)	$	0.61	$	(0.28)
Diluted	$	0.72	$	(0.21)	$	0.61	$	(0.28)

__________

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

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
	(Millions)
Weighted-average nonvested restricted stock units and awards	—	2.9	—	3.0
Weighted-average stock options	—	0.2	—	0.2
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock	Not Applicable	19.8	Not Applicable	19.8
Nonvested restricted stock units and awards antidilutive under the treasury stock method	2.6	0.7	2.6	0.7

Stock options of approximately 0.9 million and 0.6 million that were outstanding at June 30, 2019 and 2018, respectively, have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the respective second quarter weighted-average market price of our common shares.

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Asset Sales and Exploration Expense

6 Months Ended

Jun. 30, 2019

Extractive Industries [Abstract]

Asset Sales, Exploration Expenses And Other Accruals [Text Block]

Asset Sale, Equity Method Investment Transactions and Exploration Expenses

Asset Sale

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

Equity Method Investment Transactions

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

During the second quarter of 2019, we received a distribution of approximately $357 million related to our 25 percent equity interest in the Oryx pipeline partnership after the underlying assets were sold. This transaction is subject to post-closing adjustments. The net book value of this equity method investment was approximately $110 million as of the closing date. As a result of this transaction, we recorded a gain of $247 million.

Exploration Expenses

The following table presents a summary of exploration expenses.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions)
Unproved leasehold property amortization	$	21	$	16	$	44	$	33
Geologic and geophysical costs	3		1		4		3
Total exploration expenses	$	24	$	17	$	48	$	36

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Inventories

6 Months Ended

Jun. 30, 2019

Inventory Disclosure [Abstract]

Inventories

Inventories

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

	June 30, 2019		December 31, 2018
	(Millions)
Material, supplies and other	$	41	$	46
Commodity production in transit or storage	4		2
Total inventories	$	45	$	48

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Debt and Banking Arrangements

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt and Banking Arrangements

Debt and Banking Arrangements

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

	June 30, 2019		December 31, 2018
	(Millions)
Credit facility agreement	$	—	$	330
6.000% Senior Notes due 2022	529		529
8.250% Senior Notes due 2023	500		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		500
Total long-term debt	$	2,179	$	2,509
Less: Debt issuance costs on long-term debt(a)	22		24
Total long-term debt, net(a)	$	2,157	$	2,485

__________

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

Credit Facility 

As of June 30, 2019, we had no borrowings outstanding and $42 million of letters of credit issued under the Credit Facility and we were in compliance with our financial covenants with full access to the Credit Facility.

On April 22, 2019, the Company entered into a Third Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, the Swingline Lender and each of the issuing banks party thereto (the "Credit Facility"). The Credit Facility, as amended, gives the Company the option, if certain conditions are met, to elect during any Collateral Trigger Period that scheduled redeterminations of the Borrowing Base be made annually on April 1 instead of semi-annually.

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

See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information on covenants related to our Credit Facility. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended.

Senior Notes

See our Annual Report on Form 10-K for the year ended December 31, 2018 for additional discussion related to our senior notes.

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Provision (Benefit) for Income Taxes

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes

Provision (Benefit) for Income Taxes

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

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions)
Current:
Federal	$	—	$	—	$	—	$	—
State	2		—		1		—
	2		—		1		—
Deferred:
Federal	75		(28)		63		(37)
State	7		(5)		6		(11)
	82		(33)		69		(48)
Total provision (benefit)	$	84	$	(33)	$	70	$	(48)

The effective income tax rate for the three months ended June 30, 2019, differs slightly from the federal statutory rate of 21 percent due to to the effect of state income taxes and equity-based compensation, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gain from a 2019 transaction involving an equity interest in a partnership.

The effective income tax rate for the three months ended June 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of state income taxes.

The effective income tax rate for the six months ended June 30, 2019, differs slightly from the federal statutory rate of 21 percent due to to the effect of state income taxes and equity-based compensation, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gains from the 2019 transactions involving equity interests in partnerships.

The effective income tax rate for the six months ended June 30, 2018, differs from the federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of an adjustment to state deferred taxes as a result of a decrease in the blended state income tax rate due to changes in state apportionment factors resulting from the divestment of our San Juan Basin assets.

We have recorded valuation allowances against deferred tax assets attributable primarily to certain state net operating loss (“NOL”) carryovers. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. We have not recorded a valuation allowance against our federal NOL carryover, but a valuation allowance could be required in future periods if the federal NOL carryover continues to increase or circumstances change.

The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three-year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of June 30, 2019, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015 (“RKI”). Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the acquisition.

Pursuant to our tax sharing agreement with The Williams Companies, Inc. ("Williams"), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre-spin-off period for which we continue to have exposure to audit adjustments as part of Williams. In 2017, the IRS proposed an adjustment related to our business for which a payment to Williams could be required. We, along with Williams, have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS.

As of June 30, 2019, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. Currently, we do not expect ultimate resolution of our uncertain tax position during the next 12 months.

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Contingent Liabilities

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities

Contingent Liabilities and Commitments

Contingent Liabilities

Royalty litigation

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip

condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and on September 21, 2018 the Tenth Circuit dismissed the appeal for lack of jurisdiction. On January 22, 2019, plaintiffs’ filed a petition for certiorari to the United States Supreme Court, which was denied on April 1, 2019. At this time, we believe that our royalty calculations were properly determined in accordance with the appropriate contractual arrangements and applicable laws.

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

Environmental matters

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

Matters related to Williams’ former power business

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

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. In February, 2019, settlement agreements with the Kansas and Missouri class claimants were executed. A final fairness hearing seeking the court's approval of the settlement is set for August 5, 2019. In the Wisconsin class action, defendants' motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs' motion to remand the case to the originally filed district court.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered

in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court, and the MDL Court has now remanded the case to the United States District Court for the District of Kansas. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.

Other Indemnifications

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

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

As of June 30, 2019, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

As of June 30, 2019 and December 31, 2018, the Company had accrued approximately $11 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

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

Commitments

During 2019, primarily in the second quarter, we contracted for additional oil and natural gas transportation capacity to other locations in attempts to avoid location constraints and obtain more favorable pricing differentials. This capacity is associated with projects for which the counterparties have not yet begun construction. Related minimum commitments, when construction is complete and facilities are in service, total approximately $800 million over a five to ten year period with annual demand payments, beginning in 2021, ranging from approximately $38 million to $97 million.

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Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Leases of Lessee Disclosure [Text Block]

Leases

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

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

Certain of our leases include rental payments adjusted periodically for inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. From time to time we may enter into lease contracts that commence in future periods. Lease contracts that will commence subsequent to June 30, 2019 are not significant.

The following tables include quantitative disclosures related to our leases.

	Six months ended June 30, 2019
	(Millions)
Lease Costs:
Leases recorded on the Consolidated Balance Sheet:
Operating lease cost—drilling rigs(a)	$	20
Operating lease cost—other(a)	9
Variable lease cost—drilling rigs(a)	3
Variable lease cost—other(a)	2
Short-term leases:
Drilling rigs(b)	20
Other(b)	59
Total lease cost	$	113
Other Information:
Cash paid for amount included in the measurement of lease liabilities:
Operating cash flows used for operating leases(a)	$	9
Investing cash flows used for operating leases(a)	$	20
Right-of-use assets obtained in exchange for new operating lease liabilities	$	32
Weighted-average remaining lease term (in years)	1.81 years
Weighted-average discount rate—operating leases	5		%

__________

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

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

The following tables include quantitative disclosures related to our leases as of June 30, 2019.

	Drilling Rigs		Real Estate, Compression and Other		Total Undiscounted Cash Flows
	(Millions)
Maturity of Lease Liabilities:
July 2019 through December 2019	$	20	$	10	$	30
2020	36		17		53
2021	4		10		14
2022	—		1		1
2023	—		—		—
Thereafter	—		—		—
					$	98
Current lease liabilities	$	36	$	18	$	54
Noncurrent lease liabilities	21		19		40
Total lease liabilities	$	57	$	37	$	94
Difference between undiscounted cash flows and discounted cash flows					$	4
Total right-of-use assets on Consolidated Balance Sheet					$	94

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Fair Value Measurements

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

	June 30, 2019								December 31, 2018
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	123	$	—	$	123	$	—	$	175	$	3	$	178
Energy derivative liabilities	$	—	$	109	$	—	$	109	$	—	$	37	$	—	$	37
Total debt(a)	$	—	$	2,296	$	—	$	2,296	$	—	$	2,414	$	—	$	2,414

__________

(a)The carrying value of total debt, excluding debt issuance costs, was $2,179 million and $2,509 million as of June 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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

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

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

Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured

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

Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a quarterly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million and $3 million included in Level 3 as of June 30, 2019 and December 31, 2018, respectively.

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended June 30, 2019 and 2018.

There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

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Derivatives and Concentration of Credit Risk

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Derivatives and Concentration of Credit Risk

Derivatives and Concentration of Credit Risk

Energy Commodity Derivatives

Risk Management Activities

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

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

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 June 30, 2019.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	Jul - Dec 2019	Fixed Price Swaps	WTI	(53,000)	$	54.62
Crude Oil	Jul - Dec 2019	Basis Swaps	Midland/Cushing	(22,000)	$	(1.37)
Crude Oil	Jul - Dec 2019	Basis Swaps	Nymex CMA Roll	(16,630)	$	0.11
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston	(1,663)	$	4.63
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston/Midland	(5,652)	$	6.47
Crude Oil	Jul - Dec 2019	Basis Swaps	Argus LLS/Midland	(1,663)	$	8.60
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston/Argus LLS	(1,663)	$	0.75
Crude Oil	Jul - Dec 2019	Basis Swaps	Clearbrook	(8,000)	$	(3.23)
Crude Oil	Jul - Dec 2019	Fixed Price Calls	WTI	(5,000)	$	54.08
Crude Oil	Jul - Dec 2019	Fixed Price Collars	WTI	(8,000)	$50.00 - $60.19
Crude Oil	2020	Fixed Price Swaps	WTI	(20,000)	$	59.03
Crude Oil	2020	Basis Swaps	Midland/Cushing	(7,486)	$	(1.31)
Crude Oil	2020	Basis Swaps	Brent/WTI Spread	(5,000)	$	8.36
Crude Oil	2020	Fixed Price Collars	WTI	(20,000)	$53.33 - $63.48
Crude Oil	2021	Basis Swaps	Brent/WTI Spread	(1,000)	$	8.00
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75
Natural Gas
Natural Gas	Jul - Dec 2019	Fixed Price Swaps	Henry Hub	(110)	$	3.07
Natural Gas	Jul - Dec 2019	Basis Swaps	Permian	(25)	$	(0.39)
Natural Gas	Jul - Dec 2019	Basis Swaps	Waha	(15)	$	2.94
Natural Gas	Jul - Dec 2019	Basis Swaps	Houston Ship Channel	(30)	$	(0.09)
Natural Gas	2020	Basis Swaps	Waha	(60)	$	(0.79)
Natural Gas	2021	Basis Swaps	Waha	(70)	$	(0.59)
Natural Gas	2022	Basis Swaps	Waha	(70)	$	(0.57)
Natural Gas	2023	Basis Swaps	Waha	(70)	$	(0.51)

__________

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

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

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

Fair values and gains (losses)

Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. Net gain (loss) on derivatives on the Consolidated Statements of Operations includes net settlements to be paid of $10 million and $1 million for the three and six months ended June 30, 2019, respectively, and $78 million and $133 million for the three and six months ended June 30, 2018, respectively.

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

Offsetting of derivative assets and liabilities

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

	Gross Amount Presented on Balance Sheet		Netting Adjustments (a)		Net Amount
June 30, 2019	(Millions)
Derivative assets with right of offset or master netting agreements	$	123	$	(72)	$	51
Derivative liabilities with right of offset or master netting agreements	$	(109)	$	72	$	(37)
December 31, 2018
Derivative assets with right of offset or master netting agreements	$	178	$	(37)	$	141
Derivative liabilities with right of offset or master netting agreements	$	(37)	$	37	$	—

__________

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

Credit-risk-related features

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

As of June 30, 2019, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $37 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. Assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, the additional collateral that we would have been required to post at June 30, 2019 was $37 million. 

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

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

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2019 and 2018, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

Our gross and net credit exposure from our derivative contracts were $123 million and $51 million, respectively, as of June 30, 2019. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.

Our six largest net counterparty positions represent approximately 99 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course of business, we sell crude oil to NGL Energy. For the first six months of 2019, sales to NGL Energy were approximately 14 percent of our total consolidated revenues adjusted for loss on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent approximately 1 percent of operating expenses.

Other

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

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Subsequent Events	6 Months Ended
	Jun. 30, 2019
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent EventOn August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over the next 24 months. Under the stock repurchase program, we may repurchase shares at management’s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume, general market conditions, legal requirements, general business conditions and corporate considerations determined by WPX’s management, such as liquidity and capital needs. This stock repurchase program may be modified, suspended or terminated at any time by our Board of Directors.

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Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Recently Adopted Accounting Standards

The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases, effective January 1, 2019. The standard requires the recognition of right of use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right of use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess:

•whether existing contracts are or contain leases;

•lease classification for any expired or existing leases;

•initial direct costs for any existing lease; and

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

See Note 9 for additional information related to our contracts that are or contain leases.

We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019. This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging

strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period.

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

Accounting Standards Not Yet Adopted

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

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

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Discontinued Operation (Tables)

6 Months Ended

Jun. 30, 2019

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]

The following table presents the results of our discontinued operations for the six months ended June 30, 2018. For the three and six months ended June 30, 2019 and the three months ended June 30, 2018, our discontinued operations activity was minimal and therefore is not included in the table below.

	Six months ended June 30,
	2018
Total revenues	$	75
Costs and expenses:
Depreciation, depletion and amortization	$	8
Lease and facility operating	7
Gathering, processing and transportation	12
Taxes other than income	5
General and administrative	1
Exploration	3
Accretion for transportation and gathering obligations retained	3
Other—net	4
Total costs and expenses	43
Operating income	32
Loss on sale of assets	(150)
Loss from discontinued operations before income taxes	(118)
Income tax benefit	(27)
Loss from discontinued operations	$	(91)

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Earnings (Loss) Per Common Share from Continuing Operations (Tables)

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

The following table summarizes the calculation of earnings per share.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions, except per-share amounts)
Income (loss) from continuing operations	$	305	$	(79)	$	257	$	(105)
Less: Dividends on preferred stock	—		4		—		8
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share	$	305	$	(83)	$	257	$	(113)
Basic weighted-average shares	422.5		400.0		421.8		399.3
Effect of dilutive securities(a)	1.0		—		1.8		—
Diluted weighted-average shares	423.5		400.0		423.6		399.3
Earnings (loss) per common share from continuing operations:
Basic	$	0.72	$	(0.21)	$	0.61	$	(0.28)
Diluted	$	0.72	$	(0.21)	$	0.61	$	(0.28)

__________

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

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
	(Millions)
Weighted-average nonvested restricted stock units and awards	—	2.9	—	3.0
Weighted-average stock options	—	0.2	—	0.2
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock	Not Applicable	19.8	Not Applicable	19.8
Nonvested restricted stock units and awards antidilutive under the treasury stock method	2.6	0.7	2.6	0.7

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Exploration Expense (Tables)

6 Months Ended

Jun. 30, 2019

Extractive Industries [Abstract]

Exploration Expenses

The following table presents a summary of exploration expenses.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions)
Unproved leasehold property amortization	$	21	$	16	$	44	$	33
Geologic and geophysical costs	3		1		4		3
Total exploration expenses	$	24	$	17	$	48	$	36

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Inventories (Tables)

6 Months Ended

Jun. 30, 2019

Inventory Disclosure [Abstract]

Inventories

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

	June 30, 2019		December 31, 2018
	(Millions)
Material, supplies and other	$	41	$	46
Commodity production in transit or storage	4		2
Total inventories	$	45	$	48

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Debt and Banking Arrangements (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt

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

	June 30, 2019		December 31, 2018
	(Millions)
Credit facility agreement	$	—	$	330
6.000% Senior Notes due 2022	529		529
8.250% Senior Notes due 2023	500		500
5.250% Senior Notes due 2024	650		650
5.750% Senior Notes due 2026	500		500
Total long-term debt	$	2,179	$	2,509
Less: Debt issuance costs on long-term debt(a)	22		24
Total long-term debt, net(a)	$	2,157	$	2,485

__________

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

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Provision (Benefit) for Income Taxes (Tables)

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes from Continuing Operations

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

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(Millions)
Current:
Federal	$	—	$	—	$	—	$	—
State	2		—		1		—
	2		—		1		—
Deferred:
Federal	75		(28)		63		(37)
State	7		(5)		6		(11)
	82		(33)		69		(48)
Total provision (benefit)	$	84	$	(33)	$	70	$	(48)

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Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Lease, Cost [Table Text Block]

The following tables include quantitative disclosures related to our leases.

	Six months ended June 30, 2019
	(Millions)
Lease Costs:
Leases recorded on the Consolidated Balance Sheet:
Operating lease cost—drilling rigs(a)	$	20
Operating lease cost—other(a)	9
Variable lease cost—drilling rigs(a)	3
Variable lease cost—other(a)	2
Short-term leases:
Drilling rigs(b)	20
Other(b)	59
Total lease cost	$	113
Other Information:
Cash paid for amount included in the measurement of lease liabilities:
Operating cash flows used for operating leases(a)	$	9
Investing cash flows used for operating leases(a)	$	20
Right-of-use assets obtained in exchange for new operating lease liabilities	$	32
Weighted-average remaining lease term (in years)	1.81 years
Weighted-average discount rate—operating leases	5		%

__________

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

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

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

The following tables include quantitative disclosures related to our leases as of June 30, 2019.

	Drilling Rigs		Real Estate, Compression and Other		Total Undiscounted Cash Flows
	(Millions)
Maturity of Lease Liabilities:
July 2019 through December 2019	$	20	$	10	$	30
2020	36		17		53
2021	4		10		14
2022	—		1		1
2023	—		—		—
Thereafter	—		—		—
					$	98
Current lease liabilities	$	36	$	18	$	54
Noncurrent lease liabilities	21		19		40
Total lease liabilities	$	57	$	37	$	94
Difference between undiscounted cash flows and discounted cash flows					$	4
Total right-of-use assets on Consolidated Balance Sheet					$	94

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

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

	June 30, 2019								December 31, 2018
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	—	$	123	$	—	$	123	$	—	$	175	$	3	$	178
Energy derivative liabilities	$	—	$	109	$	—	$	109	$	—	$	37	$	—	$	37
Total debt(a)	$	—	$	2,296	$	—	$	2,296	$	—	$	2,414	$	—	$	2,414

__________

(a)The carrying value of total debt, excluding debt issuance costs, was $2,179 million and $2,509 million as of June 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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Derivatives and Concentration of Credit Risk (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Derivative Volume that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production

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 June 30, 2019.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)	Weighted Average Price (c)
Crude Oil
Crude Oil	Jul - Dec 2019	Fixed Price Swaps	WTI	(53,000)	$	54.62
Crude Oil	Jul - Dec 2019	Basis Swaps	Midland/Cushing	(22,000)	$	(1.37)
Crude Oil	Jul - Dec 2019	Basis Swaps	Nymex CMA Roll	(16,630)	$	0.11
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston	(1,663)	$	4.63
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston/Midland	(5,652)	$	6.47
Crude Oil	Jul - Dec 2019	Basis Swaps	Argus LLS/Midland	(1,663)	$	8.60
Crude Oil	Jul - Dec 2019	Basis Swaps	Magellan East Houston/Argus LLS	(1,663)	$	0.75
Crude Oil	Jul - Dec 2019	Basis Swaps	Clearbrook	(8,000)	$	(3.23)
Crude Oil	Jul - Dec 2019	Fixed Price Calls	WTI	(5,000)	$	54.08
Crude Oil	Jul - Dec 2019	Fixed Price Collars	WTI	(8,000)	$50.00 - $60.19
Crude Oil	2020	Fixed Price Swaps	WTI	(20,000)	$	59.03
Crude Oil	2020	Basis Swaps	Midland/Cushing	(7,486)	$	(1.31)
Crude Oil	2020	Basis Swaps	Brent/WTI Spread	(5,000)	$	8.36
Crude Oil	2020	Fixed Price Collars	WTI	(20,000)	$53.33 - $63.48
Crude Oil	2021	Basis Swaps	Brent/WTI Spread	(1,000)	$	8.00
Crude Oil	2022	Basis Swaps	Brent/WTI Spread	(1,000)	$	7.75
Natural Gas
Natural Gas	Jul - Dec 2019	Fixed Price Swaps	Henry Hub	(110)	$	3.07
Natural Gas	Jul - Dec 2019	Basis Swaps	Permian	(25)	$	(0.39)
Natural Gas	Jul - Dec 2019	Basis Swaps	Waha	(15)	$	2.94
Natural Gas	Jul - Dec 2019	Basis Swaps	Houston Ship Channel	(30)	$	(0.09)
Natural Gas	2020	Basis Swaps	Waha	(60)	$	(0.79)
Natural Gas	2021	Basis Swaps	Waha	(70)	$	(0.59)
Natural Gas	2022	Basis Swaps	Waha	(70)	$	(0.57)
Natural Gas	2023	Basis Swaps	Waha	(70)	$	(0.51)

__________

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

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

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

Gross And Net 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
June 30, 2019	(Millions)
Derivative assets with right of offset or master netting agreements	$	123	$	(72)	$	51
Derivative liabilities with right of offset or master netting agreements	$	(109)	$	72	$	(37)
December 31, 2018
Derivative assets with right of offset or master netting agreements	$	178	$	(37)	$	141
Derivative liabilities with right of offset or master netting agreements	$	(37)	$	37	$	—

__________

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

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Basis of Presentation and Description of Business- Additional Information (Details) - USD ($) $ in Millions	Jun. 30, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Right-of-Use Asset	$ 94
Operating Lease, Liability, Noncurrent	40
Operating Lease, Liability, Current	$ 54
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Right-of-Use Asset		$ 90
Operating Lease, Liability, Noncurrent		46
Operating Lease, Liability, Current		$ 44

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Discontinued Operation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue				$ 75
Disposal Group, Including Discontinued Operation, Depreciation and Amortization				8
Disposal Group, Including Discontinued Operation, Lease Operating Expense				7
Disposal Group Including Discontinued Operation Gathering and Transportation Expense				12
Disposal Group, Including Discontinued Operation Taxes other than income				5
Disposal Group, Including Discontinued Operation, General and Administrative Expense				1
Disposal Group Including Discontinued Operation Exploration Expense				3
Accretion Expense				3
Disposal Group, Including Discontinued Operation, Other Expense				4
Disposal Group, Including Discontinued Operation, Operating Expense				43
Disposal Group, Including Discontinued Operation, Operating Income (Loss)				32
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax				(150)
Disposal Group Including Discontinued Operation Income before Tax				(118)
Discontinued Operation, Tax Effect of Discontinued Operation				(27)
Loss from discontinued operations	$ 0	$ (2)	$ 0	$ (91)

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Discontinued Operations Cash Flow (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	$ (15)	$ (28)
Powder River Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations	$ (15)	(28)
San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities		45
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities		$ 29

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Discontinued Operations-Additional Information (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax		$ (150)
San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax	$ 147
Gathering and Treating [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation	309	309
Guarantee Type, Other [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual Obligation	9	9
Cash [Member] | San Juan Gallup [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	$ 667	$ 667

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Earnings (Loss) Per Common Share from Continuing Operations (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share, Basic, by Common Class [Line Items]
Income (loss) from continuing operations		$ 305	$ (79)	$ 257	$ (105)
Preferred Stock Dividends, Income Statement Impact		0	4	0	8
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share		$ 305	$ (83)	$ 257	$ (113)
Weighted Average Number of Shares Outstanding, Basic		422.5	400.0	421.8	399.3
Weighted Average Number of Shares Outstanding, Diluted	[1]	423.5	400.0	423.6	399.3
Income (Loss) from Continuing Operations, Per Basic Share		$ 0.72	$ (0.21)	$ 0.61	$ (0.28)
Income (Loss) from Continuing Operations, Per Diluted Share		$ 0.72	$ (0.21)	$ 0.61	$ (0.28)
Restricted Stock [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		1.0		1.8
Employee Stock Option [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		0.0	0.2	0.0	0.2
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount				0.9	0.6
Restricted Stock [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		0.0	2.9	0.0	3.0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		2.6	0.7	2.6	0.7
Convertible Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements			19.8		19.8

[1] Certain amounts of nonvested restricted stock units and awards and stock options are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application, in 2018, of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units and awards. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows: Three months
ended June 30,Six months
ended June 30,2019 2018 2019 2018 (Millions) Weighted-average nonvested restricted stock units and awards — 2.9 — 3.0 Weighted-average stock options— 0.2 — 0.2  Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock Not
Applicable 19.8 Not
Applicable 19.8  Nonvested restricted stock units and awards antidilutive under the treasury stock method 2.6 0.7 2.6 0.7 

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Earnings (Loss) Per Common Share from Continuing Operations (Details 1) - shares shares in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0.9	0.6

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Asset Sales-Additional Information (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from Sale of Other Assets, Investing Activities		$ 83
Gain (Loss) on Disposition of Proved Property		$ 0
Gains on equity method investment transactions	$ 247		$ 0	$ 373	$ 0
Long-term Investments	55			$ 55		$ 167
Whitewater [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Equity Method Investment, Ownership Percentage		20.00%
Gains on equity method investment transactions		$ 126
Long-term Investments		$ 15
Oryx [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proceeds from Sale of Other Assets, Investing Activities	$ 357
Equity Method Investment, Ownership Percentage	25.00%			25.00%
Gains on equity method investment transactions	$ 247
Long-term Investments	$ 110			$ 110

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Exploration Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved leasehold property amortization	$ 21	$ 16	$ 44	$ 33
Geologic and geophysical costs	3	1	4	3
Total exploration expenses	$ 24	$ 17	$ 48	$ 36

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Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Inventory [Line Items]
Materials, Supplies, and Other	$ 41	$ 46
Commodity production in transit or storage	4	2
Inventory, Total	$ 45	$ 48

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Debt and Banking Arrangements (Details) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term Debt		$ 2,179	$ 2,509
Total long-term debt		2,179	2,509
Less: Debt issuance costs on long-term debt(a)	[1]	22	24
Long-term debt, net	[1]	2,157	2,485
Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt		0	330
6.000% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term Debt		529	529
8.250% Senior Notes due 2023
Debt Instrument [Line Items]
Long-term Debt		500	500
5.250% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term Debt		650	650
5.750% Senior Notes due 2026
Debt Instrument [Line Items]
Long-term Debt		$ 500	$ 500

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

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Debt and Banking Arrangements - Debt - Additional information (Detail) $ in Millions	Jun. 30, 2019 USD ($)
Debt Instrument [Line Items]
Letters of credit issued	$ 42
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity during Collateral Period	2,100
Credit facility agreement	$ 1,500

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Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Current:
Federal	$ 0	$ 0	$ 0	$ 0
State	2	0	1	0
Total current	2	0	1	0
Deferred:
Federal	75	(28)	63	(37)
State	7	(5)	6	(11)
Total deferred	82	(33)	69	(48)
Total provision (benefit)	$ 84	$ (33)	$ 70	$ (48)

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Provision (Benefit) for Income Taxes - Additional Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%
Unrecognized Tax Benefits	$ 8
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 7

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Contingent Liabilities - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2021	Jun. 30, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Loss contingencies associated with royalty litigation		$ 11	$ 11
Oil and gas transportation [Member]
Loss Contingencies [Line Items]
Contractual Obligation		$ 800
Oil and gas transportation [Member] | Minimum [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Contractual Obligation, Future Demand Payments Due	$ 38
Oil and gas transportation [Member] | Maximum [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Contractual Obligation, Future Demand Payments Due	$ 97

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Lease Costs (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 113
Operating cash flows used for operating leases(a)	9	[1]
Investing cash flows used for operating leases(a)	20	[1]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 32
Operating Lease, Weighted Average Remaining Lease Term	1 year 9 months 21 days
Operating Lease, Weighted Average Discount Rate, Percent	5.00%
Upstream Equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 20	[1]
Variable Lease, Cost	3	[1]
Short-term Lease, Cost	20	[2]
Other Energy Equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	9	[1]
Variable Lease, Cost	2	[1]
Short-term Lease, Cost	$ 59	[2]

[1] Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners.

[2] Includes variable lease costs on short-term leases.

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Leases (Details) $ in Millions	Jun. 30, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months	$ 30
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two	53
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three	14
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four	1
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due, Total	98
Operating Lease, Liability, Current	54
Operating Lease, Liability, Noncurrent	40
Operating Lease, Liability, Total	94
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	4
Operating Lease, Right-of-Use Asset	94
Upstream Equipment [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months	20
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two	36
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three	4
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four	0
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five	0
Operating Lease, Liability, Current	36
Operating Lease, Liability, Noncurrent	21
Operating Lease, Liability, Total	57
Other Machinery and Equipment [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months	10
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two	17
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three	10
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four	1
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five	0
Operating Lease, Liability, Current	18
Operating Lease, Liability, Noncurrent	19
Operating Lease, Liability, Total	$ 37

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Fair Value Measurements (Details) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 123	$ 178
Derivative Liability, Fair Value, Gross Liability		109	37
Long-term debt, Fair Value	[1]	2,296	2,414
Long-term Debt		2,179	2,509
Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		123	178
Derivative Liability, Fair Value, Gross Liability		109	37
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	0	0
Level 1 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Derivative Liability, Fair Value, Gross Liability		0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	2,296	2,414
Level 2 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		123	175
Derivative Liability, Fair Value, Gross Liability		109	37
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, Fair Value	[1]	0	0
Level 3 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	3
Derivative Liability, Fair Value, Gross Liability		0	0
Derivative Asset			$ 3
Maximum [Member] | Level 3 | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		$ 1

[1] The carrying value of total debt, excluding debt issuance costs, was $2,179 million and $2,509 million as of June 30, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.

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Derivatives related to production (Detail) - Short [Member] - Derivatives related to production BTU / d in Thousands	6 Months Ended
	Jun. 30, 2019 bbl / d BTU / d $ / bbl $ / MMBtu	[2]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(22,000)	[1]
Underlying, Derivative	(1.37)	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Nymex CMA Roll [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(16,630)	[1]
Underlying, Derivative Energy Measure	0.11	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Magellan East Houston [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,663)	[1]
Underlying, Derivative Energy Measure	4.63	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Magellan East Houston-Midland [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(5,652)	[1]
Underlying, Derivative Energy Measure	6.47	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Argus LLS-Midland [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,663)	[1]
Underlying, Derivative Energy Measure	8.60	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Magellan East Houston-Argus LLS [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,663)	[1]
Underlying, Derivative Energy Measure	0.75	[3]
Crude Oil | 2019 [Member] | Basis Swap [Member] | Clearbrook [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(8,000)	[1]
Underlying, Derivative	(3.23)	[3]
Crude Oil | 2019 [Member] | Price Risk Derivative [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(53,000)	[1]
Underlying, Derivative Energy Measure	54.62	[3]
Crude Oil | 2019 [Member] | Call Option [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)	[1]
Underlying, Derivative Energy Measure	54.08	[3]
Crude Oil | 2019 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(8,000)	[1]
Crude Oil | 2020 [Member] | Basis Swap [Member] | Midland-Cushing [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(7,486)	[1]
Underlying, Derivative	(1.31)	[3]
Crude Oil | 2020 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(5,000)	[1]
Underlying, Derivative Energy Measure	8.36	[3]
Crude Oil | 2020 [Member] | Price Risk Derivative [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(20,000)	[1]
Underlying, Derivative Energy Measure	59.03	[3]
Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Notional Volume | bbl / d	(20,000)	[1]
Crude Oil | 2021 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,000)	[1]
Underlying, Derivative Energy Measure	8.00	[3]
Crude Oil | 2022 [Member] | Basis Swap [Member] | Brent/WTI Spread [Member]
Derivative [Line Items]
Notional Volume | bbl / d	(1,000)	[1]
Underlying, Derivative Energy Measure	7.75	[3]
Natural Gas [Member] | 2019 [Member] | Basis Swap [Member] | Permian [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(25)	[1]
Underlying, Derivative | $ / MMBtu	(0.39)	[3]
Natural Gas [Member] | 2019 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(15)	[1]
Underlying, Derivative Energy Measure | $ / MMBtu	2.94	[3]
Natural Gas [Member] | 2019 [Member] | Basis Swap [Member] | Houston Ship [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(30)	[1]
Underlying, Derivative | $ / MMBtu	(0.09)	[3]
Natural Gas [Member] | 2019 [Member] | Price Risk Derivative [Member] | Henry Hub
Derivative [Line Items]
Notional Volume | BTU / d	(110)	[1]
Underlying, Derivative Energy Measure | $ / MMBtu	3.07	[3]
Natural Gas [Member] | 2020 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(60)	[1]
Underlying, Derivative | $ / MMBtu	(0.79)	[3]
Natural Gas [Member] | 2021 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(70)	[1]
Underlying, Derivative | $ / MMBtu	(0.59)	[3]
Natural Gas [Member] | 2022 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(70)	[1]
Underlying, Derivative | $ / MMBtu	(0.57)	[3]
Natural Gas [Member] | 2023 [Member] | Basis Swap [Member] | Waha [Member]
Derivative [Line Items]
Notional Volume | BTU / d	(70)	[1]
Underlying, Derivative | $ / MMBtu	(0.51)	[3]
Minimum [Member] | Crude Oil | 2019 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	50.00	[3]
Minimum [Member] | Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	53.33	[3]
Maximum [Member] | Crude Oil | 2019 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	60.19	[3]
Maximum [Member] | Crude Oil | 2020 [Member] | Put Option [Member] | WTI
Derivative [Line Items]
Underlying, Derivative Energy Measure	63.48	[3]

[1] Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.

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

[3] The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.

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Fair values and gains (losses) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cost of Hedge	$ 10	$ 78	$ 1	$ 133

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Offsetting of derivative assets and liabilities (Detail) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Gross And Net Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 123	$ 178
Derivative Asset, Fair Value, Gross Liability	[1]	(72)	(37)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		51	141
Derivative Liability, Fair Value, Gross Liability		(109)	(37)
Derivative Liability, Fair Value, Gross Asset	[1]	72	37
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ (37)	$ 0

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

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Credit-risk-related features (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0
Net derivative liability position	37
Derivative Liability, Fair Value of Collateral	37
Maximum [Member]
Derivative [Line Items]
Reduction in derivative liabilties	$ 1

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Concentration of credit risk (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Credit Exposure From Derivatives [Line Items]
Gross credit exposure from derivatives, Gross Total	$ 123
Net credit exposure from derivatives	$ 51
Number Of Largest Net Counter Party Positions Investment Grade	6
Percentage Of Net Credit Exposure From Derivatives	99.00%
NGL Energy Partners [Member] | Sales Revenue, Net [Member]
Credit Exposure From Derivatives [Line Items]
Concentration Risk, Percentage	14.00%
NGL Energy Partners [Member] | Operating Expense [Member]
Credit Exposure From Derivatives [Line Items]
Concentration Risk, Percentage	1.00%

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Subsequent Events (Details) $ in Millions	Sep. 30, 2019 USD ($)
Subsequent Event [Member]
Subsequent Event [Line Items]
Stock Repurchase Program, Authorized Amount	$ 400