WPX ENERGY, INC., 10-Q filed on 5/2/2019
Quarterly Report
v3.19.1
Document and Entity Information - shares
3 Months Ended
Mar. 31, 2019
May 01, 2019
Document and Entity Information [Abstract]    
Document Type 10-Q  
Amendment Flag false  
Document Period End Date Mar. 31, 2019  
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q1  
Trading Symbol WPX  
Entity Registrant Name WPX ENERGY, INC.  
Entity Central Index Key 0001518832  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Common Stock, Shares Outstanding   422,267,046
v3.19.1
Consolidated Balance Sheet (Unaudited) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Current assets:    
Cash and Cash Equivalents, at Carrying Value $ 6 $ 3
Accounts receivable, net of allowance 538 405
Derivative assets, current 69 174
Inventories 52 48
Assets classified as held for sale (Note 2) 0 79
Other 38 30
Total current assets 703 739
Long-term Investments 168 167
Properties and equipment (successful efforts method of accounting) 10,370 9,949
Less—accumulated depreciation, depletion and amortization (2,917) (2,683)
Properties and equipment, net 7,453 7,266
Derivative assets, noncurrent 23 4
Other noncurrent assets 124 27
Total assets 8,471 8,203
Current liabilities:    
Accounts payable 683 514
Accrued and other current liabilities 190 178
Derivative liabilities, current 137 23
Total current liabilities 1,010 715
Deferred income taxes 188 201
Long-term debt, net [1] 2,470 2,485
Derivative liabilities, noncurrent 29 14
Other noncurrent liabilities 526 487
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 March 31, 2019 and December 31, 2018) 4 4
Additional paid-in-capital 7,729 7,734
Accumulated deficit (3,485) (3,437)
Total stockholders’ equity 4,248 4,301
Total liabilities and equity $ 8,471 $ 8,203
[1] Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
v3.19.1
Consolidated Balance Sheet (Unaudited) (Parenthetical) - $ / shares
Mar. 31, 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
v3.19.1
Consolidated Statement of Operations (Unaudited) - USD ($)
shares in Millions, $ in Millions
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Revenues:    
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net $ (207) $ (69)
Total revenues 359 374
Costs and expenses:    
Depreciation, depletion and amortization 219 161
Lease and facility operating 86 55
Taxes other than income 39 30
Exploration (Note 4) 24 19
General and administrative (including equity-based compensation of $8 million and $7 million for the respective periods) 47 43
Other—net 2 3
Total costs and expenses 508 368
Operating income (loss) (149) 6
Interest expense (41) (46)
Gain on sale of equity investment 126 0
Investment income (loss) and other 2 (1)
Income (loss) from continuing operations before income taxes (62) (41)
Provision (benefit) for income taxes (14) (15)
Income (loss) from continuing operations (48) (26)
Income (loss) from discontinued operations 0 (89)
Net income (loss) (48) (115)
Preferred Stock Dividends, Income Statement Impact 0 4
Net income (loss) available to WPX Energy, Inc. common stockholders (48) (119)
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 (48) (30)
Income (loss) from discontinued operations $ 0 $ (89)
Income (Loss) from Continuing Operations, Per Basic Share $ (0.11) $ (0.07)
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Basic Share 0 (0.23)
Earnings Per Share, Basic $ (0.11) $ (0.30)
Weighted Average Number of Shares Outstanding, Basic 421.0 398.6
Income (Loss) from Continuing Operations, Per Diluted Share $ (0.11) $ (0.07)
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Diluted Share 0 (0.23)
Earnings Per Share, Diluted $ (0.11) $ (0.30)
Weighted Average Number of Shares Outstanding, Diluted [1] 421.0 398.6
Oil and Condensate [Member]    
Revenues:    
Revenue from Customers $ 449 $ 360
Natural Gas, Production [Member]    
Revenues:    
Revenue from Customers 25 17
Natural Gas Liquids [Member]    
Revenues:    
Revenue from Customers 33 30
Oil and Gas [Member]    
Revenues:    
Revenue from Customers 507 407
Oil and Gas, Refining and Marketing [Member]    
Revenues:    
Revenue from Customers 59 36
Costs and expenses:    
Cost of Goods and Services Sold 49 39
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]    
Costs and expenses:    
Cost of Goods and Services Sold $ 42 $ 18
[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. 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 March 31,
2019 2018 
Weighted-average nonvested restricted stock units and awards
2.6 3.1 
Weighted-average stock options— 0.2 
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
Not
Applicable 
19.8 
Nonvested restricted stock units antidilutive under the treasury stock method
2.5 0.7 
v3.19.1
Consolidated Statement of Operations (parenthetical) - USD ($)
$ in Millions
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Non-cash equity-based compensation expense $ 8 $ 7
v3.19.1
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) (115)       (115)
Stock-based compensation, net of tax impact (2)     (2)  
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings 4     4  
Ending Balance at Mar. 31, 2018 4,006 232 4 7,473 (3,703)
Beginning Balance at Dec. 31, 2018 4,301 0 4 7,734 (3,437)
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Net income (loss) (48)       (48)
Stock-based compensation, net of tax impact (5)     (5)  
Ending Balance at Mar. 31, 2019 $ 4,248 $ 0 $ 4 $ 7,729 $ (3,485)
v3.19.1
Consolidated Statements of Cash Flows - USD ($)
$ in Millions
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Operating Activities(a)    
Net income (loss) $ (48) $ (115)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation Depletion And Amortization Including Discontinued Portion 219 168
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations (13) (43)
Provision For Impairment Of Properties And Equipment Including Certain Exploration Expenses And Equity Method Investment 20 20
Gain on sale of equity investment 126 0
Net (gain) loss on derivatives 207 69
Net settlements related to derivatives (9) 55
Amortization of stock-based awards 8 8
Net (gain) loss on sales of assets including discontinued operations 0 151
Cash provided by (used in) operating assets and liabilities:    
Accounts receivable (137) (21)
Inventories (4) (8)
Other current assets (6) 6
Accounts payable 197 28
Accrued and other current liabilities (37) (48)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations (8) (10)
Other, including changes in other noncurrent assets and liabilities (9) (5)
Net cash provided by (used in) operating activities(a) [1] 272 145
Investing Activities(a)    
Capital Expenditures [2] (451) (321)
Proceeds from sales of assets 228 699
Purchase of or contributions to investments (18) (16)
Proceeds from Equity Method Investment, Distribution, Return of Capital 4 0
Net cash used in investing activities(a) [1] (237) 362
Financing Activities    
Proceeds from common stock 1 1
Dividends paid on preferred stock 0 (4)
Borrowings on credit facility 609 138
Payments on credit facility (625) (138)
Taxes paid for shares withheld (15) (11)
Proceeds from (Payments for) Other Financing Activities 1 0
Net cash provided by (used in) financing activities (29) (14)
Net decrease in cash and cash equivalents and restricted cash 6 493
Cash, cash equivalents and restricted cash at beginning of period 18 201
Cash and cash equivalents and restricted cash at end of period 24 694
Increase to properties and equipment (425) (349)
Changes In Related Accounts Payable $ (26) $ 28
[1] (a) Amounts reflect continuing and discontinued operations unless otherwise noted.
[2]
(b) Increase to properties and equipment(425)(349)
Changes in related accounts payable and accounts receivable(26)28 
Capital expenditures(451)(321)
v3.19.1
Basis of Presentation and Description of Business
3 Months Ended
Mar. 31, 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 third-party working interest owners in operated wells and 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 March 31, 2019, results of operations for the three months ended March 31, 2019 and 2018, changes in equity for the three months ended March 31, 2019 and 2018, and cash flows for the three months ended March 31, 2019 and 2018. The Company has no elements 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 a initial right of use assets of $90 million in other noncurrent assets, noncurrent lease liabilies 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 Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
Accounting Standards Not Yet Adopted
In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses. This ASU 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.
v3.19.1
Discontinued Operations (Notes)
3 Months Ended
Mar. 31, 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 three months ended March 31, 2018. For the three months ended March 31, 2019, our discontinued operations activity was minimal and therefore is not included in the table below.
Three months
ended March 31,
2018
 
Total revenues$76 
Costs and expenses:
Depreciation, depletion and amortization$
Lease and facility operating
Gathering, processing and transportation12 
Taxes other than income
General and administrative
Exploration
Accretion for transportation and gathering obligations retained
Other—net
Total costs and expenses43 
Operating income (loss)33 
Gain (loss) on sale of assets(149)
Gain (loss) from discontinued operations before income taxes
(116)
Income tax provision (benefit)(27)
Income (loss) from discontinued operations $(89)

Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $8 million and $10 million for the three months ended March 31, 2019 and 2018, respectively.
Three months ended March 31,
2018
 
Cash provided by operating activities(a)$46 
Cash capital expenditures within investing activities$26 
 __________
(a) Excluding income taxes and changes in working capital items.
v3.19.1
Earnings (Loss) Per Common Share from Continuing Operations
3 Months Ended
Mar. 31, 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 March 31,
 2019 2018 
 
Income (loss) from continuing operations$(48)$(26)
Less: Dividends on preferred stock— 
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
$(48)$(30)
Basic weighted-average shares421.0 398.6 
Effect of dilutive securities(a)— — 
Diluted weighted-average shares421.0 398.6 
Earnings (loss) per common share from continuing operations:
Basic$(0.11)$(0.07)
Diluted$(0.11)$(0.07)
__________
(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. 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 March 31,
2019 2018 
Weighted-average nonvested restricted stock units and awards
2.6 3.1 
Weighted-average stock options— 0.2 
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
Not
Applicable 
19.8 
Nonvested restricted stock units antidilutive under the treasury stock method
2.5 0.7 

Stock options of approximately 0.9 million and 1.0 million that were outstanding at March 31, 2019 and 2018, respectively, have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the respective first quarter weighted-average market price of our common shares.
v3.19.1
Asset Sales and Exploration Expense
3 Months Ended
Mar. 31, 2019
Extractive Industries [Abstract]  
Asset Sales, Exploration Expenses And Other Accruals [Text Block] Asset Sale, Sales of Investments 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.
Sales of Investments
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 investment at the time of disposition was approximately $15 million. As a result of this transaction, we recorded a $126 million gain.
Subsequent to March 31, 2019, we signed an agreement to effectively sell our 25 percent equity interest in the Oryx pipeline for net proceeds of approximately $350 million, subject to closing adjustments. The net book value of this investment was approximately $111 million as of March 31, 2019. The transaction is expected to close in second-quarter 2019.
Exploration Expenses
The following table presents a summary of exploration expenses.
 Three months
ended March 31,
 2019 2018 
 
Unproved leasehold property impairment, amortization and expiration
$23 $17 
Geologic and geophysical costs
Total exploration expenses$24 $19 
v3.19.1
Inventories
3 Months Ended
Mar. 31, 2019
Inventory Disclosure [Abstract]  
Inventories Inventories
The following table presents a summary of our inventories as of the dates indicated.
March 31,
2019
December 31,
2018
 (Millions)
Material, supplies and other $46 $46 
Commodity production in transit or storage
Total inventories$52 $48 
v3.19.1
Debt and Banking Arrangements
3 Months Ended
Mar. 31, 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.
March 31,
2019
December 31,
2018
 (Millions)
Credit facility agreement$314 $330 
6.000% Senior Notes due 2022529 529 
8.250% Senior Notes due 2023500 500 
5.250% Senior Notes due 2024650 650 
5.750% Senior Notes due 2026500 500 
Total long-term debt$2,493 $2,509 
Less: Debt issuance costs on long-term debt(a)23 24 
 Total long-term debt, net(a)
$2,470 $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 March 31, 2019, we had $314 million borrowings outstanding and $47 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.
v3.19.1
Provision (Benefit) for Income Taxes
3 Months Ended
Mar. 31, 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 March 31,
 2019 2018 
 
Current:
Federal$— $— 
State(1)— 
(1)— 
Deferred:
Federal(12)(9)
State(1)(6)
(13)(15)
Total provision (benefit)$(14)$(15)

The effective income tax rate for the three months ended March 31, 2019, differs from the federal statutory rate of 21 percent due to to the effect of state income taxes, partially offset by the reversal of the valuation allowance on capital loss carryovers resulting from the expected capital gain from the 2019 sale of an equity interest in a partnership.
The effective income tax rate for the three months ended March 31, 2018, differs from the federal statutory rate of 21 percent due to 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 March 31, 2019, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the acquisition.
Pursuant to our tax sharing agreement with Williams, we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre-spin-off period for which we continue to have exposure to audit adjustments as part of Williams. 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 March 31, 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.
v3.19.1
Contingent Liabilities
3 Months Ended
Mar. 31, 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. On October 23, 2018, a settlement in principle with the Kansas and Missouri class claimants was reached. The written settlement agreement has been finalized, and a motion for preliminary approval of the settlement filed with the Court. In
the Wisconsin class action, defendants’ motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs’ motion to remand the case to the originally filed district court.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court. The parties have filed numerous motions for summary judgment, reconsideration and remand. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements.
The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.
As of March 31, 2019, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of March 31, 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.
v3.19.1
Leases
3 Months Ended
Mar. 31, 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 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 March 31, 2019 are not significant.

The following tables include quantitative disclosures related to our leases.
 Three months ended March 31, 2019
 (Millions)
Lease costs:
Leases recorded on the Consolidated Balance Sheet:
Operating lease cost—drilling rigs(a)$
Operating lease cost—other(a)
Variable lease cost—drilling rigs(a)— 
Variable lease cost—other(a)— 
Short-term leases:
Drilling rigs(b)10 
Other(b)30 
Total lease cost$53 
Other Information:
Cash paid for amount included in the measurement of lease liabilities:
Operating cash flows used for operating leases(a)$
Investing cash flows used for operating leases(a)$
Right-of-use assets obtained in exchange for new operating lease liabilities$21 
Weighted-average remaining lease term (in years)1.92 years
Weighted-average discount rate—operating leases%
__________
(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 March 31, 2019.
 Drilling RigsReal Estate, Compression and OtherTotal Undiscounted Cash Flows
 (Millions)
Maturity of Lease Liabilities:
April 2019 through December 2019$31 $12 $43 
202036 14 50 
202110 
2022— 
2023— — — 
Thereafter— — — 
$104 
Current lease liabilities$38 $15 $53 
Noncurrent lease liabilities29 17 46 
Total lease liabilities$67 $32 $99 
Difference between undiscounted cash flows and discounted cash flows$
Total right-of-use assets on Consolidated Balance Sheet$99 
v3.19.1
Fair Value Measurements
3 Months Ended
Mar. 31, 2019
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 March 31, 2019December 31, 2018
 Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
 (Millions)(Millions)
Energy derivative assets$— $92 $— $92 $— $175 $$178 
Energy derivative liabilities$— $166 $— $166 $— $37 $— $37 
Total debt(a)$— $2,590 $— $2,590 $— $2,414 $— $2,414 
__________
(a)The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,493 million and $2,509 million as of March 31, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes capital leases and 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 assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as calls and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for
receiving premium 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 did not have any Level 3 instruments as of March 31, 2019.
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 March 31, 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.
v3.19.1
Derivatives and Concentration of Credit Risk
3 Months Ended
Mar. 31, 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 March 31, 2019.
CommodityPeriodContract Type (a)LocationNotional Volume (b)Weighted Average
Price (c)
Crude Oil
Crude OilApr - Dec 2019Fixed Price SwapsWTI(53,000)$54.62 
Crude OilApr - Dec 2019Basis SwapsMidland/Cushing
(21,338)$(1.23)
Crude OilApr - Dec 2019Basis SwapsNymex CMA Roll(17,818)$0.11 
Crude OilApr - Dec 2019Basis SwapsMagellan East Houston/Midland(2,444)$8.12 
Crude OilApr - Dec 2019Basis SwapsArgus LLS/Midland(1,113)$8.60 
Crude OilApr - Dec 2019Basis SwapsMagellan East Houston/Argus LLS(1,113)$0.75 
Crude OilApr - Dec 2019Basis SwapsClearbrook(3,673)$(2.99)
Crude OilApr - Dec 2019Fixed Price CallsWTI(5,000)$54.08 
Crude OilApr - Dec 2019Fixed Price CollarsWTI(8,000)$50.00 - $60.19
Crude Oil2020Fixed Price SwapsWTI(10,000)$57.22 
Crude Oil2020Basis SwapsMidland/Cushing(7,486)$(1.31)
Crude Oil2020Basis SwapsBrent/WTI Spread(5,000)$8.36 
Crude Oil2020Fixed Price CollarsWTI(10,000)$53.01 - $63.01
Crude Oil2021Basis SwapsBrent/WTI Spread(1,000)$8.00 
Crude Oil2022Basis SwapsBrent/WTI Spread(1,000)$7.75 
Natural Gas
Natural GasApr - Dec 2019Fixed Price SwapsHenry Hub(110)$3.07 
Natural GasApr - Dec 2019Basis SwapsPermian(25)$(0.39)
Natural GasApr - Dec 2019Basis SwapsWaha(15)$2.94 
Natural GasApr - Dec 2019Basis SwapsHouston Ship Channel(30)$(0.09)
Natural Gas2020Basis SwapsWaha(60)$(0.79)
Natural Gas2021Basis SwapsWaha(70)$(0.59)
Natural Gas2022Basis SwapsWaha(70)$(0.57)
Natural Gas2023Basis SwapsWaha(70)$(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 received of $9 million and to be paid of $55 million for the three months ended March 31, 2019 and 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 SheetNetting Adjustments (a)Net Amount
March 31, 2019(Millions)
Derivative assets with right of offset or master netting agreements
$92 $(79)$13 
Derivative liabilities with right of offset or master netting agreements
$(166)$79 $(87)
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 March 31, 2019, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $87 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 March 31, 2019 was $87 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 $92 million and $13 million, respectively, as of March 31, 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 three largest net counterparty positions represent approximately 96 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 three 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.
v3.19.1
Accounting Policies (Policies)
3 Months Ended
Mar. 31, 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 a initial right of use assets of $90 million in other noncurrent assets, noncurrent lease liabilies 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 Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
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 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.
v3.19.1
Discontinued Operation (Tables)
3 Months Ended
Mar. 31, 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 three months ended March 31, 2018. For the three months ended March 31, 2019, our discontinued operations activity was minimal and therefore is not included in the table below.
Three months
ended March 31,
2018
 
Total revenues$76 
Costs and expenses:
Depreciation, depletion and amortization$
Lease and facility operating
Gathering, processing and transportation12 
Taxes other than income
General and administrative
Exploration
Accretion for transportation and gathering obligations retained
Other—net
Total costs and expenses43 
Operating income (loss)33 
Gain (loss) on sale of assets(149)
Gain (loss) from discontinued operations before income taxes
(116)
Income tax provision (benefit)(27)
Income (loss) from discontinued operations $(89)
Schedule of Disposal Groups Including Discontinued Operations Cash Flows [Table Text Block]
Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $8 million and $10 million for the three months ended March 31, 2019 and 2018, respectively.
Three months ended March 31,
2018
 
Cash provided by operating activities(a)$46 
Cash capital expenditures within investing activities$26 
 __________
(a) Excluding income taxes and changes in working capital items.
v3.19.1
Earnings (Loss) Per Common Share from Continuing Operations (Tables)
3 Months Ended
Mar. 31, 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 March 31,
 2019 2018 
 
Income (loss) from continuing operations$(48)$(26)
Less: Dividends on preferred stock— 
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
$(48)$(30)
Basic weighted-average shares421.0 398.6 
Effect of dilutive securities(a)— — 
Diluted weighted-average shares421.0 398.6 
Earnings (loss) per common share from continuing operations:
Basic$(0.11)$(0.07)
Diluted$(0.11)$(0.07)
__________
(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. 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 March 31,
2019 2018 
Weighted-average nonvested restricted stock units and awards
2.6 3.1 
Weighted-average stock options— 0.2 
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
Not
Applicable 
19.8 
Nonvested restricted stock units antidilutive under the treasury stock method
2.5 0.7 
v3.19.1
Exploration Expense (Tables)
3 Months Ended
Mar. 31, 2019
Extractive Industries [Abstract]  
Exploration Expenses
The following table presents a summary of exploration expenses.
 Three months
ended March 31,
 2019 2018 
 
Unproved leasehold property impairment, amortization and expiration
$23 $17 
Geologic and geophysical costs
Total exploration expenses$24 $19 
v3.19.1
Inventories (Tables)
3 Months Ended
Mar. 31, 2019
Inventory Disclosure [Abstract]  
Inventories
The following table presents a summary of our inventories as of the dates indicated.
March 31,
2019
December 31,
2018
 (Millions)
Material, supplies and other $46 $46 
Commodity production in transit or storage
Total inventories$52 $48 
v3.19.1
Debt and Banking Arrangements (Tables)
3 Months Ended
Mar. 31, 2019
Debt Disclosure [Abstract]  
Debt
The following table presents a summary of our debt as of the dates indicated.
March 31,
2019
December 31,
2018
 (Millions)
Credit facility agreement$314 $330 
6.000% Senior Notes due 2022529 529 
8.250% Senior Notes due 2023500 500 
5.250% Senior Notes due 2024650 650 
5.750% Senior Notes due 2026500 500 
Total long-term debt$2,493 $2,509 
Less: Debt issuance costs on long-term debt(a)23 24 
 Total long-term debt, net(a)
$2,470 $2,485 
__________
(a)Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
v3.19.1
Provision (Benefit) for Income Taxes (Tables)
3 Months Ended
Mar. 31, 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 March 31,
 2019 2018 
 
Current:
Federal$— $— 
State(1)— 
(1)— 
Deferred:
Federal(12)(9)
State(1)(6)
(13)(15)
Total provision (benefit)$(14)$(15)
v3.19.1
Leases (Tables)
3 Months Ended
Mar. 31, 2019
Leases [Abstract]  
Lease, Cost [Table Text Block]
The following tables include quantitative disclosures related to our leases.
 Three months ended March 31, 2019
 (Millions)
Lease costs:
Leases recorded on the Consolidated Balance Sheet:
Operating lease cost—drilling rigs(a)$
Operating lease cost—other(a)
Variable lease cost—drilling rigs(a)— 
Variable lease cost—other(a)— 
Short-term leases:
Drilling rigs(b)10 
Other(b)30 
Total lease cost$53 
Other Information:
Cash paid for amount included in the measurement of lease liabilities:
Operating cash flows used for operating leases(a)$
Investing cash flows used for operating leases(a)$
Right-of-use assets obtained in exchange for new operating lease liabilities$21 
Weighted-average remaining lease term (in years)1.92 years
Weighted-average discount rate—operating leases%
__________
(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 March 31, 2019.
 Drilling RigsReal Estate, Compression and OtherTotal Undiscounted Cash Flows
 (Millions)
Maturity of Lease Liabilities:
April 2019 through December 2019$31 $12 $43 
202036 14 50 
202110 
2022— 
2023— — — 
Thereafter— — — 
$104 
Current lease liabilities$38 $15 $53 
Noncurrent lease liabilities29 17 46 
Total lease liabilities$67 $32 $99 
Difference between undiscounted cash flows and discounted cash flows$
Total right-of-use assets on Consolidated Balance Sheet$99 
v3.19.1
Fair Value Measurements (Tables)
3 Months Ended
Mar. 31, 2019
Fair Value Disclosures [Abstract]  
Assets and Liabilities Measured at Fair Value on Recurring Basis
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 March 31, 2019December 31, 2018
 Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
 (Millions)(Millions)
Energy derivative assets$— $92 $— $92 $— $175 $$178 
Energy derivative liabilities$— $166 $— $166 $— $37 $— $37 
Total debt(a)$— $2,590 $— $2,590 $— $2,414 $— $2,414 
__________
(a)The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,493 million and $2,509 million as of March 31, 2019 and December 31, 2018, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.
v3.19.1
Derivatives and Concentration of Credit Risk (Tables)
3 Months Ended
Mar. 31, 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 March 31, 2019.
CommodityPeriodContract Type (a)LocationNotional Volume (b)Weighted Average
Price (c)
Crude Oil
Crude OilApr - Dec 2019Fixed Price SwapsWTI(53,000)$54.62 
Crude OilApr - Dec 2019Basis SwapsMidland/Cushing
(21,338)$(1.23)
Crude OilApr - Dec 2019Basis SwapsNymex CMA Roll(17,818)$0.11 
Crude OilApr - Dec 2019Basis SwapsMagellan East Houston/Midland(2,444)$8.12 
Crude OilApr - Dec 2019Basis SwapsArgus LLS/Midland(1,113)$8.60 
Crude OilApr - Dec 2019Basis SwapsMagellan East Houston/Argus LLS(1,113)$0.75 
Crude OilApr - Dec 2019Basis SwapsClearbrook(3,673)$(2.99)
Crude OilApr - Dec 2019Fixed Price CallsWTI(5,000)$54.08 
Crude OilApr - Dec 2019Fixed Price CollarsWTI(8,000)$50.00 - $60.19
Crude Oil2020Fixed Price SwapsWTI(10,000)$57.22 
Crude Oil2020Basis SwapsMidland/Cushing(7,486)$(1.31)
Crude Oil2020Basis SwapsBrent/WTI Spread(5,000)$8.36 
Crude Oil2020Fixed Price CollarsWTI(10,000)$53.01 - $63.01
Crude Oil2021Basis SwapsBrent/WTI Spread(1,000)$8.00 
Crude Oil2022Basis SwapsBrent/WTI Spread(1,000)$7.75 
Natural Gas
Natural GasApr - Dec 2019Fixed Price SwapsHenry Hub(110)$3.07 
Natural GasApr - Dec 2019Basis SwapsPermian(25)$(0.39)
Natural GasApr - Dec 2019