WPX ENERGY, INC., 10-K filed on 2/21/2019
Annual Report
v3.10.0.1
Document and Entity Information - USD ($)
12 Months Ended
Dec. 31, 2018
Feb. 20, 2019
Jun. 30, 2018
Document Documentand Entity Information [Abstract]      
Document type 10-K    
Amendment flag false    
Document period end date Dec. 31, 2018    
Document fiscal year focus 2018    
Document fiscal period focus FY    
Trading symbol WPX    
Entity registrant name WPX ENERGY, INC.    
Entity central index key 0001518832    
Current fiscal year end date --12-31    
Entity well-known seasoned issuer Yes    
Entity current reporting status Yes    
Entity voluntary filers No    
Entity filer category Large Accelerated Filer    
Entity small business false    
Entity emerging growth company false    
Entity Shell Company false    
Entity common stock, shares outstanding   420,465,218  
Entity public float     $ 7,172,269,200
v3.10.0.1
Consolidated Balance Sheets - USD ($)
$ in Millions
Dec. 31, 2018
Dec. 31, 2017
Current assets:    
Cash and cash equivalents $ 3 $ 189
Accounts receivable, net of allowance 405 307
Derivative asset, current 174 36
Inventories 48 30
Assets classified as held for sale, current 79 811
Other 30 28
Total current assets 739 1,401
Long-term investments 167 70
Properties and equipment, net (successful efforts method of accounting) 7,266 6,691
Derivative asset, noncurrent 4 23
Other noncurrent assets 27 22
Total assets 8,203 8,207
Current liabilities:    
Accounts payable 514 446
Accrued liabilities and other liabilities 178 209
Liabilities associated with assets held for sale, current 0 20
Derivative liabilities 23 171
Total current liabilities 715 846
Deferred income taxes 201 117
Long-term debt and capital lease obligations [1] 2,485 2,575
Derivative liabilities 14 65
Other noncurrent liabilities 487 477
Contingent liabilities and commitments (Note 11)
Stockholders’ equity:    
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding at December 31, 2018 and 4.8 million shares outstanding at December 31, 2017) 0 232
Common stock (2 billion shares authorized at $0.01 par value; 420.6 million and 398.3 million shares issued and outstanding at December 31, 2018 and 2017) 4 4
Additional paid-in-capital 7,734 7,479
Accumulated deficit (3,437) (3,588)
Total equity 4,301 4,127
Total liabilities and equity $ 8,203 $ 8,207
[1] Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
v3.10.0.1
Consolidated Balance Sheets (Parenthetical) - $ / shares
Dec. 31, 2018
Dec. 31, 2017
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 4,800,000
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 420,600,000 398,300,000
v3.10.0.1
Consolidated Statements of Operations - USD ($)
shares in Millions, $ in Millions
3 Months Ended 12 Months Ended
Dec. 31, 2018
Sep. 30, 2018
Jun. 30, 2018
Mar. 31, 2018
Dec. 31, 2017
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Revenues:                      
Net gain (loss) on derivatives $ 443 $ (139) $ (154) $ (69) $ (210) $ (106) $ 116 $ 203 $ 81 $ 3 $ (207)
Other                 0 1 1
Total revenues 1,022 484 430 374 155 145 350 395 2,310 1,045 478
Costs and expenses:                      
Depreciation, depletion and amortization                 777 542 441
Lease and facility operating                 272 168 118
Taxes other than income                 157 79 43
Exploration                 75 87 26
General and administrative (including equity-based compensation) [1]                 182 166 202
Net (gain) loss on sales of assets and divestment of transportation contracts                 (3) (161) 239
Other—net                 7 15 15
Total costs and expenses 447 413 388 322 265 223 231 208 1,756 947 1,304
Operating income (loss) 575 71 42 52 (110) (78) 119 187 554 98 (826)
Interest expense                 (163) (188) (207)
Gain (Loss) on Extinguishment of Debt     (71)     (17)     (71) (17) (1)
Investment income (loss) and other                 (4) 3 2
Income (loss) from continuing operations before income taxes                 316 (104) (1,032)
Provision (benefit) for income taxes                 74 (128) (360)
Income (loss) from continuing operations 353 (6) (79) (26) (20) (378) 327 95 242 24 (672)
Income (loss) from discontinued operations 1 (1) (2) (89) (18) 232 (251) (3) (91) (40) 71
Net Income (Loss) 354 (7) (81) (115)         151 (16) (601)
Preferred stock dividends, income statement impact                 8 15 18
Preferred stock conversions, inducements                 0 0 22
Net income (loss) available to common stockholders, 354 (7) (85) (119) (42) (149) 72 88 143 (31) (641)
Amounts available to WPX Energy, Inc. common stockholders                      
Income (loss) from continuing operations attributable to WPX 353 (6) (83) (30) (24) (381) 323 91 234 9 (712)
Income (loss) from discontinued operations attributable to WPX $ 1 $ (1) $ (2) $ (89) $ (18) $ 232 $ (251) $ (3) $ (91) $ (40) $ 71
Income (loss) from continuing operations, per basic share $ 0.84 $ (0.01) $ (0.21) $ (0.07) $ (0.06) $ (0.96) $ 0.81 $ 0.24 $ 0.57 $ 0.02 $ (2.28)
Discontinued operation, income (loss) from discontinued operation, net of tax, per basic share 0 0 0 (0.23) (0.04) 0.58 (0.63) (0.01) (0.22) (0.10) 0.23
Earnings per share, basic 0.84 (0.01) (0.21) (0.30) (0.10) (0.38) 0.18 0.23 0.35 (0.08) (2.05)
Income (loss) from continuing operations, per diluted share 0.83 (0.01) (0.21) (0.07) (0.06) (0.96) 0.77 0.23 $ 0.57 $ 0.02 $ (2.28)
Basic weighted-average shares                 408.4 395.1 313.3
Discontinued operation, income (loss) from discontinued operation, net of tax, per diluted share 0 0 0 (0.23) (0.04) 0.58 (0.60) (0.01) $ (0.22) $ (0.10) $ 0.23
Earnings per share, diluted $ 0.83 $ (0.01) $ (0.21) $ (0.30) $ (0.10) $ (0.38) $ 0.17 $ 0.22 $ 0.35 $ (0.08) $ (2.05)
Diluted weighted-average shares(a) [2]                 411.7 397.4 313.3
Oil and Condensate [Member]                      
Revenues:                      
Revenue from contract with customer, including assessed tax                 $ 1,790 $ 879 $ 451
Natural Gas, Production [Member]                      
Revenues:                      
Revenue from contract with customer, including assessed tax                 87 67 35
Natural Gas Liquids [Member]                      
Revenues:                      
Revenue from contract with customer, including assessed tax                 148 70 21
Oil and Gas [Member]                      
Revenues:                      
Revenue from contract with customer, including assessed tax $ 544 $ 554 $ 520 $ 407 $ 356 $ 247 $ 226 $ 187 2,025 1,016 507
Oil and Gas, Refining and Marketing [Member]                      
Revenues:                      
Revenue from contract with customer, including assessed tax $ 36 $ 68 $ 64 $ 36 $ 8 $ 4 $ 8 $ 5 204 25 177
Costs and expenses:                      
Cost of Goods and Services Sold                 182 27 208
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]                      
Costs and expenses:                      
Cost of Goods and Services Sold                 $ 107 $ 24 $ 12
[1] General and administrative (including non-cash equity-based compensation of $32 million, $28 million and $31 million for the respective periods)
[2] Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:  
Years Ended December 31,
201820172016
(Millions)
Weighted-average nonvested restricted stock units and awards — — 2.2 
Weighted-average stock options— — 0.01 
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)
11.4 19.8 23.8 
Nonvested restricted stock units antidilutive under the treasury stock method
0.7 0.6 — 
v3.10.0.1
Consolidated Statements of Operations Consolidated Statements of Operations - Parentheticals - USD ($)
$ in Millions
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Employee Benefits and Share-based Compensation, Noncash [Abstract]      
Non-cash equity-based compensation expense $ 32 $ 28 $ 31
v3.10.0.1
Consolidated Statements of Changes in Equity - USD ($)
$ in Millions
Total
Total Stockholders’ Equity
Preferred Stock
Common Stock
Capital in Excess of Par Value
Accumulated Deficit
Balance At Beginning Of Period at Dec. 31, 2015   $ 3,535 $ 339 $ 3 $ 6,164 $ (2,971)
Comprehensive income:            
Net income (loss) attributable to WPX Energy, Inc. $ (601) (601)       (601)
Stock based compensation, net of tax impact   23     23  
Stock issued during period, value, new issues   538     538  
Conversion of stock, amount issued   11 (107)   118  
Adjustments to additional paid in capital, dividends in excess of retained earnings   (18)     (18)  
Preferred stock conversions, inducements (22) (22)     (22)  
Balance At End Of Period at Dec. 31, 2016   3,466 232 3 6,803 (3,572)
Comprehensive income:            
Net income (loss) attributable to WPX Energy, Inc. (16) (16)       (16)
Stock based compensation, net of tax impact   22     22  
Stock issued during period, value, new issues   670   1 669  
Adjustments to additional paid in capital, dividends in excess of retained earnings   (15)     (15)  
Preferred stock conversions, inducements 0          
Balance At End Of Period at Dec. 31, 2017   4,127 232 4 7,479 (3,588)
Comprehensive income:            
Net income (loss) attributable to WPX Energy, Inc. 151 151       151
Stock based compensation, net of tax impact   31     31  
Conversion of stock, amount issued   0 (232)   232  
Adjustments to additional paid in capital, dividends in excess of retained earnings   (8)     (8)  
Preferred stock conversions, inducements $ 0          
Balance At End Of Period at Dec. 31, 2018   $ 4,301 $ 0 $ 4 $ 7,734 $ (3,437)
v3.10.0.1
Consolidated Statements of Cash Flows - USD ($)
$ in Millions
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Operating Activities      
Net income (loss) $ 151 $ (16) $ (601)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Depreciation, depletion and amortization 785 673 631
Deferred income tax provision (benefit) 84 (134) (281)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments 73 158 38
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net 81 3 (207)
Derivative, Cost of Hedge Net of Cash Received (237) 4 302
Unrealized Loss on Derivatives, including Discontinued Operations 0 0 46
Amortization of stock-based awards 34 32 36
Loss on extinguishment of debt and acquisition bridge financing fees 71 17 1
Net (gains) losses on sales of assets and divestment of transportation contracts 145 (170) (29)
Cash provided by (used in) operating assets and liabilities:      
Accounts receivable (59) (153) 126
Inventories (15) (8) 10
Other current assets 2 (8) 5
Accounts payable 17 158 (72)
Federal Income Taxes receivable and payable (38) 12 (19)
Accrued and other current liabilities (22) (31) (45)
Increase (Decrease) in Other Accrued Liabilities (47) (53) (53)
Other, including changes in other noncurrent assets and liabilities 20 29 (34)
Net cash provided by operating activities(a) [1] 883 507 268
Investing Activities(a)      
Payments to Acquire Productive Assets 1,476 1,161 578
Proceeds from sales of assets 682 193 1,127
Proceeds (payments) related to divestment of transportation contracts 0 0 (238)
Payments to Acquire Businesses, Gross 0 799 0
Proceeds from joint venture formation 0 338 0
Purchases of or contributions to investments (102) (8) 0
Other 0 1 0
Net cash provided by (used in) investing activities(a) [1] (896) (1,436) 311
Financing Activities      
Proceeds from common stock 10 672 540
Dividends paid on preferred stock (11) (15) (18)
Payments related to induced conversion of preferred stock to common stock 0 0 (10)
Borrowings on credit facility 1,453 661 380
Payments on credit facility (1,123) (661) (645)
Proceeds from long-term debt, net of discount 494 148 0
Payments for retirement of long-term debt, including premium (986) (165) (356)
Taxes paid for shares withheld 14 12 6
Payments for debt issuance costs and credit facility amendment fees (10) (2) (5)
Other 17 (2) 0
Net cash provided by (used in) financing activities (170) 624 (120)
Net increase (decrease) in cash and cash equivalents and restricted cash (183) (305) 459
Cash and cash equivalents and restricted cash at beginning of period 201 506 47
Cash and cash equivalents and restricted cash at end of period 18 201 506
Increase to properties and equipment (1,510) (1,232) (584)
Changes In Related Accounts Payable And Accounts Receivable $ (34) $ (71) $ (6)
[1] (a) Amounts reflect continuing and discontinued operations unless otherwise noted.
v3.10.0.1
Consolidated Statements of Cash Flows (Parenthetical) - USD ($)
$ in Millions
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Increase to properties and equipment $ 1,510 $ 1,232 $ 584
Changes in related accounts payable and accounts receivable 34 71 6
Payments to Acquire Productive Assets $ 1,476 $ 1,161 $ 578
v3.10.0.1
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2018
Accounting Policies [Abstract]  
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3).
We had operations in the San Juan Basin which were sold in 2017 and 2018 that are reported in discontinued operations as discussed below. We also had other operations sold in 2016 which are reported as discontinued operations, as discussed below.
The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.”
Basis of Presentation and Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated. The Company has no other elements of comprehensive income (loss) other than net income (loss).
Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations 
On January 30, 2018, we signed an agreement to sell our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC for $700 million (subject to closing and post-closing adjustments). This sale closed in March 2018. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million, a portion of which closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. The assets and liabilities were reclassified as held for sale on the Consolidated Balance Sheet as of December 31, 2017 and the results of operations of the San Juan Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3).
Our discontinued operations also include the results of previously owned properties in the Piceance Basin.
See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
impairment assessments of long-lived assets;
valuation of deferred tax assets and liabilities;
valuations of derivatives;
estimation of oil and natural gas reserves; and
assessments of litigation-related contingencies.
 
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash was approximately $15 million and $12 million as of December 31, 2018 and 2017, respectively, and is included in other current assets on the Consolidated Balance Sheets.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories.
Years ended December 31,
20182017
(Millions)
Material, supplies and other$46 $29 
Commodity production in storage
$48 $30 

Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense on the Consolidated Statements of Operations. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs as unproved properties.
From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange in which commercial substance is established, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
Derivative Treatment  Accounting Method
Normal purchases and normal sales exception  Accrual accounting
Designated in a qualifying hedging relationship  Hedge accounting
All other derivatives  Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
Certain gains and losses on derivative instruments included on the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to commodity management and for which we have not elected the normal purchases and normal sales exception;
realized gains and losses on all derivatives that settle financially;
realized gains and losses on derivatives held for trading purposes; and
realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product and commodity management revenues
Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.
Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.
Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Significant judgments related to revenue recognition include principal versus agent considerations.
We record revenue on a gross basis when we control a promised good or service before transferring it to a customer. We record
revenue on a net basis when we arrange for another company to provide the good or service. Determining the point and time when control of a product transfers to a customer requires significant judgment. Payment is typically due 30 to 45 days following delivery of product to our customers. 
Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2018 and 2017 was insignificant.
Commodity management expenses
Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million in 2016.
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.
Employee stock-based compensation
Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Performance-based awards are tied to shareholder return over time relative to our peer group and are valued using a Monte Carlo method using measures of total shareholder return.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units and awards (see Note 4).
Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $35 million and $32 million as of December 31, 2018 and 2017, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets. 
Recently Adopted Accounting Standards
The Company adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at December 31, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are
wholly unsatisfied at the reporting period end. In addition, see Note 16 for receivables related to sales of oil, natural gas and related products and services.
We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $15 million, $12 million and $10 million as of December 31, 2018, 2017 and 2016, respectively.
We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.
We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.
Accounting Standards Not Yet Adopted
In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on review of the guidance and the Company’s current commitments, the Company believes it will be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and other arrangements. In 2018, we began the process of evaluating our contracts with components that may be subject to ASU 2016-02 and engaged a third party to assist with implementing the standard. In 2018 and 2019, we have implemented appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company is finalizing the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We believe the amounts recorded as right to use assets and lease payment liabilities will be less than $100 million.
In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to exclude from evaluation any land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. The amendments affect trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with and expected loss model for instruments measured at amortized cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update 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 standard 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 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
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 Update 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.
v3.10.0.1
Acquisitions
12 Months Ended
Dec. 31, 2018
Acquisition [Abstract]  
Mergers, Acquisitions and Dispositions Disclosures [Text Block] AcquisitionOn January 12, 2017, we signed an agreement to acquire certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”) for $775 million, subject to post-closing adjustments. The transaction closed in March 2017 for $798 million including estimated closing adjustments. The assets, as of the closing date, included 25 producing wells (18 horizontals), three drilled but uncompleted horizontal laterals, approximately 18,000 net acres and more than 900 gross undeveloped locations in the Delaware Basin. We estimated that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved developed properties and facilities. This estimate is based on discounted cash flow models, which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. These assumptions represent Level 3 inputs. At the time of the acquisition closing, production was approximately 10,000 Boe per day. The impact of this acquisition to prior periods is not material to our results of operations for those periods.
v3.10.0.1
Discontinued Operations
12 Months Ended
Dec. 31, 2018
Discontinued operations [Abstract]  
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] Discontinued Operations
On January 30, 2018, we signed an agreement to sell our operations in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC (“Enduring”) for $700 million (subject to closing and post-closing adjustments). The transaction closed on March 28, 2018 and we received approximately $667 million (subject to post-closing adjustments). In 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 believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and Enduring and the declining size of the obligations subject to the guarantee over time. Although we believe the probability of performance by WPX is low, we must 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. The operations in the San Juan Gallup represented 12 percent of our total proved reserves at December 31, 2017 and 16 percent of our total production for 2017.
In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million and recorded a gain of approximately $2 million. A portion of the San Juan Legacy sale closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin.
Significant transactions for the San Juan Basin operations reflected in the tables below are as follows:
In the third quarter of 2017, we began a process to market our San Juan Legacy properties and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value at September 30, 2017 which resulted in an impairment of $60 million recorded in third-quarter 2017. At the close of the sale, we recorded a gain of $2 million.
On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million. The consideration reflected $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX’s development in the Gallup oil play. We were obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and additional gains of $18 million in the subsequent quarters of 2016 as certain in-progress construction was completed. As of December 31, 2017, the remaining deferred gain was approximately $3 million.
On February 8, 2016, we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations for $910 million. The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million, subject to post-closing adjustments, resulting in a gain of $52 million. We performed certain transition services for the buyer which concluded during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in commodity management revenue and expenses.
We sold our Powder River Basin properties in 2015; however, we retained certain firm gathering and treating obligations that continue through 2020 related to the Powder River properties sold. These commitments had been in excess of the production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company that continue through 2021. We recorded liabilities related to these commitments in 2015. In 2017, we increased the liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 11 for additional information related to these liabilities.
Summarized Results of Discontinued Operations
The following table presents the results of discontinued operations for the years presented.
Years Ended December 31,
201820172016
 (Millions)
Total revenues$75 $291 $279 
Costs and expenses:
Depreciation, depletion and amortization$$131 $191 
Lease and facility operating50 63 
Gathering, processing and transportation12 70 113 
Taxes other than income23 19 
Exploration14 16 
General and administrative21 
Accrual for contract obligations retained— — 
Net (gain) loss—sales of assets and impairments— 50 (217)
Accretion of liabilities related to contract obligations retained
Other—net(a)(3)
Total costs and expenses47 354 215 
Operating income (loss)28 (63)64 
Gain (loss) on sales of domestic assets
(148)— 51 
Income (loss) from discontinued operations before income taxes(120)(63)115 
Provision (benefit) for income taxes(29)(23)44 
Income (loss) from discontinued operations$(91)$(40)$71 
 __________
(a) Includes severance tax refund received in 2017.
Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
 December 31,
 2017
 (Millions)
Assets classified as held for sale
Inventories$14 
Properties and equipment, net (successful efforts method of accounting)797 
Total assets classified as held for sale on the Consolidated Balance Sheets$811 
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable$
Accrued and other current liabilities
Total current liabilities
Asset retirement obligations15 
Other noncurrent liabilities
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets$20 
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 $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.
Years Ended December 31,
201820172016
 (Millions)
Cash provided by operating activities(a)$44 $143 $102 
Cash capital expenditures within investing activities$29 $175 $135 
 __________
(a) Excluding income taxes and changes to working capital.
v3.10.0.1
Earnings (Loss) Per Common Share from Continuing Operations
12 Months Ended
Dec. 31, 2018
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.
 Years Ended December 31,
 201820172016
 (Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.$242 $24 $(672)
Less: Dividends on preferred stock 15 18 
Less: Loss on induced conversion of preferred stock  — — 22 
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income (loss) per common share
$234 $$(712)
Basic weighted-average shares408.4 395.1 313.3 
Effect of dilutive securities(a):
Nonvested restricted stock units and awards3.1 2.1 — 
Stock options0.2 0.2 — 
Diluted weighted-average shares(a)411.7 397.4 313.3 
Income (loss) per common share from continuing operations:
Basic$0.57 $0.02 $(2.28)
Diluted$0.57 $0.02 $(2.28)
 __________
(a) Certain amounts 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 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 excluded amounts are as follows:  
Years Ended December 31,
201820172016
(Millions)
Weighted-average nonvested restricted stock units and awards — — 2.2 
Weighted-average stock options— — 0.01 
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)
11.4 19.8 23.8 
Nonvested restricted stock units antidilutive under the treasury stock method
0.7 0.6 — 
The table below includes information related to stock options that were outstanding at December 31, 2018, 2017 and 2016 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
December 31,
 201820172016
Options excluded (millions)0.7 1.5 2.0 
Weighted-average exercise price of options excluded$18.05 $17.80 $17.42 
Exercise price range of options excluded$16.46 - $21.81$14.41 - $21.81$14.41 - $21.81
Fourth quarter weighted-average market price$15.16 $12.10 $13.23 
v3.10.0.1
Asset Sales, Impairments and Exploration Expenses
12 Months Ended
Dec. 31, 2018
Extractive Industries [Abstract]  
Asset Sales,Other Expenses and Exploration Expenses Asset Sales and Exploration Expenses
Asset Sales
2017
Net gain on sales of assets for the year ended December 31, 2017 primarily reflect total gains of $103 million from exchanges of leasehold acreage in the Permian Basin, $48 million from the recognition of deferred gains related to the completion of commitments from the sale in 2015 of a North Dakota gathering system and $8 million recognized on the sales of certain Green River Basin and Appalachian Basin assets.
In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs.
2016
During July 2016, we completed the divestment of the remaining transportation contracts primarily related to our Piceance Basin operations which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment. As a result of the divestment and net payment of $238 million, we recorded a net loss of $238 million in third-quarter 2016.
Exploration Expenses
The following table presents a summary of exploration expenses.
 Years Ended December 31,
 201820172016
 (Millions)
Unproved leasehold property impairments, amortization and expiration$69 $84 $22 
Geologic and geophysical costs$
Impairments of exploratory area well costs and dry hole costs— — 
Total exploration expenses$75 $87 $26 
Unproved leasehold property impairment, amortization and expiration for 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Permian Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.
v3.10.0.1
Investments
12 Months Ended
Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]  
Equity Method Investments and Joint Ventures Disclosure [Text Block] Investments
In June 2017, we signed an agreement with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the agreement, WPX and Howard each have a 50 percent voting interest in the newly formed joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity will serve as operator. In addition to a $300 million cash contribution, Howard is obligated to fund the first $263 million of joint venture capital expenditures. At closing in October 2017, WPX contributed subsidiaries holding crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $53 million. WPX also paid $11 million for advisory services and legal fees on the transaction. Howard contributed $439 million in cash at closing, $139 million of which applies to the $263 million carry obligation of Howard including $49 million for capital expenditures from January 1, 2017 to closing. Concurrently, WPX received a $300 million special distribution plus the $49 million for capital expenditures from Catalyst. We will account for our investment in Catalyst as an equity method investment. In connection with the joint venture, a consolidated subsidiary of WPX dedicated production from its current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to 20 year fixed-fee oil gathering and natural gas processing agreements with subsidiaries of Catalyst. The agreements do not include any minimum volume commitments. Our investment in Catalyst totaled $58 million and $64 million as of December 31, 2018 and 2017, respectively. In 2017, we deferred recognition of the $349 million and will recognize it over the 20 years based on production volumes as a deduction to gathering, processing and transportation expense. As of December 31, 2018, the deferred amount was $346 million of which $336 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.
During 2018, we contributed an additional $93 million to our equity method investment in the Oryx II pipeline project, of which $23 million increased our ownership from 12.5 percent to 25 percent.
v3.10.0.1
Properties and Equipment
12 Months Ended
Dec. 31, 2018
Property, Plant and Equipment [Abstract]  
Properties and Equipment Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
 
Estimated
Useful
Life(a)
(Years)
December 31,
 20182017
  (Millions)
Proved properties(b)$7,289 $5,815 
Unproved properties(c)1,891 2,194 
Gathering, processing and other facilities15-25294 242 
Construction in progress(c)350 305 
Other3-40125 118 
Total properties and equipment, at cost9,949 8,674 
Accumulated depreciation, depletion and amortization(2,683)(1,983)
Properties and equipment—net$7,266 $6,691 
__________
(a) Estimated useful lives are presented as of December 31, 2018.
(b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c) Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.
In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 17).
Asset Retirement Obligations 
Our asset retirement obligations relate to producing wells, gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment. Asset retirement obligations are reported in other noncurrent liabilities on the Consolidated Balance Sheets.
A rollforward of our asset retirement obligations for the years ended 2018 and 2017 is presented below.
 
20182017
 (Millions)
Balance, January 1$39 $40 
Liabilities incurred
Liabilities settled(7)(11)
Estimate revisions30 
Accretion expense(a)
Balance, December 31$72 $39 
Amount reflected as current$$
__________
(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
v3.10.0.1
Accounts Payable and Accrued and Other Current Liabilities
12 Months Ended
Dec. 31, 2018
Payables and Accruals [Abstract]  
Accounts Payable and Accrued and Other Current Liabilities Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
The following table presents a summary of our accounts payable as of the dates indicated below.
 December 31,
 20182017
 (Millions)
Trade$130 $120 
Accrual for capital expenditures190 151 
Royalties170 150 
Cash overdrafts17 — 
Other25 
$514 $446 
Accrued and other current liabilities
The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.
 December 31,
 20182017
 (Millions)
Taxes other than income taxes$19 $14 
Accrued interest45 69 
Compensation and benefit related accruals39 39 
Gathering and transportation 11 
Gathering and transportation related to exited areas 30 53 
Other, including other loss contingencies38 23 
$178 $209 
v3.10.0.1
Debt and Banking Arrangements
12 Months Ended
Dec. 31, 2018
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 below.
 December 31,
 2018 (a)2017 (a)
 (Millions)
Credit facility agreement $330 $— 
7.500% Senior Notes due 2020— 350 
6.000% Senior Notes due 2022529 1,100 
8.250% Senior Notes due 2023500 500 
5.250% Senior Notes due 2024650 650 
5.750% Senior Notes due 2026500 — 
Total debt
$2,509 $2,600 
Less: Current portion of long-term debt— — 
Total long-term debt
$2,509 $2,600 
Less: Debt issuance costs(b) 24 25 
Total long-term debt, net(b)
$2,485 $2,575 
__________
(a) Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.
(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Credit Facility
On April 17, 2018, the Company entered into a Second Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, increases total commitments to $1.5 billion, increases the Borrowing Base to $1.8 billion, and extends the maturity date to April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2018, WPX had $330 million borrowings outstanding, had $52 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement.
Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. In October 2018, the Borrowing Base was increased to $2.0 billion and will remain in effect until the next Redetermination Date as set forth in the Credit Facility. At this time, the Credit Facility Agreement is limited by the total commitments on the Credit Facility which remained at $1.5 billion. The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.
Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.
The Collateral Trigger Termination Date is the first date following the Second Amendment Effective Date and the first date following any Collateral Trigger Date, as applicable, on which:
1.(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or
2.in the case of a Voluntary Collateral Trigger Period, WPX elects to cause a Collateral Trigger Termination Date to occur.
Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings.
Significant Financial Covenants.
Currently, the Company is required to maintain:
ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 4.25 to 1.00 as of the last day of the Rolling Period; and
a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.
If a Collateral Trigger Termination Date occurs, other financial covenants would apply.
Covenants. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit,
among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties.
Events of Default. The Credit Facility includes customary events of default, including events of default relating to:
non-payment of principal, interest or fees;
inaccuracy of representations and warranties in any material respect when made or when deemed made;
violation of covenants;
cross payment-defaults;
cross acceleration;
bankruptcy and insolvency events;
certain unsatisfied judgments;
a change of control; and
during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.
If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2018.  
Senior NoteFace Value (Millions)Maturity DateInterest Payment DatesOptional Redemption Period(a)
6.000% Senior Notes due 2022 (the “2022 Notes”) $529 January 15, 2022January 15, July 15October 15, 2021
8.250% Senior Notes due 2023 (the “2023 Notes”) $500 August 1,
2023
February 1, August 1June 1, 2023
5.250% Senior Notes due 2024 (the “2024 Notes”) $650 September 15, 2024March 15, September 15June 15, 2024
5.750% Senior Notes due 2026 (the “2026 Notes”) $500 June 1,
2026
June 1, December 1June 1, 2021
 __________
(a) At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.
In the second quarter of 2018, we used proceeds from our San Juan Gallup disposition and the issuance of new senior notes discussed below to retire $921 million aggregate principal amount of our senior notes ($350 million due 2020 and $571 million due 2022) through a series of cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $71 million, which includes approximately $63 million of premium and approximately $6 million write-off of previously capitalized costs.
On May 23, 2018, we completed a debt offering of $500 million of 5.750% Senior Notes due in 2026 (the “2026 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on June 1 and December 1 of each year commencing on December 1, 2018. The 2026 Notes will mature on June 1, 2026 with the option, prior to June 1, 2021, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, after June 1, 2021, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2026 Notes was approximately $494 million and approximately $1 million of debt issuance costs were capitalized.
During third-quarter 2017, we issued an additional $150 million of our 5.250% senior notes due 2024. The proceeds were used to fund the tender offer of $150 million of our 7.500% senior notes due 2020. As a result, we recorded a loss on extinguishment of debt of $17 million.
The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes and 2026 Notes are substantially identical.
Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:
(1) a default in the payment of interest on the notes when due that continues for 30 days;
(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity,
upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in
clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
v3.10.0.1
Provision (Benefit) for Income Taxes
12 Months Ended
Dec. 31, 2018
Income Tax Disclosure [Abstract]  
Provision (Benefit) for Income Taxes Provision (Benefit) for Income Taxes
The following table includes the provision (benefit) for income taxes from continuing operations.
 Years Ended December 31,
 201820172016
 (Millions)
Provision (benefit):
Current:
Federal$(38)$(18)$(26)
State(7)
(37)(17)(33)
Deferred:
Federal107 (100)(333)
State(11)
111 (111)(327)
Total provision (benefit)$74 $(128)$(360)
 
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Act”). The income tax effects of changes in tax laws are recognized in the period when enacted. The Act repealed the corporate alternative minimum tax (“AMT”) and amended Section 53 of the Internal Revenue Code to allow for refunds of AMT credit carryforwards. Under Section 53(e), taxpayers receive 50 percent of their uncredited balance in years 2018–2020. Taxpayers receive 100 percent of the remaining balance in 2021. Accordingly, the Company recorded a current receivable of $38 million as of December 31, 2018 related to AMT credit refunds expected to be collected in 2019. However, our AMT credit carryforwards are subject to change based on the results of the 2011 Williams audit discussed below and may impact future refunds.
The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.
 Years Ended December 31,
 201820172016
 (Millions)
Federal Statutory Rate21 %35 %35 %
Provision (benefit) at statutory rate$66 $(36)$(361)
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)(8)(12)(42)
Valuation allowance on current year state income taxes (net of federal
  benefit)
17 17 18 
Valuation allowance on state income taxes resulting from sale (net of
  federal benefit)
— — 
Effective state income tax rate change (net of federal benefit)(5)(12)15 
Provisional impact of Tax Cuts and Jobs Act— (92)— 
Other
Provision (benefit) for income taxes$74 $(128)$(360)
As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years. As a result of the sale of our Piceance Basin operations in Colorado in the second quarter of 2016, we recorded $8 million of valuation allowances against Colorado NOL and credit carryovers generated in prior years.
Significant changes to our operations during 2018, 2017 and 2016 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we recorded an additional $5 million and $12 million deferred tax benefit in 2018 and 2017, respectively. We also accrued an additional $15 million of deferred tax expense in 2016.
Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allowed us to provide a provisional estimate of the impacts of the Act in our earnings for the year ending December 31, 2017. Additional impacts from the enactment of the Act were allowed to be recorded as they were identified during the one-year measurement period as provided for in SAB 118. Accordingly, the Company did not have any adjustments to its provisional amounts.
The following table includes significant components of deferred tax liabilities and deferred tax assets.
 December 31,
 20182017
 (Millions)
Deferred tax liabilities:
Properties and equipment$797 $792 
Derivatives, net33 — 
Other, net— 
Total deferred tax liabilities830 793 
Deferred tax assets:
Accrued liabilities and other137 79 
Alternative minimum tax credits40 78 
Loss carryovers665 672 
Derivatives, net— 42 
Total deferred tax assets842 871 
Less: valuation allowance213 195 
Total net deferred tax assets629 676 
Net deferred tax liabilities$201 $117 
Net cash payments (refunds) for income taxes were $2 million, $(39) million and $21 million in 2018, 2017 and 2016, respectively.
The Company has federal NOL carryovers of approximately $2,021 million at December 31, 2018, including a $353 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, we have $48 million of federal capital loss carryovers at December 31, 2018, that will begin to expire in 2020. 
The Company has state NOL carryovers of approximately $4.1 billion and $3.8 billion at 2018 and 2017, respectively, of which more than 99 percent expire after 2029.
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. As of December 31, 2018, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss may result in the need for a valuation allowance on our deferred tax assets.
The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of December 31, 2018, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI NOL that arose prior to the acquisition.
Pursuant to our tax sharing agreement with The Williams Companies ("Williams"), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. The IRS has proposed an adjustment related to our business for which a payment to Williams could be required. We have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the 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.
The Company files a consolidated federal income tax return and several state income tax returns. The Company’s federal income tax returns for tax years 2014 through 2016 remain open for examination. The statute of limitations for most states expires one year after expiration of the IRS statute. During the year ended December 31, 2017, the IRS began an examination of the Company’s 2014, 2015 and 2016 federal income tax returns. In addition, the IRS began an examination of RKI’s 2014 and short-period 2015 federal income tax returns. These examinations remain ongoing and no additional taxes or refunds have been recorded at this time.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are less than $1 million for 2018 and 2017. The impact of this accrual is included within Other in our reconciliation of the provision (benefit) at statutory rate to recorded provision (benefit) for income taxes.
As of December 31, 2018, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.
v3.10.0.1
Contingent Liabilities and Commitments
12 Months Ended
Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]  
Contingent Liabilities and Commitments 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. At this time, we believe that our royalty calculations were properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
 Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to many of our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has 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. Final documents have not been finalized and approved by 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 December 31, 2018, 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 December 31, 2018 and December 31, 2017, 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 
We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our oil and natural gas production and third-party purchases of oil and natural gas to other locations in an attempt to obtain more favorable pricing differentials. During 2017 and 2018, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. As of December 31, 2018, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:
 
Midstream ServicesTransportationTotal
 (Millions)
2019$55 $115 $170 
202058 95 153 
202148 68 116 
202243 59 102 
202340 47 87 
Thereafter68 352 420 
Total commitments$312 $736 $1,048 
Accrued liabilities$24 $40 $64 
Our midstream service commitments will be settled over approximately seven years.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2018, are payable as follows:
(Millions)
2019$38 
202037 
202112 
2022
2023— 
Thereafter— 
 
Total$90 
Total rent expense, excluding amounts capitalized, was $25 million, $19 million and $23 million in 2018, 2017 and 2016, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
v3.10.0.1
Employee Benefit Plans
12 Months Ended
Dec. 31, 2018
Postemployment Benefits [Abstract]  
Employee Benefit Plans Employee Benefit PlansWPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $10 million, $11 million and $13 million for 2018, 2017 and 2016, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2018, and 2017 related to the non-matching annual employer contribution.
v3.10.0.1
Stock-Based Compensation
12 Months Ended
Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]  
Stock-Based Compensation Stock-Based Compensation
We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units and awards for purposes of this footnote). During 2018, the 2013 Incentive Plan was amended to authorize an additional 7.4 million shares for issuance under the plan. At December 31, 2018, 18 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 12 million shares were available for future grants. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.
Total stock-based compensation expense was $32 million, $28 million and $31 million for of the years ended December 31, 2018, 2017 and 2016, respectively, and is reflected in general and administrative expense. Measured but unrecognized stock-based compensation expense related to restricted stock units and awards at December 31, 2018 was $40 million and is expected to be recognized over a weighted-average period of 2.6 years. There was no unrecognized stock-based compensation expense related to stock options at December 31, 2018.
The ESPP allows employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. During 2018, the ESPP was amended to replenish the number of shares of our common stock that may be issued under the ESPP by 750 thousand. Offering periods are from January through June and from July through December. Employees purchased 97 thousand shares at an average price of $10.74 per share during 2018.
Nonvested Restricted Stock Units and Awards
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2018.
Restricted Stock UnitsShares
Weighted-
Average
Fair Value(a)
 (Millions) 
Nonvested at December 31, 20175.7 $12.06 
Granted2.4 $16.74 
Forfeited(0.1)$12.63 
Vested(2.6)$10.18 
Nonvested at December 31, 20185.4 $15.01 
__________
(a) Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.
Other restricted stock unit information
 201820172016
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$16.74 $13.76 $10.99 
Total fair value of restricted stock units vested during the year (millions) $26 $33 $37 
Performance-based shares granted represent 36 percent of nonvested restricted stock units outstanding at December 31, 2018. These grants may be earned at the end of a three year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established.
Based on the extent to which certain financial targets are achieved, vested shares may range from zero to 200 percent of the original grant amount.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2018.
Stock OptionsOptions
Weighted-
Average
Exercise
Price
Weighted-Average Remaining Contractual Life
Aggregate
Intrinsic
Value
 (Millions) (Years)(Millions)
Outstanding at December 31, 20172.2 $15.35 $
Granted— $— 
Exercised(0.8)$12.35 
Forfeited(0.3)$20.19 
Outstanding at December 31, 20181.1 $16.00 2.2$0.3 
Exercisable at December 31, 20181.1 $16.00 2.2$0.3 

The total intrinsic value of options exercised was $4.3 million, $224 thousand and $160 thousand for the years ended December 31, 2018, 2017 and 2016, respectively.
Cash received from stock option exercises was $9.2 million, $0.4 million and $0.4 million during 2018, 2017 and 2016, respectively.
The Company did not grant stock options during the years ended 2018, 2017 and 2016.
v3.10.0.1
Stockholders' Equity
12 Months Ended
Dec. 31, 2018
Equity [Abstract]  
Stockholders' Equity Stockholders’ Equity
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.
Series A Mandatory Convertible Preferred Stock
On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our Preferred Stock at $50 per share, for gross proceeds of approximately $350 million, before underwriting discounts and commissions. Dividends on our Preferred Stock were paid in cash on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018. 
On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our Preferred Stock, pursuant to which each of the Preferred Holders agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders agreed to convert an aggregate of approximately 2.2 million shares of Preferred Stock into approximately 10.2 million shares of our common stock in the Conversion, and we made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million in 2016. 
On July 30, 2018, all of the outstanding shares, approximately 4.8 million, of our preferred stock converted into approximately 19.8 million shares of our common stock pursuant to the mandatory conversion provisions of the preferred stock offering.
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at
such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2018, 2017 or 2016. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Subject to certain exceptions, so long as any share of our Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Preferred Stock.
On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
On January 12, 2017, we completed an underwritten public offering of 51.675 million shares of our common stock, which included 6.675 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $12.97 per share and we received proceeds of approximately $670 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. We used these proceeds, and cash on hand, to close the Panther Acquisition (see Note 2).
v3.10.0.1
Fair Value Measurements
12 Months Ended
Dec. 31, 2018
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars, calls or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.
Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash and margin deposits approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 December 31, 2018December 31, 2017
 Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
 (Millions)(Millions)
Energy derivative assets$— $175 $$178 $— $59 $— $59 
Energy derivative liabilities$— $37 $— $37 $— $236 $— $236 
Total debt(a)$— $2,414 $— $2,414 $— $2,746 $— $2,746 
__________
(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,509 million and $2,600 million as of December 31, 2018 and 2017, respectively.
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, calls or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil and natural gas swaps entered into, we granted swaptions and calls to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling $3 million included in Level 3 as of December 31, 2018. There were no instruments included in Level 3 as of December 31, 2017.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1, Level 2 and Level 3 occurred during the years ended December 31, 2018 or 2017.
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues on our Consolidated Statements of Operations.
Other
In addition to the items discussed below, we performed other nonrecurring fair value assessments as discussed in Note 2.
2017
In conjunction with the $103 million of gains from exchanges of leasehold during 2017, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs. The total fair value of leasehold exchanges in 2017 approximated $200 million. See Note 5 for additional discussion related to leasehold exchanges.
In addition, during the third quarter of 2017, we began a process to market our natural gas-producing properties in the San Juan Basin and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value which resulted in an impairment of $60 million recorded in the third-quarter of 2017. See Note 3 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin reported as discontinued operations.
v3.10.0.1
Derivatives and Concentration of Credit Risk
12 Months Ended
Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [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 swaptions.
Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2018.
CommodityPeriodContract Type (a)LocationNotional Volume (b)
Weighted Average
Price (c)
Crude Oil
Crude Oil2019Fixed Price SwapsWTI(38,000)$53.49 
Crude Oil2019Basis SwapsMidland/Cushing(21,008)$(1.16)
Crude Oil