Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 26, 2020 | Jun. 30, 2019 | |
Document Documentand Entity Information [Abstract] | |||
Document type | 10-K | ||
Document Annual Report | true | ||
Document period end date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 1-35322 | ||
Entity registrant name | WPX Energy, Inc. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 45-1836028 | ||
Entity Address, Address Line One | 3500 One Williams Center | ||
Entity Address, City or Town | Tulsa, | ||
Entity Address, State or Province | OK | ||
Entity Address, Postal Zip Code | 74172-0172 | ||
City Area Code | 855 | ||
Local Phone Number | 979-2012 | ||
Title of 12(b) Security | Common Stock, $0.01 par value | ||
Trading symbol | WPX | ||
Security Exchange Name | NYSE | ||
Entity well-known seasoned issuer | Yes | ||
Entity voluntary filers | No | ||
Entity current reporting status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity filer category | Large Accelerated Filer | ||
Entity small business | false | ||
Entity emerging growth company | false | ||
Entity Shell Company | false | ||
Entity public float | $ 4,310,692,615 | ||
Entity common stock, shares outstanding | 417,011,573 | ||
Amendment flag | false | ||
Document fiscal year focus | 2019 | ||
Document fiscal period focus | FY | ||
Entity central index key | 0001518832 | ||
Current fiscal year end date | --12-31 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Current assets: | |||
Cash and cash equivalents | $ 60 | $ 3 | |
Accounts receivable, net of allowance | 450 | 405 | |
Derivative asset, current | 57 | 174 | |
Inventories | 41 | 48 | |
Assets classified as held for sale, current | 0 | 79 | |
Other | 39 | 30 | |
Total current assets | 647 | 739 | |
Long-term investments | 48 | 167 | |
Properties and equipment, net (successful efforts method of accounting) | 7,590 | 7,266 | |
Derivative asset, noncurrent | 10 | 4 | |
Other noncurrent assets | 118 | 27 | |
Total assets | 8,413 | 8,203 | |
Current liabilities: | |||
Accounts payable | 556 | 514 | |
Accrued liabilities and other liabilities | 251 | 178 | |
Derivative liabilities | 91 | 23 | |
Total current liabilities | 898 | 715 | |
Deferred income taxes | 290 | 201 | |
Long-term debt | [1] | 2,202 | 2,485 |
Derivative liabilities | 0 | 14 | |
Other noncurrent liabilities | 508 | 487 | |
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, 2019 and 2018) | 0 | 0 | |
Common stock (2 billion shares authorized at $0.01 par value; 416.8 million and 420.6 million shares issued and outstanding at December 31, 2019 and 2018) | 4 | 4 | |
Additional paid-in-capital | 7,692 | 7,734 | |
Accumulated deficit | (3,181) | (3,437) | |
Stockholders' Equity Attributable to Parent, Total | 4,515 | 4,301 | |
Total liabilities and equity | $ 8,413 | $ 8,203 | |
[1] | Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 100,000,000 | 100,000,000 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares issued and outstanding | 416,800,000 | 420,600,000 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Revenues: | ||||
Net gain (loss) on derivatives | $ (153) | $ 81 | $ 3 | |
Other | 4 | 0 | 1 | |
Total revenues | 2,292 | 2,310 | 1,045 | |
Costs and expenses: | ||||
Depreciation, depletion and amortization | 928 | 777 | 542 | |
Lease and facility operating | 374 | 272 | 168 | |
Taxes other than income | 178 | 157 | 79 | |
Exploration | 95 | 75 | 87 | |
General and administrative (including equity-based compensation) | [1] | 206 | 182 | 166 |
Net gain on sales of assets (Note 4) | 0 | (3) | (161) | |
Acquisition Costs, Period Cost | 3 | 0 | 0 | |
Other—net | 18 | 7 | 15 | |
Costs and Expenses, Total | 2,148 | 1,756 | 947 | |
Operating income (loss) | 144 | 554 | 98 | |
Interest expense | (159) | (163) | (188) | |
Gain (Loss) on Extinguishment of Debt | (47) | (71) | (17) | |
Equity Method Investment, Realized Gain (Loss) on Disposal | 380 | 0 | 0 | |
Income (Loss) from Equity Method Investments | 9 | (6) | 0 | |
Investment income (loss) and other | 1 | 2 | 3 | |
Income (loss) from continuing operations before income taxes | 328 | 316 | (104) | |
Provision (benefit) for income taxes | 70 | 74 | (128) | |
Income (loss) from continuing operations | 258 | 242 | 24 | |
Income (loss) from discontinued operations | (2) | (91) | (40) | |
Net Income (Loss) | 256 | 151 | (16) | |
Preferred stock dividends, income statement impact | 0 | 8 | 15 | |
Net income (loss) available to common stockholders, | 256 | 143 | (31) | |
Amounts available to WPX Energy, Inc. common stockholders | ||||
Income (loss) from continuing operations attributable to WPX | 258 | 234 | 9 | |
Income (loss) from discontinued operations attributable to WPX | $ (2) | $ (91) | $ (40) | |
Income (loss) from continuing operations, per basic share | $ 0.62 | $ 0.57 | $ 0.02 | |
Discontinued operation, income (loss) from discontinued operation, net of tax, per basic share | (0.01) | (0.22) | (0.10) | |
Earnings per share, basic | $ 0.61 | $ 0.35 | $ (0.08) | |
Basic weighted-average shares | 420.4 | 408.4 | 395.1 | |
Income (loss) from continuing operations, per diluted share | $ 0.61 | $ 0.57 | $ 0.02 | |
Discontinued operation, income (loss) from discontinued operation, net of tax, per diluted share | 0 | (0.22) | (0.10) | |
Earnings per share, diluted | $ 0.61 | $ 0.35 | $ (0.08) | |
Diluted weighted-average shares(a) | [2] | 422 | 411.7 | 397.4 |
Oil and Condensate [Member] | ||||
Revenues: | ||||
Revenue from contract with customer, including assessed tax | $ 2,050 | $ 1,790 | $ 879 | |
Natural Gas, Production [Member] | ||||
Revenues: | ||||
Revenue from contract with customer, including assessed tax | 75 | 87 | 67 | |
Natural Gas Liquids [Member] | ||||
Revenues: | ||||
Revenue from contract with customer, including assessed tax | 122 | 148 | 70 | |
Oil and Gas [Member] | ||||
Revenues: | ||||
Revenue from contract with customer, including assessed tax | 2,247 | 2,025 | 1,016 | |
Oil and Gas, Refining and Marketing [Member] | ||||
Revenues: | ||||
Revenue from contract with customer, including assessed tax | 194 | 204 | 25 | |
Costs and expenses: | ||||
Cost of Goods and Services Sold | 163 | 182 | 27 | |
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | ||||
Costs and expenses: | ||||
Cost of Goods and Services Sold | $ 183 | $ 107 | $ 24 | |
[1] | General and administrative (including non-cash equity-based compensation of $34 million, $32 million and $28 million for the respective periods) | |||
[2] | Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (ii) application of the treasury stock method to certain nonvested restricted stock units. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows: Years Ended December 31, 2019 2018 2017 (Millions) Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock Not 11.4 19.8 Nonvested restricted stock units antidilutive under the treasury stock method 1.0 0.7 0.6 |
Consolidated Statements of Op_2
Consolidated Statements of Operations Consolidated Statements of Operations - Parentheticals - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract] | |||
Non-cash equity-based compensation expense | $ 34 | $ 32 | $ 28 |
Consolidated Statements of Chan
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, 2016 | $ 3,466 | $ 232 | $ 3 | $ 6,803 | $ (3,572) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
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 | |||
Dividends on preferred stock | (15) | (15) | ||||
Balance At End Of Period at Dec. 31, 2017 | 4,127 | 232 | 4 | 7,479 | (3,588) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
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 | (232) | 232 | ||||
Dividends on preferred stock | (8) | (8) | ||||
Balance At End Of Period at Dec. 31, 2018 | 4,301 | 4,301 | 0 | 4 | 7,734 | (3,437) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net income (loss) attributable to WPX Energy, Inc. | 256 | 256 | 256 | |||
Stock based compensation, net of tax impact | 22 | 22 | ||||
Transaction costs related to partnerships | 6 | (6) | (6) | |||
Repurchases of common stock | 58 | 58 | ||||
Balance At End Of Period at Dec. 31, 2019 | $ 4,515 | $ 4,515 | $ 0 | $ 4 | $ 7,692 | $ (3,181) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Operating Activities | ||||
Net income (loss) | $ 256 | $ 151 | $ (16) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Depreciation, depletion and amortization | 928 | 785 | 673 | |
Deferred income tax provision (benefit) | 89 | 84 | (134) | |
Provision for impairment of properties and equipment (including certain exploration expenses) and investments | 86 | 73 | 158 | |
Gain (Loss) on Disposition of Assets | 380 | (145) | 170 | |
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | (153) | 81 | 3 | |
Derivative, Cost of Hedge Net of Cash Received | 12 | (237) | 4 | |
Amortization of stock-based awards | 37 | 34 | 32 | |
Loss on extinguishment of debt | 47 | 71 | 17 | |
Undistributed equity (earnings) losses, net of distributions received | (4) | 6 | 0 | |
Cash provided by (used in) operating assets and liabilities: | ||||
Accounts receivable | (62) | (59) | (153) | |
Inventories | 6 | (15) | (8) | |
Other current assets | (5) | 2 | (8) | |
Accounts payable | 97 | 17 | 158 | |
Federal Income Taxes receivable and payable | 19 | (38) | 12 | |
Accrued and other current liabilities | 3 | (22) | (31) | |
Increase (Decrease) in Other Accrued Liabilities | (28) | (47) | (53) | |
Other, including changes in other noncurrent assets and liabilities | 3 | 14 | 29 | |
Net cash provided by operating activities(a) | [1] | 1,257 | 883 | 507 |
Investing Activities(a) | ||||
Payments to Acquire Oil and Gas Property and Equipment | [2] | 1,357 | 1,476 | 1,161 |
Proceeds from sales of assets | 592 | 682 | 193 | |
Payments to Acquire Businesses, Gross | 0 | 0 | 799 | |
Proceeds from joint venture formation | 0 | 0 | 338 | |
Purchases of or contributions to investments | (18) | (102) | (8) | |
Proceeds from Equity Method Investment, Distribution, Return of Capital | 14 | 0 | 0 | |
Other | 1 | 0 | 1 | |
Net Cash Provided by (Used in) Investing Activities | [1] | (773) | (896) | (1,436) |
Financing Activities | ||||
Proceeds from common stock | 2 | 10 | 672 | |
Dividends paid on preferred stock | 0 | (11) | (15) | |
Payments related to induced conversion of preferred stock to common stock | (58) | 0 | 0 | |
Borrowings on credit facility | 1,541 | 1,453 | 661 | |
Payments on credit facility | (1,871) | (1,123) | (661) | |
Proceeds from long-term debt, net of discount | 593 | 494 | 148 | |
Payments for retirement of long-term debt, including premium | (594) | (986) | (165) | |
Taxes paid for shares withheld | 16 | 14 | 12 | |
Payments for debt issuance costs and credit facility amendment fees | (3) | (10) | (2) | |
Other | (16) | 17 | (2) | |
Net cash provided by (used in) financing activities | (422) | (170) | 624 | |
Net increase (decrease) in cash and cash equivalents and restricted cash | 62 | (183) | (305) | |
Cash and cash equivalents and restricted cash at beginning of period | 18 | 201 | 506 | |
Cash and cash equivalents and restricted cash at end of period | 80 | 18 | 201 | |
Partnership [Member] | ||||
Investing Activities(a) | ||||
Payments to Acquire Oil and Gas Property and Equipment | [3] | $ 5 | $ 0 | $ 0 |
[1] | (a) Amounts reflect both continuing and discontinued operations unless otherwise noted. | |||
[2] | (b) Incurred capital expenditures were $1,313 million, $1,510 million and $1,232 million for the respective periods. The difference between incurred and cash | |||
[3] | (c) Incurred capital expenditures were $8 million for 2019. The difference between incurred and cash capital expenditures is due to changes in related accounts |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Increase to properties and equipment | $ 1,313 | $ 1,510 | $ 1,232 |
Partnership [Member] | |||
Increase to properties and equipment | $ 8 |
Description of Business, Basis
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
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, which include oil and natural gas purchased from third-party working interest owners in operated wells and the management of various commodity contracts, such as transportation. We had operations in the San Juan Basin, which were sold in 2017 and 2018, that are reported in 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 See Note 2 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 that 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 $20 million and $15 million as of December 31, 2019 and 2018, 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, 2019 2018 (Millions) Material, supplies and other $ 36 $ 46 Commodity production in storage 5 2 $ 41 $ 48 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, 2019 and 2018 was insignificant. Commodity management expenses Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. 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 3). 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 $36 million and $35 million as of December 31, 2019 and 2018, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 8) 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”) 2016-02, Leases , effective January 1, 2019. The standard requires the recognition of right-of-use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right-of-use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess: • whether existing contracts are or contain leases; • lease classification for any expired or existing leases; • initial direct costs for any existing lease; and • whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease. See Note 11 for additional information related to our contracts that are or contain leases. We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019 . This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period. Accounting Standards Not Yet Adopted In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses . This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This ASU will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this ASU will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of material credit losses. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued operations [Abstract] | |
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] | Discontinued Operations In first-quarter 2018, we sold our properties in the San Juan Basin’s Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of annual gathering and processing commitments that conclude in 2026; however, WPX has left in place a performance guarantee with respect to these commitments. The current remaining commitment is approximately $277 million. We believed and continue to believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and the purchaser, and the declining size of the obligations subject to the guarantee over time. As part of the divestiture, we determined the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future 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. In December 2017, we sold our natural gas-producing properties in the San Juan Basin for $169 million and recorded a gain of approximately $2 million. A portion of this sale closed in 2018. Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years related to the sale of Powder River properties. See Note 10 for additional information related to the Powder River liabilities. Summarized Results of Discontinued Operations The following table presents the results of discontinued operations for the years presented. For the year ended December 31, 2019, our discontinued operations activity was minimal and therefore not included in the table below. Years Ended December 31, 2018 2017 (Millions) Total revenues $ 75 $ 291 Costs and expenses: Depreciation, depletion and amortization $ 8 $ 131 Lease and facility operating 7 50 Gathering, processing and transportation 12 70 Taxes other than income 5 23 Exploration 3 14 General and administrative 1 8 Accrual for contract obligations retained — 5 Net loss—sales of assets and impairments — 50 Accretion of liabilities related to contract obligations retained 6 6 Other—net(a) 5 (3) Total costs and expenses 47 354 Operating income (loss) 28 (63) Loss on sales of assets (148) — Loss from discontinued operations before income taxes (120) (63) Benefit for income taxes (29) (23) Loss from discontinued operations $ (91) $ (40) __________ (a) Includes severance tax refund received in 2017. 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 $28 million, $47 million and $53 million for 2019, 2018 and 2017, 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, 2018 2017 (Millions) Cash provided by operating activities(a) $ 44 $ 143 Cash capital expenditures within investing activities $ 29 $ 175 __________ (a) Excluding income taxes and changes to working capital. |
Earnings (Loss) Per Common Shar
Earnings (Loss) Per Common Share from Continuing Operations | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Common Share from Continuing Operations | Earnings (Loss) Per Common Share from Continuing Operations The following table summarizes the calculation of earnings per share. Years Ended December 31, 2019 2018 2017 (Millions, except per-share amounts) Income from continuing operations attributable to WPX Energy, Inc. $ 258 $ 242 $ 24 Less: Dividends on preferred stock — 8 15 Income from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income per common share $ 258 $ 234 $ 9 Basic weighted-average shares 420.4 408.4 395.1 Effect of dilutive securities(a): Nonvested restricted stock units and awards 1.6 3.1 2.1 Stock options — 0.2 0.2 Diluted weighted-average shares(a) 422.0 411.7 397.4 Income per common share from continuing operations: Basic $ 0.62 $ 0.57 $ 0.02 Diluted $ 0.61 $ 0.57 $ 0.02 __________ (a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (ii) application of the treasury stock method to certain nonvested restricted stock units. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows: Years Ended December 31, 2019 2018 2017 (Millions) Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock Not 11.4 19.8 Nonvested restricted stock units antidilutive under the treasury stock method 1.0 0.7 0.6 The table below includes information related to stock options that were outstanding at December 31, 2019, 2018 and 2017 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, 2019 2018 2017 Options excluded (millions) 0.7 0.7 1.5 Weighted-average exercise price of options excluded $ 16.84 $ 18.05 $ 17.80 Exercise price range of options excluded $11.75 - $21.81 $16.46 - $21.81 $14.41 - $21.81 Fourth quarter weighted-average market price $ 10.67 $ 15.16 $ 12.10 |
Asset Sales, Impairments and Ex
Asset Sales, Impairments and Exploration Expenses | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Asset Sales,Other Expenses and Exploration Expenses | Asset Sales, Exploration Expenses and Other Asset Sales 2019 During the first quarter of 2019, we closed on the sale of certain non-core properties, primarily proved, in the Delaware Basin which were held for sale at December 31, 2018. We received approximately $83 million in proceeds. No gain or loss was recorded on this transaction. 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 included 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. Exploration Expenses The following table presents a summary of exploration expenses. Years Ended December 31, 2019 2018 2017 (Millions) Unproved leasehold property impairments, amortization and expiration $ 89 $ 69 $ 84 Geologic and geophysical costs 6 $ 6 3 Total exploration expenses $ 95 $ 75 $ 87 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. Other In third-quarter 2019, we recorded an $11 million charge included in other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin. The offer is still pending. |
Investments
Investments | 12 Months Ended |
Dec. 31, 2019 | |
Schedule of Equity Method Investments [Line Items] | |
Equity Method Investments and Joint Ventures Disclosure [Text Block] | Investments Catalyst Midstream Partners, LLC 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 joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity serves as operator. We account for our investment in Catalyst as an equity method investment. In connection with the joint venture formation, 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 $48 million and $58 million as of December 31, 2019 and 2018, respectively. As of December 31, 2019, the difference in our investment and our underlying equity in the net assets of Catalyst was approximately $244 million. In 2017, we deferred recognition of the $349 million we received at closing 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, 2019, the deferred amount was $339 million of which $329 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet. Other 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. During the second quarter of 2019, we received a distribution of approximately $357 million related to our 25 percent equity interest in the Oryx pipeline partnership after the |
Properties and Equipment
Properties and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 2018 (Millions) Proved properties (b) $ 8,719 $ 7,289 Unproved properties and land (c) 1,765 1,891 Gathering, processing and other facilities 15-25 403 294 Construction in progress (c) 224 350 Other 3-40 133 125 Total properties and equipment, at cost 11,244 9,949 Accumulated depreciation, depletion and amortization (3,654) (2,683) Properties and equipment—net $ 7,590 $ 7,266 __________ (a) Estimated useful lives are presented as of December 31, 2019. (b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1). (c) Unproved properties, land and construction in progress are not subject to depreciation and depletion. Unproved properties consist primarily of non-producing leasehold in the Delaware Basin. In first-quarter 2019, we closed a $100 million purchase of 14,000 surface acres within our Stateline operations of which a portion was allocated to unproved properties and the remainder to land. In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin, which closed in the first quarter of 2019. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 4). 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 2019 and 2018 is presented below. 2019 2018 (Millions) Balance, January 1 $ 72 $ 39 Liabilities incurred 11 8 Liabilities settled (4) (7) Estimate revisions 14 30 Accretion expense(a) 4 2 Balance, December 31 $ 97 $ 72 Amount reflected as current $ 5 $ 5 __________ (a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations. |
Accounts Payable and Accrued an
Accounts Payable and Accrued and Other Current Liabilities | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 2018 (Millions) Trade $ 162 $ 130 Accrual for capital expenditures 159 190 Royalties 209 170 Cash overdrafts 8 17 Other 18 7 $ 556 $ 514 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, 2019 2018 (Millions) Taxes other than income taxes $ 37 $ 19 Accrued interest 39 45 Compensation and benefit related accruals 55 39 Gathering and transportation 6 7 Gathering and transportation related to exited areas 26 30 Lease liabilities 60 — Other, including other loss contingencies 28 38 $ 251 $ 178 |
Debt and Banking Arrangements
Debt and Banking Arrangements | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt and Banking Arrangements | Debt and Banking Arrangements Interest paid on debt totaled $150 million, $172 million and $178 million for 2019, 2018 and 2017, respectively. The following table presents a summary of our debt as of the dates indicated below. December 31, 2019 2018 (Millions) Credit facility agreement $ — $ 330 6.000% Senior Notes due 2022 73 529 8.250% Senior Notes due 2023 406 500 5.250% Senior Notes due 2024 650 650 5.750% Senior Notes due 2026 500 500 5.250% Senior Notes due 2027 600 — Total debt $ 2,229 $ 2,509 Less: Current portion of long-term debt — — Total long-term debt $ 2,229 $ 2,509 Less: Debt issuance costs(a) 27 24 Total long-term debt, net(a) $ 2,202 $ 2,485 __________ (a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. Credit Facility On April 22, 2019, the Company entered into a Third Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, gives the Company the option, if certain conditions are met, to elect during any Collateral Trigger Period that scheduled redeterminations of the Borrowing Base be made annually on April 1 instead of semi-annually. Based on our current credit ratings, a Collateral Trigger Period applies that 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, 2019, WPX had no borrowings outstanding, had $28 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the Credit Facility. 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 April 2019, the Borrowing Base was increased to $2.1 billion and will remain in effect until the next Redetermination Date as described above. At this time, the Credit Facility Agreement is limited by the total commitments which remained at $1.5 billion. Terms and Conditions. The Credit Facility is 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 guarantees 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, 2019. Senior Note Face Value (Millions) Maturity Date Interest Payment Dates Optional Redemption Period(a) 6.000% Senior Notes due 2022 (the “2022 Notes”) $ 73 January 15, 2022 January 15, July 15 October 15, 2021 8.250% Senior Notes due 2023 (the “2023 Notes”) $ 406 August 1, February 1, August 1 June 1, 2023 5.250% Senior Notes due 2024 (the “2024 Notes”) $ 650 September 15, 2024 March 15, September 15 June 15, 2024 5.750% Senior Notes due 2026 (the “2026 Notes”) $ 500 June 1, June 1, December 1 June 1, 2021 5.250% Senior Notes due 2027 (the “2027 Notes”) $ 600 October 15, April 15, October 15 October 15, 2022 __________ (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 the applicable redemption prices set forth in the indenture, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture. See Note 17 for a discussion of Senior Notes issued subsequent to December 31, 2019. On September 24, 2019, we completed a debt offering of $600 million of 5.250% Senior Notes due in 2027 (the “2027 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on April 15 and October 15 of each year commencing on April 15, 2020. The 2027 Notes will mature on October 15, 2027 with the option, prior to October 15, 2022, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, at any time on or after October 15, 2022, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2027 Notes was approximately $592.5 million and approximately $2 million of debt issuance costs were capitalized. The net proceeds from this offering were used to fund the purchase of $550 million aggregate principal amount of our 2022 Notes and 2023 Notes through cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $47 million, which includes approximately $44 million of premium and approximately $3 million write-off of previously capitalized costs. 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. The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes, 2026 Notes and 2027 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. |
Provision (Benefit) for Income
Provision (Benefit) for Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 2018 2017 (Millions) Provision (benefit): Current: Federal $ (19) $ (38) $ (18) State (1) 1 1 (20) (37) (17) Deferred: Federal 81 107 (100) State 9 4 (11) 90 111 (111) Total provision (benefit) $ 70 $ 74 $ (128) 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 lowered the corporate regular tax rate. The Act also 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 had current receivables of $19 million and $38 million as of December 31, 2019 and 2018, respectively, related to AMT credit carryforward refunds. In 2019, we received the $38 million and expect the $19 million to be collected in 2020. 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 and those already received. 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, 2019 2018 2017 (Millions) Federal Statutory Rate 21 % 21 % 35 % Provision (benefit) at statutory rate $ 69 $ 66 $ (36) Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 2 (8) (12) Valuation allowance on state net operating losses and other assets (net of federal benefit) 14 17 17 Deferred state income tax rate change (net of federal benefit) (10) (5) (12) Reversal of valuation allowance on federal capital loss (10) — — Provisional impact of Tax Cuts and Jobs Act — — (92) Executive compensation deduction limitation 4 4 2 Other 1 — 5 Provision (benefit) for income taxes $ 70 $ 74 $ (128) As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years. Significant changes to our operations during 2019, 2018 and 2017 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 $10 million, $5 million and $12 million deferred tax benefit in 2019, 2018 and 2017, respectively. 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. However, 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, 2019 2018 (Millions) Deferred tax liabilities: Properties and equipment $ 938 $ 797 Derivatives, net — 33 Total deferred tax liabilities 938 830 Deferred tax assets: Accrued liabilities and other 156 137 Alternative minimum tax credits 21 40 NOL and other carryovers 682 665 Derivatives, net 5 — Total deferred tax assets 864 842 Less: valuation allowance 216 213 Total net deferred tax assets 648 629 Net deferred tax liabilities $ 290 $ 201 Net cash payments (receipts) for income taxes, including AMT credit carryforward refunds, were $(38) million, $2 million and $(39) million in 2019, 2018 and 2017, respectively. The Company has federal NOL carryovers of approximately $2.1 billion at December 31, 2019, including a $218 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, the Company has federal excess business interest expense carryover of approximately $20 million. The Company's $48 million federal capital loss carryovers have been utilized due to current year divestments. The Company has state NOL carryovers of approximately $4.2 billion and $4.1 billion at 2019 and 2018, 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. 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, 2019, 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 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, 2019, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI 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 AMT credit carryforward 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 refunds of AMT credit carryforwards have been received, the Company may have to remit cash to the IRS. Through December 31, 2019, we have received approximately $50 million related to these AMT credit carryforwards. 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 2018 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 approximately $1 million or less for 2019, 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, 2019, the Company has approximately $9 million of unrecognized tax benefits, which is offset by an increase in deferred tax assets of approximately $7 million. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position that would result in a significant increase or decrease of an unrecognized tax benefit. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases of Lessee Disclosure [Text Block] | Leases Our contracts that are leases or contain leases primarily relate to drilling rigs, compression units and office space. Leases are recorded on the balance sheet when the lease term exceeds one year and we direct the use of an identified asset while receiving substantially all of the economic benefit of the asset. Right-of-use assets are included in other noncurrent assets on the Consolidated Balance Sheet. Lease liabilities are included in accrued and other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheet. We have elected to include both lease and non-lease components for all significant asset classes as a single lease component for measurement purposes. Leases with an initial term of 12 months or less are not recorded on the balance sheet and lease expense for these leases is recognized as incurred. We have elected to include lease costs associated with lease terms of one month or less in our short-term lease disclosure below. We use judgments and assumptions to determine our discount rate and whether a contract contains a lease. The discount rate used to determine the lease payment liability is based on our estimated incremental borrowing rate. Certain of our leases include rental payments adjusted periodically for inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. From time to time we may enter into lease contracts that commence in future periods. Lease contracts that will commence subsequent to December 31, 2019 are not significant. The following tables include quantitative disclosures related to our leases. Twelve months ended December 31, 2019 (Millions) Lease Costs: Leases recorded on the Consolidated Balance Sheet: Operating lease cost—drilling rigs(a) $ 42 Operating lease cost—other(a) 19 Variable lease cost—drilling rigs(a) 6 Variable lease cost—other(a) 3 Short-term leases: Drilling rigs(b) 41 Other(b) 116 Total lease cost $ 227 Other Information: Cash paid for amount included in the measurement of lease liabilities: Operating cash flows used for operating leases(a) $ 19 Investing cash flows used for operating leases(a) $ 42 Right-of-use assets obtained in exchange for new operating lease liabilities $ 44 Weighted-average remaining lease term (in years) 1.36 years Weighted-average discount rate—operating leases 5 % __________ (a) Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners. (b) Includes variable lease costs on short-term leases. The following tables include quantitative disclosures related to our leases as of December 31, 2019. Drilling Rigs Real Estate, Compression and Other Total Undiscounted Cash Flows (Millions) Maturity of Lease Liabilities: 2020 $ 44 $ 18 $ 62 2021 5 10 15 2022 — 1 1 2023 — — — 2024 — — — Thereafter — — — $ 78 Lease Liabilities: Current lease liabilities $ 43 $ 17 $ 60 Noncurrent lease liabilities 5 11 16 Total lease liabilities $ 48 $ 28 $ 76 Difference between undiscounted cash flows and discounted cash flows $ 2 Total right-of-use assets on Consolidated Balance Sheet $ 76 |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2019 | |
Postemployment Benefits [Abstract] | |
Employee Benefit Plans | Employee Benefit PlansWPX has a defined contribution plan, which matches employee contributions 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, $10 million and $11 million for 2019, 2018 and 2017, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2019, and 2018 related to the non-matching annual employer contribution. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [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, 2019, 15 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 8 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 $34 million, $32 million and $28 million for of the years ended December 31, 2019, 2018 and 2017, 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, 2019 was $44 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, 2019. 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 106 thousand shares at an average price of $9.82 per share during 2019. Nonvested Restricted Stock Units and Awards The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2019. Restricted Stock Units Shares Weighted- Average Fair Value(a) (Millions) Nonvested at December 31, 2018 5.4 $ 15.01 Granted 3.8 $ 13.16 Forfeited (0.1) $ 13.12 Vested (3.2) $ 13.92 Nonvested at December 31, 2019 5.9 $ 14.78 __________ (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 2019 2018 2017 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 13.16 $ 16.74 $ 13.76 Total fair value of restricted stock units vested during the year (millions) $ 45 $ 26 $ 33 Performance-based shares granted represent 35 percent of nonvested restricted stock units outstanding at December 31, 2019. 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, 2019. Stock Options Options Weighted- Average Exercise Price Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (Millions) (Years) (Millions) Outstanding at December 31, 2018 1.1 $ 16.00 $ 0.3 Granted — $ — Exercised (0.1) $ 7.29 Forfeited (0.3) $ 16.40 Outstanding at December 31, 2019 0.7 $ 16.84 2.2 $ 0.2 Exercisable at December 31, 2019 0.7 $ 16.84 2.2 $ 0.2 The total intrinsic value of options exercised was $468 thousand, $4.3 million and $224 thousand for the years ended December 31, 2019, 2018 and 2017, respectively. Cash received from stock option exercises was $0.5 million, $9.2 million and $0.4 million during 2019, 2018 and 2017, respectively. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2019 | |
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. As of December 31, 2019, we have no preferred shares outstanding. 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 2019, 2018 or 2017. 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 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 an acreage acquisition in the Delaware Basin. Stock Repurchase Program On August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over a 24 month period. Under the share repurchase program, we may repurchase shares at management’s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume, general market conditions, legal requirements, general business conditions and corporate considerations determined by WPX’s management, such as liquidity and capital needs. This share repurchase program may be modified, suspended or terminated at any time by our Board of Directors. As of December 31, 2019, we have repurchased approximately 5.7 million shares under the program at an average price of $10.16. Transaction Costs Related to Partnerships In September and October 2019, we entered into strategic relationships with two third-parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022, respectively. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. During 2019, we incurred approximately $6 million of partnership equity commitment and issuance costs, which are recognized as a reduction of additional paid-in-capital within stockholders’ equity attributable to WPX. The Company will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds. WPX holds a controlling financial interest in these partnerships. Accordingly, we will consolidate the financial results of these entities and will present the portion attributable to the third parties as a noncontrolling interest in our consolidated financial statements. |
Contingent Liabilities and Comm
Contingent Liabilities and Commitments | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities and Commitments | Contingent Liabilities and Commitments Contingent Liabilities Federal gas royalties 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 subsequently 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 EPA, other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance. Matters related to Williams’ former power business In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications. Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. In February, 2019, settlement agreements with the Kansas and Missouri class claimants were executed, and on August 5, 2019, after the final fairness hearing, the court approved the settlement and entered final judgment. In the Wisconsin putative class action, the case was remanded to its originally filed court of the Western District of Wisconsin for trial. 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. In May 2019, the MDL Court remanded the case back to Kansas District Court. On December 30, 2019, Defendants petitioned the United States Court of Appeals for the Tenth Circuit to consider their motion for appeal of their motion to reconsider the denial of their motion for summary judgement. 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 in existence at the time of disposition. The current owner/operator of properties we divested in the Powder River Basin filed for bankruptcy during the fourth quarter of 2019, and it is uncertain to what extent the current owner/operator will perform its obligations with respect to such properties. Prior to our disposition of such properties, payments under the surface use agreements were approximately $6 million annually and our recorded asset retirement obligation under GAAP related to the plugging and abandoning of wells was approximately $46 million. 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 accounted for transportation costs when calculating royalty payments. In 2017, we settled one of these claims. As of December 31, 2019, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made. In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it. Summary As of December 31, 2019 and December 31, 2018, the Company had accrued approximately $10 million and $11 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year. Commitments We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our 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. 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, 2019, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows: Midstream Services Transportation Total (Millions) 2020 $ 53 $ 114 $ 167 2021 48 94 142 2022 43 87 130 2023 40 75 115 2024 36 76 112 Thereafter 32 315 347 Total commitments $ 252 $ 761 $ 1,013 Accrued liabilities $ 15 $ 21 $ 36 Our midstream service commitments will be settled over approximately seven years. Total rent expense, excluding amounts capitalized, was $25 million and $19 million in 2018 and 2017, 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. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
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 and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. December 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 67 $ — $ 67 $ — $ 175 $ 3 $ 178 Energy derivative liabilities $ — $ 91 $ — $ 91 $ — $ 37 $ — $ 37 Total debt(a) $ — $ 2,400 $ — $ 2,400 $ — $ 2,414 $ — $ 2,414 __________ (a) The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of December 31, 2019 and 2018, 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 or swaptions. These are carried at fair value on the Consolidated Balance Sheets. Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions. The determination of fair value for our derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements. Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as calls, costless collars, 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 swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedged prices on the swaps. The sold calls or swaptions establish a maximum price we will receive for the volumes under contract and are financially settled. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a 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 less than $1 million and $3 million included in Level 3 as of December 31, 2019 and 2018, respectively. Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1, Level 2 and Level 3 occurred during the years ended December 31, 2019 or 2018. 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 4 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 2 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin reported as discontinued operations. |
Derivatives and Concentration o
Derivatives and Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019. Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Price (c) Crude Oil Crude Oil 2020 Fixed Price Swaps(d) WTI (65,129) $ 57.07 Crude Oil 2020 Fixed Price Costless Collars WTI (20,000) 53.33 -63.48 Crude Oil 2020 Basis Swaps Midland/Cushing (7,486) $ (1.31) Crude Oil 2020 Basis Swaps Brent/WTI Spread (5,000) $ 8.36 Crude Oil 2021 Basis Swaps Brent/WTI Spread (1,000) $ 8.00 Crude Oil 2021 Fixed Price Swaptions WTI (20,000) $ 57.02 Crude Oil 2022 Basis Swaps Brent/WTI Spread (1,000) $ 7.75 Natural Gas Natural Gas 2020 Basis Swaps Waha (60) $ (0.79) Natural Gas 2021 Basis Swaps Waha (70) $ (0.59) Natural Gas 2022 Basis Swaps Waha (70) $ (0.57) Natural Gas 2023 Basis Swaps Waha (70) $ (0.51) __________ (a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. (b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. (c) The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu. (d) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests. Fair values and gains (losses) Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, our derivatives do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives. Years Ended December 31, 2019 2018 2017 (Millions) Gain (loss) from derivatives related to production(a) $ (150) $ 78 $ 3 Gain (loss) from derivatives related to physical marketing agreements(b) (3) 3 — Net gain (loss) on derivatives $ (153) $ 81 $ 3 __________ (a) Includes settlements totaling $12 million for the year ended December 31, 2019, payments totaling $237 million for the year ended December 31, 2018, and settlements totaling $4 million for the year ended December 31, 2017. (b) Includes payments totaling less than $1 million for the years ended December 31, 2019, 2018 and 2017. The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows. Offsetting of derivative assets and liabilities The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Net Amount December 31, 2019 (Millions) Derivative assets with right of offset or master netting agreements $ 67 $ (45) $ 22 Derivative liabilities with right of offset or master netting agreements $ (91) $ 45 $ (46) December 31, 2018 Derivative assets with right of offset or master netting agreements $ 178 $ (37) $ 141 Derivative liabilities with right of offset or master netting agreements $ (37) $ 37 $ — __________ (a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts. Credit-risk-related features Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. As of December 31, 2019, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $46 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. As of December 31, 2018, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net less than $1 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $46 million and less than $1 million at December 31, 2019 and 2018, respectively. Concentration of Credit Risk Cash equivalents Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. Accounts receivable The following table summarizes concentration of receivables, net of allowances, by product or service as of dates indicated below. December 31, 2019 2018 (Millions) Receivables by product or service: Sale of natural gas, crude and related products and services $ 336 $ 269 Joint interest owners 88 98 Income tax receivable 19 38 Other 7 — Total $ 450 $ 405 Oil and natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the southwestern United States and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Derivative assets and liabilities We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by creditworthy parties. We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2019, 2018 and 2017, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. Our gross and net credit exposure from our derivative contracts were $67 million and $22 million, respectively, as of December 31, 2019. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We consider counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade. Our five largest net counterparty positions represent approximately 98 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities. Other At December 31, 2019, we held collateral support of $40 million, either in the form of cash, letters of credit or surety bond, related to our commodity management agreements. Collateral support for our commodity agreements could include margin deposits, letters of credit, and guarantees of payment by credit worthy parties. Revenues The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company. Year ended December 31, 2019 2018 2017 United Energy Trading LLC 20% 23% (a) Occidental Energy Marketing 18% 16% (a) Crestwood Midstream Partners LP (a) (a) 21% St. Paul Refining (a) (a) 16% NGL Crude Logistics 13% 14% 13% Delek Refining, Ltd (a) (a) 10% BP Products North America, Inc. 11% (a) (a) __________ (a) Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives. One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course of business, we sell crude oil to a subsidiary of NGL Energy, noted in the table above as NGL Crude Logistics. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 2 percent of operating expenses. |
Pending Felix Acquisition
Pending Felix Acquisition | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | Pending Felix Acquisition On December 15, 2019, we entered into a Securities Purchase Agreement (the "Purchase Agreement") with Felix Investments Holdings II, LLC ("Felix Parent") to acquire all of the issued and outstanding membership interests of Felix Energy ("Felix") (collectively, the "Felix Acquisition"), for consideration of approximately $2.5 billion (the "Unadjusted Purchase Price"), consisting of $900 million in cash (the "Unadjusted Cash Purchase Price"), and 152,963,671 unregistered shares of our common stock (the "Unadjusted Equity Consideration") determined by dividing $1.6 billion by $10.46, the volume weighted average per share price of the Company for the ten consecutive trading days ending on December 13, 2019. The Unadjusted Purchase Price is subject to certain customary closing adjustments set forth in the Purchase Agreement. If certain closing adjustments are positive, the Unadjusted Cash Purchase Price is adjusted and if certain closing adjustments are negative, the Unadjusted Equity Consideration is adjusted. WPX plans to fund the cash portion through the issuance of $900 million of senior notes (see "Financing Transaction" below). We expect to close the Felix Acquisition in the first quarter of 2020, subject to satisfaction of customary closing conditions and pending shareholder approval. As of December 31, 2019, we have accrued approximately $3 million of acquisition bridge facility fees, included in interest expense, and approximately $3 million of acquisition costs, primarily related to legal and advisory fees, reflected on a separate line item on the Consolidated Statement of Operations. Additional expenses will be incurred upon closing. Felix Parent has a senior secured notes facility pursuant to that certain Note Purchase Agreement, dated as of August 9, 2017 (as amended, restated, amended and restated, supplemented and otherwise modified prior to the date hereof, the "Felix Parent Notes Facility"), and Felix has a reserve-based revolving credit facility pursuant to that certain Credit Agreement dated as of July 1, 2016 (as amended, restated, amended and restated, supplemented and otherwise modified prior the date hereof, the "Felix Revolving Credit Facility" and together with the Felix Parent Notes Facility, the "Felix Debt Facilities"). The Felix Parent Notes Facility is secured by a lien on the equity of Felix and certain of Felix's assets. As a condition to and simultaneous with the closing of the Felix Acquisition, all remaining amounts outstanding under the Felix Debt Facilities are to be repaid in order to cause the release of such liens and terminate the facilities. Any amounts outstanding under the Felix Debt Facilities that are repaid from the Unadjusted Cash Purchase Price in connection with and simultaneous with the closing of the Felix Acquisition will result in a reduction in the Unadjusted Cash Purchase Price received by Felix Parent. Furthermore, in connection with entering into the Purchase Agreement, Felix Parent received commitments from certain of its affiliates to finance the repayment of any amounts outstanding under the Felix Debt Facilities to the extent such amounts outstanding exceed the Unadjusted Cash Purchase Price subject to certain adjustments. Pursuant to the Purchase Agreement, Felix Parent will receive our common stock as consideration and Felix Parent (and/or certain of Felix Parent's direct or indirect equity holders) will have registration rights with respect to such common stock. Following the acquisition, Felix will be our wholly-owned subsidiary. Felix is engaged in the acquisition, development and production of oil and gas properties in the Permian Basin, and more specifically in the Delaware Basin sub-area. All of Felix's Permian properties are located in the Delaware Basin and include approximately 58,500 net acres with six productive benches, with core operations located in Loving, Reeves, Ward and Winkler counties in Texas. Felix has assembled a multi-year inventory of approximately 1,500 gross drillable locations. Financing Transaction On January 10, 2020, we completed our debt offering of $900 million aggregate principal amount of 4.50% senior unsecured notes due 2030 (the "2030 Notes"). The proceeds were deposited into an escrow account upon the closing of the offering. Upon release from escrow, WPX intends to use the proceeds to finance a portion of the cash consideration of the Felix Acquisition and to pay certain fees and expenses. The Notes are the Company’s senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. The 2030 Notes bear interest at a rate of 4.50% per annum and were priced at 100.0% of par. Interest is payable on the 2030 Notes semi-annually in arrears on January 15 and July 15 of each year commencing on July 15, 2020. The 2030 Notes will mature on January 15, 2030. At any time prior to January 15, 2023, the Company may, on one or more occasions and subject to certain conditions described in the Indenture, redeem up to 35% of the aggregate principal amount of the Notes at a redemption price equal to 104.5% of the principal amount of the Notes redeemed with an amount of cash not greater than the net proceeds that the Company raises in certain equity offerings, as described in the Indenture. The Company also has the option, at any time prior to January 15, 2025, on one or more occasions, to redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus a specified “make whole” premium as described in the Indenture. At any time on or after January 15, 2025, the Company may, on one or more occasions, redeem the Notes, in whole or in part, at the applicable redemption prices set forth in the Indenture. The Indenture contains covenants that, among other things, restrict the Company’s ability to grant liens on its assets and merge, consolidate or transfer or lease all or substantially all of its assets, subject to certain qualifications and exceptions. |
Quarterly Financial Data
Quarterly Financial Data | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL DATA | WPX Energy, Inc. QUARTERLY FINANCIAL DATA (Unaudited) Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding. First Quarter Second Quarter Third Quarter Fourth Quarter 2019 (Millions, except per-share amounts) Product revenues $ 507 $ 558 $ 581 $ 601 Net gain (loss) on derivatives $ (207) $ 78 $ 175 $ (199) Commodity management $ 59 $ 58 $ 38 $ 39 Total revenues $ 359 $ 695 $ 795 $ 443 Operating costs and expenses $ 410 $ 422 $ 454 $ 472 Operating income (loss) $ (149) $ 181 $ 242 $ (130) Income (loss) from continuing operations $ (48) $ 305 $ 122 $ (121) Loss from discontinued operations — — (1) (1) Net income (loss) $ (48) $ 305 $ 121 $ (122) Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (48) $ 305 $ 122 $ (121) Loss from discontinued operations — — (1) (1) Net income (loss) $ (48) $ 305 $ 121 $ (122) Basic earnings (loss) per common share: Income (loss) from continuing operations $ (0.11) $ 0.72 $ 0.29 $ (0.29) Net income (loss) $ (0.11) $ 0.72 $ 0.29 $ (0.29) Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (0.11) $ 0.72 $ 0.29 $ (0.29) Net income (loss) $ (0.11) $ 0.72 $ 0.29 $ (0.29) 2018 Product revenues $ 407 $ 520 $ 554 $ 544 Net gain (loss) on derivatives $ (69) $ (154) $ (139) $ 443 Commodity management $ 36 $ 64 $ 68 $ 36 Total revenues $ 374 $ 430 $ 484 $ 1,022 Operating costs and expenses $ 322 $ 388 $ 413 $ 447 Operating income $ 6 $ (3) $ 26 $ 525 Income (loss) from continuing operations $ (26) $ (79) $ (6) $ 353 Income (loss) from discontinued operations (89) (2) (1) 1 Net income (loss) $ (115) $ (81) $ (7) $ 354 Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (30) $ (83) $ (6) $ 353 Income (loss) from discontinued operations (89) (2) (1) 1 Net income (loss) $ (119) $ (85) $ (7) $ 354 Basic earnings (loss) per common share: Income (loss) from continuing operations $ (0.07) $ (0.21) $ (0.01) $ 0.84 Loss from discontinued operations (0.23) — — — Net income (loss) $ (0.30) $ (0.21) $ (0.01) $ 0.84 Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (0.07) $ (0.21) $ (0.01) $ 0.83 Loss from discontinued operations (0.23) — — — Net income (loss) $ (0.30) $ (0.21) $ (0.01) $ 0.83 Net income or loss for each respective quarter include the following pre-tax items: First-quarter 2019: • $126 million gain on sale of our 20 percent equity interest in the Whitewater natural gas pipeline (see Note 5). Second-quarter 2019: • $247 million gain related to a distribution received for our 25 percent equity interest in the Oryx pipeline partnership after the underlying assets were sold (see Note 5). Third-quarter 2019: • $47 million loss on extinguishment of debt (see Note 8). • $11 million charge included in Other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin (see Note 4). Fourth-quarter 2019: • $7 million additional gain on sale of our 20 percent equity interest in the Whitewater natural gas pipeline (see Note 5). First-quarter 2018: • $138 million loss included in discontinued operations for the sale of the San Juan Gallup and $9 million performance guarantee related to gathering and processing commitments (see Note 2). Second-quarter 2018: • $71 million loss on extinguishment of debt (see Note 8). |
Supplemental Oil and Gas Disclo
Supplemental Oil and Gas Disclosures | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Gas Disclosures | We have significant continuing oil and gas producing activities primarily in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota, all of which are located in the United States. The following information includes activity through the completion of any asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan Basin, which have been reported as discontinued operations in our consolidated financial statements. The San Juan Basin properties were sold in March 2018 and December 2017. Capitalized Costs As of December 31, 2019 2018 (Millions) Proved Properties $ 8,928 $ 7,612 Unproved properties 1,765 1,891 10,693 9,503 Accumulated depreciation, depletion and amortization and valuation provisions (3,491) (2,542) Net capitalized costs $ 7,202 $ 6,961 __________ • Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $350 million and $276 million, net, as of December 31, 2019 and 2018, respectively. • Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells. • Unproved properties consist primarily of unproved leasehold costs. Cost Incurred For the years ended December 31, 2019 2018 2017 (Millions) Acquisition $ 115 $ 68 $ 864 Exploration 8 7 5 Development 1,099 1,350 1,048 $ 1,222 $ 1,425 $ 1,917 __________ • Costs incurred include capitalized and expensed items but excludes costs associated with facilities. • Acquisition costs are as follows: Costs in 2019 primarily reflect the purchase of surface acreage within our Delaware Basin acreage. Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin in March 2017 that included approximately $200 million and 23.8 MMboe of proved developed reserves and facilities. • Exploration costs include costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds. • Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our San Juan Basin operations were $24 million and $168 million for 2018 and 2017, respectively. Proved Reserves The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. The following is a summary of changes in our proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations. Oil (MMbbls) Natural Gas (Bcf) NGLs (MMbbls) All Products (MMboe) Proved reserves at December 31, 2016 174.6 734.5 49.5 346.4 Revisions 4.7 (8.4) (1.1) 2.3 Purchases 21.8 58.8 7.8 39.4 Divestitures (1.7) (312.5) (0.8) (54.6) Extensions and discoveries 86.7 194.5 23.6 142.7 Production (22.4) (75.9) (5.0) (40.0) Proved reserves at December 31, 2017 263.7 591.0 74.0 436.2 Revisions — (11.4) 5.3 3.4 Purchases 1.5 4.8 0.6 2.9 Divestitures (27.6) (79.8) (10.4) (51.3) Extensions and discoveries 84.5 176.9 22.7 136.7 Production (30.8) (63.8) (7.2) (48.6) Proved reserves at December 31, 2018 291.3 617.7 85.0 479.3 Revisions (10.7) 41.4 8.6 4.8 Divestitures (3.7) (10.7) (0.8) (6.3) Extensions and discoveries 56.7 170.7 25.5 110.7 Production (37.8) (78.4) (10.0) (60.9) Proved reserves at December 31, 2019 295.8 740.7 108.3 527.6 Proved developed reserves: December 31, 2017 130.3 321.2 38.8 222.7 December 31, 2018 156.4 365.4 48.4 265.8 December 31, 2019 184.3 456.5 65.5 325.9 Proved undeveloped reserves: December 31, 2017 133.4 269.8 35.2 213.5 December 31, 2018 134.9 252.3 36.6 213.5 December 31, 2019 111.5 284.2 42.8 201.7 __________ • Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. • Revisions in 2019 primarily reflect 21 MMboe of positive technical revisions partially offset by 16 MMboe of negative revisions due to a decrease in the 12 month average price. Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells. • Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed. • Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves. • Extensions and discoveries in 2019 reflect 42 MMboe added for proved developed locations primarily in the Permian Basin and 68 MMboe added for proved undeveloped locations in the Permian Basin. Extensions and discoveries in 2018 reflect 52 MMboe added for proved developed locations and 85 MMboe of proved undeveloped locations. Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is based on the estimated quantities of proved reserves. Prices were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. The average domestic oil price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $53.62, $61.57 and $46.39 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $0.97, $1.21 and $1.67 per Mcf, respectively. The average NGL price per barrel was $13.23, $26.76 and $21.16 for the same periods. Future income tax expenses have been computed considering applicable taxable cash flows, including historical tax basis and carry forwards (i.e. future deductions for taxable income calculations), and appropriate statutory tax rates. The discount rate of 10 is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates. Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2019 2018 (Millions) Future cash inflows $ 18,012 $ 20,963 Less: Future production costs 8,407 7,615 Future development costs 1,469 2,345 Future income tax provisions 772 1,366 Future net cash flows 7,364 9,637 Less 10 percent annual discount for estimated timing of cash flows 3,233 4,446 Standardized measure of discounted future net cash inflows $ 4,131 $ 5,191 Sources of Change in Standardized Measure of Discounted Future Net Cash Flows For the years ended December 31, 2019 2018 2017 (Millions) Beginning of year $ 5,191 $ 3,161 $ 1,038 Sales of oil and gas produced, net of operating costs (1,515) (1,541) (894) Net change in prices and production costs (2,247) 2,004 1,385 Extensions, discoveries and improved recovery, less estimated future costs 667 1,341 816 Development costs incurred during year 636 654 345 Changes in estimated future development costs 585 (35) 105 Purchase of reserves in place, less estimated future costs — 27 305 Sale of reserves in place, less estimated future costs (63) (409) 20 Revisions of previous quantity estimates 85 75 30 Accretion of discount 548 324 104 Net change in income taxes 260 (396) (83) Other (16) (14) (10) Net changes (1,060) 2,030 2,123 End of year $ 4,131 $ 5,191 $ 3,161 |
II-Valuation and Qualifying Acc
II-Valuation and Qualifying Accounts (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
II-Valuation and Qualifying Accounts [Abstract] | |
SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block] | SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS Beginning Balance Charged (Credited) to Costs and Expenses Other Deductions Ending Balance 2019: Allowance for doubtful accounts—accounts and notes $ — $ 9 $ — $ — $ 9 Deferred tax asset valuation(a) 213 3 — — 216 2018: Allowance for doubtful accounts—accounts and notes $ 2 $ — $ — $ (2) $ — Deferred tax asset valuation(a) 195 18 — — 213 Price-risk management credit reserves—liabilities(b)(c) 4 — (4) — — 2017: Allowance for doubtful accounts—accounts and notes $ 3 $ — $ — $ (1) $ 2 Deferred tax asset valuation(a)(d) 151 44 — — 195 Price-risk management credit reserves—liabilities(b)(c) 5 — (1) — 4 __________ (a) Deducted from related assets. (b) Deducted from related liabilities. (c) Included in revenues. (d) Includes impact of the Tax Cuts and Jobs Act enacted rate reduction. |
Description of Business, Basi_2
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Description of Business and Basis of Presentation | Description of Business Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, which include oil and natural gas purchased from third-party working interest owners in operated wells and the management of various commodity contracts, such as transportation. We had operations in the San Juan Basin, which were sold in 2017 and 2018, that are reported in 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.” |
Principles of consolidation | 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). |
Discontinued operations | Discontinued Operations |
Use of estimates | 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 that 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 | 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 cashRestricted cash was approximately $20 million and $15 million as of December 31, 2019 and 2018, respectively, and is included in other current assets on the Consolidated Balance Sheets. |
Accounts receivable | 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 | 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, 2019 2018 (Millions) Material, supplies and other $ 36 $ 46 Commodity production in storage 5 2 $ 41 $ 48 |
Properties and equipment | 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 | 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. |
Impairment of long-lived assets | 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 | 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 | 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 | 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 | 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. |
Revenue Recognition | 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 |
Commodity management expenses | Commodity management expenses Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. |
Income taxes | Income taxesWe 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 | 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 | 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 3). |
Debt issuance costs | Debt issuance costsDebt 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 $36 million and $35 million as of December 31, 2019 and 2018, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 8) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets. |
New Accounting Pronouncements and Changes in Accounting Principles | Recently Adopted Accounting Standards The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases , effective January 1, 2019. The standard requires the recognition of right-of-use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right-of-use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess: • whether existing contracts are or contain leases; • lease classification for any expired or existing leases; • initial direct costs for any existing lease; and • whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease. See Note 11 for additional information related to our contracts that are or contain leases. We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019 . This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in |
New Accounting Pronouncements Not yet Adopted | Accounting Standards Not Yet Adopted In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses . This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This ASU will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this ASU will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of material credit losses. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard. |
Description of Business, Basi_3
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventory, Current [Table Text Block] | The following table presents a summary of inventories. Years ended December 31, 2019 2018 (Millions) Material, supplies and other $ 36 $ 46 Commodity production in storage 5 2 $ 41 $ 48 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued operations [Abstract] | |
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block] | Summarized Results of Discontinued Operations The following table presents the results of discontinued operations for the years presented. For the year ended December 31, 2019, our discontinued operations activity was minimal and therefore not included in the table below. Years Ended December 31, 2018 2017 (Millions) Total revenues $ 75 $ 291 Costs and expenses: Depreciation, depletion and amortization $ 8 $ 131 Lease and facility operating 7 50 Gathering, processing and transportation 12 70 Taxes other than income 5 23 Exploration 3 14 General and administrative 1 8 Accrual for contract obligations retained — 5 Net loss—sales of assets and impairments — 50 Accretion of liabilities related to contract obligations retained 6 6 Other—net(a) 5 (3) Total costs and expenses 47 354 Operating income (loss) 28 (63) Loss on sales of assets (148) — Loss from discontinued operations before income taxes (120) (63) Benefit for income taxes (29) (23) Loss from discontinued operations $ (91) $ (40) __________ (a) Includes severance tax refund received in 2017. |
Schedule of Disposal Groups Including Discontinued Operations Cash Flows [Table Text Block] | Cash Flows Attributable to Discontinued Operations In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $28 million, $47 million and $53 million for 2019, 2018 and 2017, 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, 2018 2017 (Millions) Cash provided by operating activities(a) $ 44 $ 143 Cash capital expenditures within investing activities $ 29 $ 175 __________ (a) Excluding income taxes and changes to working capital. |
Earnings (Loss) Per Common Sh_2
Earnings (Loss) Per Common Share from Continuing Operations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Common Share from Continuing Operations | The following table summarizes the calculation of earnings per share. Years Ended December 31, 2019 2018 2017 (Millions, except per-share amounts) Income from continuing operations attributable to WPX Energy, Inc. $ 258 $ 242 $ 24 Less: Dividends on preferred stock — 8 15 Income from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income per common share $ 258 $ 234 $ 9 Basic weighted-average shares 420.4 408.4 395.1 Effect of dilutive securities(a): Nonvested restricted stock units and awards 1.6 3.1 2.1 Stock options — 0.2 0.2 Diluted weighted-average shares(a) 422.0 411.7 397.4 Income per common share from continuing operations: Basic $ 0.62 $ 0.57 $ 0.02 Diluted $ 0.61 $ 0.57 $ 0.02 __________ (a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (ii) application of the treasury stock method to certain nonvested restricted stock units. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows: Years Ended December 31, 2019 2018 2017 (Millions) Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock Not 11.4 19.8 Nonvested restricted stock units antidilutive under the treasury stock method 1.0 0.7 0.6 |
Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Options | The table below includes information related to stock options that were outstanding at December 31, 2019, 2018 and 2017 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, 2019 2018 2017 Options excluded (millions) 0.7 0.7 1.5 Weighted-average exercise price of options excluded $ 16.84 $ 18.05 $ 17.80 Exercise price range of options excluded $11.75 - $21.81 $16.46 - $21.81 $14.41 - $21.81 Fourth quarter weighted-average market price $ 10.67 $ 15.16 $ 12.10 |
Asset Sales, Impairments and _2
Asset Sales, Impairments and Exploration Expenses (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Summary of exploration expenses | The following table presents a summary of exploration expenses. Years Ended December 31, 2019 2018 2017 (Millions) Unproved leasehold property impairments, amortization and expiration $ 89 $ 69 $ 84 Geologic and geophysical costs 6 $ 6 3 Total exploration expenses $ 95 $ 75 $ 87 |
Properties and Equipment (Table
Properties and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Properties and Equipment, at Cost | Properties and equipment is carried at cost and consists of the following: Estimated Useful Life(a) (Years) December 31, 2019 2018 (Millions) Proved properties (b) $ 8,719 $ 7,289 Unproved properties and land (c) 1,765 1,891 Gathering, processing and other facilities 15-25 403 294 Construction in progress (c) 224 350 Other 3-40 133 125 Total properties and equipment, at cost 11,244 9,949 Accumulated depreciation, depletion and amortization (3,654) (2,683) Properties and equipment—net $ 7,590 $ 7,266 __________ (a) Estimated useful lives are presented as of December 31, 2019. (b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1). (c) Unproved properties, land and construction in progress are not subject to depreciation and depletion. |
Rollforward of Asset Retirement Obligation | A rollforward of our asset retirement obligations for the years ended 2019 and 2018 is presented below. 2019 2018 (Millions) Balance, January 1 $ 72 $ 39 Liabilities incurred 11 8 Liabilities settled (4) (7) Estimate revisions 14 30 Accretion expense(a) 4 2 Balance, December 31 $ 97 $ 72 Amount reflected as current $ 5 $ 5 __________ (a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations. |
Accounts Payable and Accrued _2
Accounts Payable and Accrued and Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Payables and Accruals [Abstract] | |
Accounts Payable | Accounts Payable The following table presents a summary of our accounts payable as of the dates indicated below. December 31, 2019 2018 (Millions) Trade $ 162 $ 130 Accrual for capital expenditures 159 190 Royalties 209 170 Cash overdrafts 8 17 Other 18 7 $ 556 $ 514 |
Accrued and Other Current Liabilities | 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, 2019 2018 (Millions) Taxes other than income taxes $ 37 $ 19 Accrued interest 39 45 Compensation and benefit related accruals 55 39 Gathering and transportation 6 7 Gathering and transportation related to exited areas 26 30 Lease liabilities 60 — Other, including other loss contingencies 28 38 $ 251 $ 178 |
Debt and Banking Arrangements S
Debt and Banking Arrangements Schedule of Long-term Debt Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt Instrument Redemption [Table Text Block] | 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, 2019. Senior Note Face Value (Millions) Maturity Date Interest Payment Dates Optional Redemption Period(a) 6.000% Senior Notes due 2022 (the “2022 Notes”) $ 73 January 15, 2022 January 15, July 15 October 15, 2021 8.250% Senior Notes due 2023 (the “2023 Notes”) $ 406 August 1, February 1, August 1 June 1, 2023 5.250% Senior Notes due 2024 (the “2024 Notes”) $ 650 September 15, 2024 March 15, September 15 June 15, 2024 5.750% Senior Notes due 2026 (the “2026 Notes”) $ 500 June 1, June 1, December 1 June 1, 2021 5.250% Senior Notes due 2027 (the “2027 Notes”) $ 600 October 15, April 15, October 15 October 15, 2022 __________ (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 the applicable redemption prices set forth in the indenture, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture. |
Schedule of Debt [Table Text Block] | The following table presents a summary of our debt as of the dates indicated below. December 31, 2019 2018 (Millions) Credit facility agreement $ — $ 330 6.000% Senior Notes due 2022 73 529 8.250% Senior Notes due 2023 406 500 5.250% Senior Notes due 2024 650 650 5.750% Senior Notes due 2026 500 500 5.250% Senior Notes due 2027 600 — Total debt $ 2,229 $ 2,509 Less: Current portion of long-term debt — — Total long-term debt $ 2,229 $ 2,509 Less: Debt issuance costs(a) 27 24 Total long-term debt, net(a) $ 2,202 $ 2,485 __________ (a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. |
Provision (Benefit) for Incom_2
Provision (Benefit) for Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Provision (Benefit) for Income Taxes from Continuing Operations | The following table includes the provision (benefit) for income taxes from continuing operations. Years Ended December 31, 2019 2018 2017 (Millions) Provision (benefit): Current: Federal $ (19) $ (38) $ (18) State (1) 1 1 (20) (37) (17) Deferred: Federal 81 107 (100) State 9 4 (11) 90 111 (111) Total provision (benefit) $ 70 $ 74 $ (128) |
Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate | 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, 2019 2018 2017 (Millions) Federal Statutory Rate 21 % 21 % 35 % Provision (benefit) at statutory rate $ 69 $ 66 $ (36) Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 2 (8) (12) Valuation allowance on state net operating losses and other assets (net of federal benefit) 14 17 17 Deferred state income tax rate change (net of federal benefit) (10) (5) (12) Reversal of valuation allowance on federal capital loss (10) — — Provisional impact of Tax Cuts and Jobs Act — — (92) Executive compensation deduction limitation 4 4 2 Other 1 — 5 Provision (benefit) for income taxes $ 70 $ 74 $ (128) |
Significant Components of Deferred Tax Liabilities and Deferred Tax Assets | The following table includes significant components of deferred tax liabilities and deferred tax assets. December 31, 2019 2018 (Millions) Deferred tax liabilities: Properties and equipment $ 938 $ 797 Derivatives, net — 33 Total deferred tax liabilities 938 830 Deferred tax assets: Accrued liabilities and other 156 137 Alternative minimum tax credits 21 40 NOL and other carryovers 682 665 Derivatives, net 5 — Total deferred tax assets 864 842 Less: valuation allowance 216 213 Total net deferred tax assets 648 629 Net deferred tax liabilities $ 290 $ 201 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Lease, Cost [Table Text Block] | The following tables include quantitative disclosures related to our leases. Twelve months ended December 31, 2019 (Millions) Lease Costs: Leases recorded on the Consolidated Balance Sheet: Operating lease cost—drilling rigs(a) $ 42 Operating lease cost—other(a) 19 Variable lease cost—drilling rigs(a) 6 Variable lease cost—other(a) 3 Short-term leases: Drilling rigs(b) 41 Other(b) 116 Total lease cost $ 227 Other Information: Cash paid for amount included in the measurement of lease liabilities: Operating cash flows used for operating leases(a) $ 19 Investing cash flows used for operating leases(a) $ 42 Right-of-use assets obtained in exchange for new operating lease liabilities $ 44 Weighted-average remaining lease term (in years) 1.36 years Weighted-average discount rate—operating leases 5 % __________ (a) Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners. (b) Includes variable lease costs on short-term leases. |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | The following tables include quantitative disclosures related to our leases as of December 31, 2019. Drilling Rigs Real Estate, Compression and Other Total Undiscounted Cash Flows (Millions) Maturity of Lease Liabilities: 2020 $ 44 $ 18 $ 62 2021 5 10 15 2022 — 1 1 2023 — — — 2024 — — — Thereafter — — — $ 78 Lease Liabilities: Current lease liabilities $ 43 $ 17 $ 60 Noncurrent lease liabilities 5 11 16 Total lease liabilities $ 48 $ 28 $ 76 Difference between undiscounted cash flows and discounted cash flows $ 2 Total right-of-use assets on Consolidated Balance Sheet $ 76 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Summary of Nonvested Restricted Stock Unit Activity and Related Information | Nonvested Restricted Stock Units and Awards The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2019. Restricted Stock Units Shares Weighted- Average Fair Value(a) (Millions) Nonvested at December 31, 2018 5.4 $ 15.01 Granted 3.8 $ 13.16 Forfeited (0.1) $ 13.12 Vested (3.2) $ 13.92 Nonvested at December 31, 2019 5.9 $ 14.78 __________ (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. |
Share-based Compensation, Activity | Other restricted stock unit information 2019 2018 2017 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 13.16 $ 16.74 $ 13.76 Total fair value of restricted stock units vested during the year (millions) $ 45 $ 26 $ 33 |
Summary of Stock Option Activity and Related Information | Stock Options The following summary reflects stock option activity and related information for the year ended December 31, 2019. Stock Options Options Weighted- Average Exercise Price Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (Millions) (Years) (Millions) Outstanding at December 31, 2018 1.1 $ 16.00 $ 0.3 Granted — $ — Exercised (0.1) $ 7.29 Forfeited (0.3) $ 16.40 Outstanding at December 31, 2019 0.7 $ 16.84 2.2 $ 0.2 Exercisable at December 31, 2019 0.7 $ 16.84 2.2 $ 0.2 |
Contingent Liabilities and Co_2
Contingent Liabilities and Commitments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitment Under Contracts | 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. 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, 2019, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows: Midstream Services Transportation Total (Millions) 2020 $ 53 $ 114 $ 167 2021 48 94 142 2022 43 87 130 2023 40 75 115 2024 36 76 112 Thereafter 32 315 347 Total commitments $ 252 $ 761 $ 1,013 Accrued liabilities $ 15 $ 21 $ 36 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on Recurring Basis | The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. December 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (Millions) (Millions) Energy derivative assets $ — $ 67 $ — $ 67 $ — $ 175 $ 3 $ 178 Energy derivative liabilities $ — $ 91 $ — $ 91 $ — $ 37 $ — $ 37 Total debt(a) $ — $ 2,400 $ — $ 2,400 $ — $ 2,414 $ — $ 2,414 __________ (a) The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of December 31, 2019 and 2018, respectively. |
Derivatives and Concentration_2
Derivatives and Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives Related to Production | 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, 2019. Commodity Period Contract Type (a) Location Notional Volume (b) Weighted Average Price (c) Crude Oil Crude Oil 2020 Fixed Price Swaps(d) WTI (65,129) $ 57.07 Crude Oil 2020 Fixed Price Costless Collars WTI (20,000) 53.33 -63.48 Crude Oil 2020 Basis Swaps Midland/Cushing (7,486) $ (1.31) Crude Oil 2020 Basis Swaps Brent/WTI Spread (5,000) $ 8.36 Crude Oil 2021 Basis Swaps Brent/WTI Spread (1,000) $ 8.00 Crude Oil 2021 Fixed Price Swaptions WTI (20,000) $ 57.02 Crude Oil 2022 Basis Swaps Brent/WTI Spread (1,000) $ 7.75 Natural Gas Natural Gas 2020 Basis Swaps Waha (60) $ (0.79) Natural Gas 2021 Basis Swaps Waha (70) $ (0.59) Natural Gas 2022 Basis Swaps Waha (70) $ (0.57) Natural Gas 2023 Basis Swaps Waha (70) $ (0.51) __________ (a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. (b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. (c) The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu. (d) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests. |
DerivativeGainLoss [Table Text Block] | The following table presents the net gain (loss) related to our energy commodity derivatives. Years Ended December 31, 2019 2018 2017 (Millions) Gain (loss) from derivatives related to production(a) $ (150) $ 78 $ 3 Gain (loss) from derivatives related to physical marketing agreements(b) (3) 3 — Net gain (loss) on derivatives $ (153) $ 81 $ 3 __________ (a) Includes settlements totaling $12 million for the year ended December 31, 2019, payments totaling $237 million for the year ended December 31, 2018, and settlements totaling $4 million for the year ended December 31, 2017. (b) Includes payments totaling less than $1 million for the years ended December 31, 2019, 2018 and 2017. |
Gross And Net Derivative Asset and Liability | The following table presents our gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments (a) Net Amount December 31, 2019 (Millions) Derivative assets with right of offset or master netting agreements $ 67 $ (45) $ 22 Derivative liabilities with right of offset or master netting agreements $ (91) $ 45 $ (46) December 31, 2018 Derivative assets with right of offset or master netting agreements $ 178 $ (37) $ 141 Derivative liabilities with right of offset or master netting agreements $ (37) $ 37 $ — __________ (a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts. |
Concentration of Receivables, Net of Allowances, by Product or Service | The following table summarizes concentration of receivables, net of allowances, by product or service as of dates indicated below. December 31, 2019 2018 (Millions) Receivables by product or service: Sale of natural gas, crude and related products and services $ 336 $ 269 Joint interest owners 88 98 Income tax receivable 19 38 Other 7 — Total $ 450 $ 405 |
Schedules of Concentration of Risk, by Risk Factor | The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company. Year ended December 31, 2019 2018 2017 United Energy Trading LLC 20% 23% (a) Occidental Energy Marketing 18% 16% (a) Crestwood Midstream Partners LP (a) (a) 21% St. Paul Refining (a) (a) 16% NGL Crude Logistics 13% 14% 13% Delek Refining, Ltd (a) (a) 10% BP Products North America, Inc. 11% (a) (a) __________ (a) Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives. |
Quarterly Financial Data (Table
Quarterly Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data | Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding. First Quarter Second Quarter Third Quarter Fourth Quarter 2019 (Millions, except per-share amounts) Product revenues $ 507 $ 558 $ 581 $ 601 Net gain (loss) on derivatives $ (207) $ 78 $ 175 $ (199) Commodity management $ 59 $ 58 $ 38 $ 39 Total revenues $ 359 $ 695 $ 795 $ 443 Operating costs and expenses $ 410 $ 422 $ 454 $ 472 Operating income (loss) $ (149) $ 181 $ 242 $ (130) Income (loss) from continuing operations $ (48) $ 305 $ 122 $ (121) Loss from discontinued operations — — (1) (1) Net income (loss) $ (48) $ 305 $ 121 $ (122) Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (48) $ 305 $ 122 $ (121) Loss from discontinued operations — — (1) (1) Net income (loss) $ (48) $ 305 $ 121 $ (122) Basic earnings (loss) per common share: Income (loss) from continuing operations $ (0.11) $ 0.72 $ 0.29 $ (0.29) Net income (loss) $ (0.11) $ 0.72 $ 0.29 $ (0.29) Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (0.11) $ 0.72 $ 0.29 $ (0.29) Net income (loss) $ (0.11) $ 0.72 $ 0.29 $ (0.29) 2018 Product revenues $ 407 $ 520 $ 554 $ 544 Net gain (loss) on derivatives $ (69) $ (154) $ (139) $ 443 Commodity management $ 36 $ 64 $ 68 $ 36 Total revenues $ 374 $ 430 $ 484 $ 1,022 Operating costs and expenses $ 322 $ 388 $ 413 $ 447 Operating income $ 6 $ (3) $ 26 $ 525 Income (loss) from continuing operations $ (26) $ (79) $ (6) $ 353 Income (loss) from discontinued operations (89) (2) (1) 1 Net income (loss) $ (115) $ (81) $ (7) $ 354 Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (30) $ (83) $ (6) $ 353 Income (loss) from discontinued operations (89) (2) (1) 1 Net income (loss) $ (119) $ (85) $ (7) $ 354 Basic earnings (loss) per common share: Income (loss) from continuing operations $ (0.07) $ (0.21) $ (0.01) $ 0.84 Loss from discontinued operations (0.23) — — — Net income (loss) $ (0.30) $ (0.21) $ (0.01) $ 0.84 Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (0.07) $ (0.21) $ (0.01) $ 0.83 Loss from discontinued operations (0.23) — — — Net income (loss) $ (0.30) $ (0.21) $ (0.01) $ 0.83 |
Supplemental Oil and Gas Disc_2
Supplemental Oil and Gas Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Capitalized Costs | Capitalized Costs As of December 31, 2019 2018 (Millions) Proved Properties $ 8,928 $ 7,612 Unproved properties 1,765 1,891 10,693 9,503 Accumulated depreciation, depletion and amortization and valuation provisions (3,491) (2,542) Net capitalized costs $ 7,202 $ 6,961 __________ • Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $350 million and $276 million, net, as of December 31, 2019 and 2018, respectively. • Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells. • Unproved properties consist primarily of unproved leasehold costs. |
Cost Incurred | Cost Incurred For the years ended December 31, 2019 2018 2017 (Millions) Acquisition $ 115 $ 68 $ 864 Exploration 8 7 5 Development 1,099 1,350 1,048 $ 1,222 $ 1,425 $ 1,917 __________ • Costs incurred include capitalized and expensed items but excludes costs associated with facilities. • Acquisition costs are as follows: Costs in 2019 primarily reflect the purchase of surface acreage within our Delaware Basin acreage. Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin in March 2017 that included approximately $200 million and 23.8 MMboe of proved developed reserves and facilities. • Exploration costs include costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds. • Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our San Juan Basin operations were $24 million and $168 million for 2018 and 2017, respectively. |
Proved Reserves | The following is a summary of changes in our proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations. Oil (MMbbls) Natural Gas (Bcf) NGLs (MMbbls) All Products (MMboe) Proved reserves at December 31, 2016 174.6 734.5 49.5 346.4 Revisions 4.7 (8.4) (1.1) 2.3 Purchases 21.8 58.8 7.8 39.4 Divestitures (1.7) (312.5) (0.8) (54.6) Extensions and discoveries 86.7 194.5 23.6 142.7 Production (22.4) (75.9) (5.0) (40.0) Proved reserves at December 31, 2017 263.7 591.0 74.0 436.2 Revisions — (11.4) 5.3 3.4 Purchases 1.5 4.8 0.6 2.9 Divestitures (27.6) (79.8) (10.4) (51.3) Extensions and discoveries 84.5 176.9 22.7 136.7 Production (30.8) (63.8) (7.2) (48.6) Proved reserves at December 31, 2018 291.3 617.7 85.0 479.3 Revisions (10.7) 41.4 8.6 4.8 Divestitures (3.7) (10.7) (0.8) (6.3) Extensions and discoveries 56.7 170.7 25.5 110.7 Production (37.8) (78.4) (10.0) (60.9) Proved reserves at December 31, 2019 295.8 740.7 108.3 527.6 Proved developed reserves: December 31, 2017 130.3 321.2 38.8 222.7 December 31, 2018 156.4 365.4 48.4 265.8 December 31, 2019 184.3 456.5 65.5 325.9 Proved undeveloped reserves: December 31, 2017 133.4 269.8 35.2 213.5 December 31, 2018 134.9 252.3 36.6 213.5 December 31, 2019 111.5 284.2 42.8 201.7 __________ • Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. • Revisions in 2019 primarily reflect 21 MMboe of positive technical revisions partially offset by 16 MMboe of negative revisions due to a decrease in the 12 month average price. Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells. • Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed. • Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves. |
Standardized Measure of Discounted Future Net Cash Flows | Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2019 2018 (Millions) Future cash inflows $ 18,012 $ 20,963 Less: Future production costs 8,407 7,615 Future development costs 1,469 2,345 Future income tax provisions 772 1,366 Future net cash flows 7,364 9,637 Less 10 percent annual discount for estimated timing of cash flows 3,233 4,446 Standardized measure of discounted future net cash inflows $ 4,131 $ 5,191 |
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows | Sources of Change in Standardized Measure of Discounted Future Net Cash Flows For the years ended December 31, 2019 2018 2017 (Millions) Beginning of year $ 5,191 $ 3,161 $ 1,038 Sales of oil and gas produced, net of operating costs (1,515) (1,541) (894) Net change in prices and production costs (2,247) 2,004 1,385 Extensions, discoveries and improved recovery, less estimated future costs 667 1,341 816 Development costs incurred during year 636 654 345 Changes in estimated future development costs 585 (35) 105 Purchase of reserves in place, less estimated future costs — 27 305 Sale of reserves in place, less estimated future costs (63) (409) 20 Revisions of previous quantity estimates 85 75 30 Accretion of discount 548 324 104 Net change in income taxes 260 (396) (83) Other (16) (14) (10) Net changes (1,060) 2,030 2,123 End of year $ 4,131 $ 5,191 $ 3,161 |
Schedule II - valuation and qua
Schedule II - valuation and qualifying accounts schedule II (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |
Summary of Valuation Allowance [Table Text Block] | Beginning Balance Charged (Credited) to Costs and Expenses Other Deductions Ending Balance 2019: Allowance for doubtful accounts—accounts and notes $ — $ 9 $ — $ — $ 9 Deferred tax asset valuation(a) 213 3 — — 216 2018: Allowance for doubtful accounts—accounts and notes $ 2 $ — $ — $ (2) $ — Deferred tax asset valuation(a) 195 18 — — 213 Price-risk management credit reserves—liabilities(b)(c) 4 — (4) — — 2017: Allowance for doubtful accounts—accounts and notes $ 3 $ — $ — $ (1) $ 2 Deferred tax asset valuation(a)(d) 151 44 — — 195 Price-risk management credit reserves—liabilities(b)(c) 5 — (1) — 4 __________ (a) Deducted from related assets. (b) Deducted from related liabilities. (c) Included in revenues. (d) Includes impact of the Tax Cuts and Jobs Act enacted rate reduction. |
Description of Business, Basi_4
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 | |
Description of business [Line Items] | |||
Restricted Cash | $ 20 | $ 15 | |
Debt Issuance Costs, Noncurrent, Net | $ 36 | 35 | |
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Minimum | 20.00% | ||
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Maximum | 50.00% | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating Lease, Right-of-Use Asset | $ 76 | ||
Operating Lease, Liability, Noncurrent | 16 | ||
Operating Lease, Liability, Current | $ 60 | $ 0 | |
Accounting Standards Update 2016-02 [Member] | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating Lease, Right-of-Use Asset | $ 90 | ||
Operating Lease, Liability, Noncurrent | 46 | ||
Operating Lease, Liability, Current | $ 44 | ||
Restricted Stock Units | |||
Description of business [Line Items] | |||
Award vesting period | 3 years |
Description of Business, Basi_5
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Inventory [Line Items] | ||
Materials, Supplies, and Other | $ 36 | $ 46 |
Other Inventory, in Transit, Gross | 5 | 2 |
Inventories | $ 41 | $ 48 |
Discontinued Operations - Addit
Discontinued Operations - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Contractual Obligation | $ 1,013 | |||
Gain (Loss) on Disposition of Proved Property | 0 | |||
Increase (Decrease) in Other Accrued Liabilities | (28) | $ (47) | $ (53) | |
San Juan Legacy [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | 2 | |||
San Juan Gallup [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | $ 138 | |||
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax | 147 | |||
Piceance Basin [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
DisposalGroupOperatingTaxRefund | 10 | |||
Gathering and Treating [Member] | San Juan Gallup [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Contractual Obligation | 309 | $ 277 | ||
Guarantee Type, Other [Member] | San Juan Gallup [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Contractual Obligation | 9 | |||
San Juan Legacy [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Disposal Group, Including Discontinued Operation, Consideration | $ 169 | |||
Cash [Member] | San Juan Gallup [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Disposal Group, Including Discontinued Operation, Consideration | $ 667 |
Discontinued Operations - Summa
Discontinued Operations - Summarized Results of Discontinued Operations (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||
Disposal Group, Including Discontinued Operation, Revenue | $ 75 | $ 291 | ||||||||||
Disposal Group, Including Discontinued Operation, Depreciation and Amortization | 8 | 131 | ||||||||||
Disposal Group, Including Discontinued Operation, Lease Operating Expense | 7 | 50 | ||||||||||
Disposal Group Including Discontinued Operation Gathering and Transportation Expense | 12 | 70 | ||||||||||
Disposal Group, Including Discontinued Operation Taxes other than income | 5 | 23 | ||||||||||
Disposal Group Including Discontinued Operation Exploration Expense | 3 | 14 | ||||||||||
Disposal Group, Including Discontinued Operation, General and Administrative Expense | 1 | 8 | ||||||||||
Disposal group contract obligation expense | 0 | 5 | ||||||||||
Disposal Group (gain) loss on sale of Assets and Impairment charges | 0 | 50 | ||||||||||
Accretion Expense | 6 | 6 | ||||||||||
Disposal Group, Including Discontinued Operation, Other Expense | 5 | (3) | [1] | |||||||||
Disposal Group, Including Discontinued Operation, Operating Expense | 47 | 354 | ||||||||||
Disposal Group, Including Discontinued Operation, Operating Income (Loss) | 28 | (63) | ||||||||||
Disposal Group Including Discontinued Operation Income before Tax | (120) | (63) | ||||||||||
Discontinued Operation, Tax Effect of Discontinued Operation | (29) | (23) | ||||||||||
Income (loss) from discontinued operations | $ (1) | $ (1) | $ 0 | $ 0 | $ 1 | $ (1) | $ (2) | $ (89) | $ (2) | (91) | (40) | |
Domestic | ||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax | $ (148) | $ 0 | ||||||||||
[1] | Includes severance tax refund received in 2017. |
Discontinued Operations Discont
Discontinued Operations Discontinued Operations Cash Flow (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Cash Provided by (Used in) Operating Activities, Discontinued Operations | [1] | $ 44 | $ 143 |
Capital Expenditure, Discontinued Operations | $ (29) | $ (175) | |
[1] | (a) Excluding income taxes and changes to working capital. |
Earnings (Loss) Per Common Sh_3
Earnings (Loss) Per Common Share from Continuing Operations (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||||||||||
Income (loss) from continuing operations attributable to parent including preferred dividends | $ 258 | $ 242 | $ 24 | |||||||||
Preferred stock dividends, income statement impact | 0 | 8 | 15 | |||||||||
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted income (loss) per common share | $ (121) | $ 122 | $ 305 | $ (48) | $ 353 | $ (6) | $ (83) | $ (30) | $ 258 | $ 234 | $ 9 | |
Basic weighted-average shares | 420.4 | 408.4 | 395.1 | |||||||||
Diluted weighted-average shares(a) | [1] | 422 | 411.7 | 397.4 | ||||||||
Income (loss) per common share from continuing operations: | ||||||||||||
Basic (in dollars per share) | $ (0.29) | $ 0.29 | $ 0.72 | $ (0.11) | $ 0.84 | $ (0.01) | $ (0.21) | $ (0.07) | $ 0.62 | $ 0.57 | $ 0.02 | |
Diluted (in dollars per share) | $ (0.29) | $ 0.29 | $ 0.72 | $ (0.11) | $ 0.83 | $ (0.01) | $ (0.21) | $ (0.07) | $ 0.61 | $ 0.57 | $ 0.02 | |
Restricted Stock Units | ||||||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||||||||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 1.6 | 3.1 | 2.1 | |||||||||
Stock Options | ||||||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||||||||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 0 | 0.2 | 0.2 | |||||||||
[1] | Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (ii) application of the treasury stock method to certain nonvested restricted stock units. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows: Years Ended December 31, 2019 2018 2017 (Millions) Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock Not 11.4 19.8 Nonvested restricted stock units antidilutive under the treasury stock method 1.0 0.7 0.6 |
Earnings (Loss) Per Common Sh_4
Earnings (Loss) Per Common Share from Continuing Operations - (Details1) - $ / shares shares in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Weighted-average exercise price of options excluded | $ 16.84 | $ 18.05 | $ 17.80 |
Exercise price range of options excluded, upper limit | 21.81 | 21.81 | 21.81 |
Exercise price range of options excluded, lower limit | 11.75 | 16.46 | 14.41 |
Fourth quarter weighted-average market price | $ 10.67 | $ 15.16 | $ 12.10 |
Restricted Stock Units | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 1 | 0.7 | 0.6 |
Employee Stock Option [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 0.7 | 0.7 | 1.5 |
Convertible Preferred Stock [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock | 11.4 | 19.8 |
Asset Sales, Impairments and _3
Asset Sales, Impairments and Exploration Expenses - Significant Adjustments (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Proceeds from Sale of Other Assets | $ 83 | |||
Gain (Loss) on Disposition of Proved Property | 0 | |||
Other—net | $ 18 | $ 7 | $ 15 | |
Pending Litigation [Member] | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Other—net | $ 11 | |||
Permian [Member] | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | 103 | |||
Other Property | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | 8 | |||
Collaborative Arrangement, Transaction with Party to Collaborative Arrangement [Member] | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | $ 48 |
Asset Sales, Impairments and _4
Asset Sales, Impairments and Exploration Expenses - Summary of Exploration Expenses (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Results of Operations for Oil and Gas Producing Activities [Line Items] | |||
Unproved leasehold property impairments, amortization and expiration | $ 89 | $ 69 | $ 84 |
Geologic And Geophysical Costs | 6 | 6 | 3 |
Exploration Expense | $ 95 | $ 75 | $ 87 |
Investments (Details)
Investments (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2019USD ($) | Jun. 30, 2019USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2019USD ($)a | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jun. 30, 2017 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Long-term investments | $ 48 | $ 48 | $ 167 | ||||
Equity Method Investment, Realized Gain (Loss) on Disposal | $ 380 | 0 | $ 0 | ||||
Catalyst | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||
Oil and Gas Acreage Dedication For Joint Venture | a | 50,000 | ||||||
Equity Method Investments | 48 | $ 48 | 58 | ||||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | 244 | 244 | |||||
Equity Method Investment, Summarized Financial Information, Liabilities | 339 | 339 | $ 349 | ||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | $ 329 | $ 329 | |||||
Oryxx II Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 25.00% | 25.00% | |||||
Payments to Acquire Equity Method Investments | $ 93 | ||||||
Proceeds from Sale of Other Assets, Investing Activities | $ 357 | ||||||
Long-term investments | $ 110 | 110 | |||||
Equity Method Investment, Realized Gain (Loss) on Disposal | $ 247 | $ 247 | |||||
Whitewater [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 20.00% | 20.00% | |||||
Long-term investments | $ 15 | $ 15 | |||||
Equity Method Investment, Realized Gain (Loss) on Disposal | $ 7 | $ 126 | |||||
Minimum | Oryxx II Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 12.50% | ||||||
Payments to Acquire Equity Method Investments | $ 23 | ||||||
Maximum | Oryxx II Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 25.00% |
Properties and Equipment - Carr
Properties and Equipment - Carried at Cost (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | ||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment-gross, at cost | $ 11,244 | $ 9,949 | |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 3,654 | 2,683 | |
Properties and equipment-net | 7,590 | 7,266 | |
Proved properties | |||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment-gross, at cost | [1],[2] | 8,719 | 7,289 |
Unproved Properties | |||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment-gross, at cost | [1],[3] | 1,765 | 1,891 |
Gathering, Processing and Other Facilities | |||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment-gross, at cost | [1] | $ 403 | 294 |
Gathering, Processing and Other Facilities | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, estimated useful life (years) | [1] | 15 years | |
Gathering, Processing and Other Facilities | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, estimated useful life (years) | [1] | 25 years | |
Construction in Progress | |||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment-gross, at cost | [1],[3] | $ 224 | 350 |
Other | |||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment-gross, at cost | [1] | $ 133 | $ 125 |
Other | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, estimated useful life (years) | [1] | 3 years | |
Other | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, estimated useful life (years) | [1] | 40 years | |
[1] | Estimated useful lives are presented as of December 31, 2019. | ||
[2] | Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1). | ||
[3] | Unproved properties, land and construction in progress are not subject to depreciation and depletion. |
Properties and Equipment - Roll
Properties and Equipment - Rollforward Asset Retirement Obligation (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning Balance | $ 72 | $ 39 | |
Liabilities incurred during the period | 11 | 8 | |
Liabilities settled during the period | (4) | (7) | |
Estimate revisions | 14 | 30 | |
Accretion expense | [1] | 4 | 2 |
Ending Balance | 97 | 72 | |
Amount reflected as current | $ 5 | $ 5 | |
[1] | Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations. |
Property and Equipment - Additi
Property and Equipment - Additional Information (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2019USD ($) | Dec. 31, 2019a | |
Property, Plant and Equipment [Line Items] | ||
Payments to Acquire Land Held-for-use | $ | $ 100 | |
Acreage purchased | a | 14,000 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued and Other Current Liabilities - Accounts Payable (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Payables and Accruals [Abstract] | ||
Trade | $ 162 | $ 130 |
Accrual for capital expenditures | 159 | 190 |
Royalty Payable | 209 | 170 |
Cash Overdrafts | 8 | 17 |
Other | 18 | 7 |
Accounts payable | $ 556 | $ 514 |
Accounts Payable and Accrued _4
Accounts Payable and Accrued and Other Current Liabilities - Accrued and Other Current Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Payables and Accruals [Abstract] | ||
Accrual for Taxes Other than Income Taxes, Current | $ 37 | $ 19 |
Interest Payable, Current | 39 | 45 |
Accrued Compensation And Related Liabilities Current | 55 | 39 |
Gathering and transportation | 6 | 7 |
Gathering and transportation related to exited areas | 26 | 30 |
Operating Lease, Liability, Current | 60 | 0 |
Other Accrued Liabilities, Current | 28 | 38 |
Accrued liabilities and other liabilities | $ 251 | $ 178 |
Debt and Banking Arrangements -
Debt and Banking Arrangements - Debt (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | |||
Total debt | $ 2,229 | $ 2,509 | |
Debt and Capital Lease Obligations | 2,229 | 2,509 | |
Debt, Current | 0 | 0 | |
Long-term Debt, Excluding Current Maturities | 2,229 | 2,509 | |
Debt Issuance Costs, Net | [1] | 27 | 24 |
Long-term debt | [1] | 2,202 | 2,485 |
Credit Facility Agreement | |||
Debt Instrument [Line Items] | |||
Total debt | 0 | 330 | |
6.000% Senior Notes due 2022 | |||
Debt Instrument [Line Items] | |||
Total debt | 73 | 529 | |
8.250% Senior Notes due 2023 | |||
Debt Instrument [Line Items] | |||
Total debt | 406 | 500 | |
5.250 % Senior Notes due 2024 | |||
Debt Instrument [Line Items] | |||
Total debt | 650 | 650 | |
5.750% Senior Notes Due 2026 | |||
Debt Instrument [Line Items] | |||
Total debt | 500 | 500 | |
5.250% Senior Notes due 2027 | |||
Debt Instrument [Line Items] | |||
Total debt | $ 600 | $ 0 | |
[1] | Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets. |
Debt and Banking Arrangements_2
Debt and Banking Arrangements - Debt - Additional Information (Detail) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jun. 30, 2019USD ($) | |
Debt Instrument [Line Items] | |||||||
Interest Paid, Including Capitalized Interest, Operating and Investing Activities | $ 150 | $ 172 | $ 178 | ||||
Write off of Deferred Debt Issuance Cost | $ 3 | $ 6 | |||||
Gain (Loss) on Extinguishment of Debt, before Write off of Debt Issuance Cost | (44) | (63) | |||||
Debt Instrument, Repurchase Amount | 550 | 921 | |||||
Maximum Limit On Consolidated Secure Indebtedness to Consolidated EBITDAX | 4.25 | ||||||
Minimum Current Ratio | 1 | ||||||
Gain (Loss) on Extinguishment of Debt | (47) | $ (71) | (71) | $ (47) | (71) | $ (17) | |
Percentage of repurchase of notes on principal amount of notes | 101.00% | ||||||
Total debt | $ 2,229 | 2,509 | |||||
Letters of credit issued | 28 | ||||||
Credit Facility Agreement | |||||||
Debt Instrument [Line Items] | |||||||
Total debt | $ 0 | $ 330 | |||||
7.500% Senior Notes due 2020 | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Repurchase Amount | 350 | ||||||
Debt instrument stated interest rate | 7.50% | 7.50% | |||||
6.000% Senior Notes due 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Repurchase Amount | 571 | ||||||
Debt Instrument, Face Amount | $ 73 | ||||||
Debt instrument stated interest rate | 6.00% | 6.00% | |||||
Total debt | $ 73 | $ 529 | |||||
8.250% Senior Notes due 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 406 | ||||||
Debt instrument stated interest rate | 8.25% | 8.25% | |||||
Total debt | $ 406 | $ 500 | |||||
5.250 % Senior Notes due 2024 | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 650 | ||||||
Debt instrument stated interest rate | 5.25% | 5.25% | |||||
Total debt | $ 650 | $ 650 | |||||
5.750% Senior Notes Due 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Debt Issuance Costs, Gross | 1 | ||||||
Proceeds from Issuance of Debt | 494 | ||||||
Debt Instrument, Face Amount | $ 500 | $ 500 | |||||
Debt instrument stated interest rate | 5.75% | 5.75% | 5.75% | ||||
Total debt | $ 500 | $ 500 | |||||
5.250% Senior Notes due 2027 | |||||||
Debt Instrument [Line Items] | |||||||
Debt Issuance Costs, Gross | 2 | ||||||
Proceeds from Issuance of Debt | 592.5 | ||||||
Debt Instrument, Face Amount | $ 600 | $ 600 | |||||
Debt instrument stated interest rate | 5.25% | 5.25% | |||||
Total debt | $ 600 | $ 0 | |||||
Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,500 | ||||||
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases | $ 2,100 |
Provision (Benefit) for Incom_3
Provision (Benefit) for Income Taxes - Provision (Benefit) for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Current: | |||
Federal | $ (19) | $ (38) | $ (18) |
State | (1) | 1 | 1 |
Total current | (20) | (37) | (17) |
Deferred: | |||
Federal | 81 | 107 | (100) |
State | 9 | 4 | (11) |
Total Deferred | 90 | 111 | (111) |
Total provision (benefit) | $ 70 | $ 74 | $ (128) |
Provision (Benefit) for Incom_4
Provision (Benefit) for Income Taxes - Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 21.00% | 35.00% |
Provision (benefit) at statutory rate | $ 69 | $ 66 | $ (36) |
Increases (decreases) in taxes resulting from: | |||
State income taxes (net of federal benefit) | 2 | (8) | (12) |
Valuation allowance on current year state income taxes (net of federal benefit) | 14 | 17 | 17 |
Effective state income tax rate change (net of federal benefit) | (10) | (5) | (12) |
Effective Income Tax Rate Reconciliation, Reversal of valuation allowance on federal capital loss | (10) | 0 | 0 |
IncomeTaxReconciliationChangeInStatutoryTaxRate | 0 | 0 | (92) |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Payment Arrangement, Amount | 4 | 4 | 2 |
Other | 1 | 0 | 5 |
Total provision (benefit) | $ 70 | $ 74 | $ (128) |
Provision (Benefit) for Incom_5
Provision (Benefit) for Income Taxes - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Provision For Income Taxes [Line Items] | |||
Income Taxes Receivable | $ 19 | $ 38 | |
Proceeds from Income Tax Refunds | 38 | $ 39 | |
Income Taxes Paid | 2 | ||
Deferred Other Tax Expense (Benefit) | (10) | (5) | $ (12) |
Federal Excess Business Interest Expense Carryover | 20 | ||
Deferred Tax Assets, Capital Loss Carryforwards | $ 48 | ||
Operating Loss Carryforwards, Limitations on Use | 50 percent | ||
AMT Credit Carryforward Refund | $ 50 | ||
Income Tax Examination, Penalties and Interest Accrued | 1 | ||
Unrecognized Tax Benefits | 9 | ||
Deferred Tax Assets, Tax Credit Carryforwards, Other | $ 7 | ||
Uncertain tax position expiration period | 12 months | ||
Domestic Tax Authority [Member] | |||
Provision For Income Taxes [Line Items] | |||
Operating Loss Carryforwards | $ 2,100 | ||
State and Local Jurisdiction [Member] | |||
Provision For Income Taxes [Line Items] | |||
Operating Loss Carryforwards | $ 4,200 | $ 4,100 | |
Percentage Deferred Tax Assets Operating Loss Carryforwards State That Expire | 99.00% | ||
RKI [Member] | Domestic Tax Authority [Member] | |||
Provision For Income Taxes [Line Items] | |||
Operating Loss Carryforwards | $ 218 | ||
Maximum | |||
Provision For Income Taxes [Line Items] | |||
Operating Loss Carryforwards, Limitations on Use | three |
Provision (Benefit) for Incom_6
Provision (Benefit) for Income Taxes - Significant Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred tax liabilities: | ||
Properties and equipment | $ 938 | $ 797 |
Deferred tax liabilities, Derivatives, net | 0 | 33 |
Deferred Tax Liabilities, Gross | 938 | 830 |
Deferred tax assets: | ||
Accrued liabilities and other | 156 | 137 |
Alternative minimum tax credits | 21 | 40 |
Loss carryovers | 682 | 665 |
Deferred tax assets, Derivatives, net | 5 | 0 |
Total deferred tax assets | 864 | 842 |
Less: valuation allowance | 216 | 213 |
Total net deferred tax assets | 648 | 629 |
Deferred Tax Liabilities, Net | $ 290 | $ 201 |
Lease Costs (Details)
Lease Costs (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($) | ||
Lessee, Lease, Description [Line Items] | ||
Lease, Cost | $ 227 | |
Operating Lease, Payments | 19 | [1] |
Operating Lease, Payments, Use | 42 | [1] |
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | $ 44 | |
Operating Lease, Weighted Average Remaining Lease Term | 1 year 4 months 9 days | |
Operating Lease, Weighted Average Discount Rate, Percent | 5.00% | |
Upstream Equipment [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | $ 42 | [1] |
Variable Lease, Cost | 6 | [1] |
Short-term Lease, Cost | 41 | [2] |
Other Energy Equipment [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | 19 | [1] |
Variable Lease, Cost | 3 | [1] |
Short-term Lease, Cost | $ 116 | [2] |
[1] | Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners. | |
[2] | Includes variable lease costs on short-term leases. |
Lease Liabilities Maturity (Det
Lease Liabilities Maturity (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months | $ 62 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two | 15 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three | 1 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four | 0 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five | 0 | |
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five | 0 | |
Lessee, Operating Lease, Liability, Payments, Due, Total | 78 | |
Operating Lease, Liability, Current | 60 | $ 0 |
Operating Lease, Liability, Noncurrent | 16 | |
Operating Lease, Liability, Total | 76 | |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | 2 | |
Operating Lease, Right-of-Use Asset | 76 | |
Upstream Equipment [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months | 44 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two | 5 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three | 0 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four | 0 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five | 0 | |
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five | 0 | |
Operating Lease, Liability, Current | 43 | |
Operating Lease, Liability, Noncurrent | 5 | |
Operating Lease, Liability, Total | 48 | |
Other Machinery and Equipment [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months | 18 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two | 10 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three | 1 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Four | 0 | |
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five | 0 | |
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five | 0 | |
Operating Lease, Liability, Current | 17 | |
Operating Lease, Liability, Noncurrent | 11 | |
Operating Lease, Liability, Total | $ 28 |
Employee Benefit Plans - Additi
Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Employee Benefit And Retirement Plans [Line Items] | |||
Defined contribution plan, employer contribution | $ 10 | $ 10 | $ 11 |
Postretirement Defined Benefit Plans, Liabilities | $ 7 | $ 7 | |
Maximum | |||
Employee Benefit And Retirement Plans [Line Items] | |||
Defined contribution plan, employer matching percentage | 6.00% | ||
If employees are under age 40 [Member] | |||
Employee Benefit And Retirement Plans [Line Items] | |||
Defined contribution plan, employer matching percentage | 6.00% | ||
If employees are 40 years or older [Member] | |||
Employee Benefit And Retirement Plans [Line Items] | |||
Defined contribution plan, employer matching percentage | 8.00% |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized stock based compensation | $ 44,000 | ||
Unrecognized stock based compensation, weighted average period of recognition | 2 years 7 months 6 days | ||
Value of stock option exercised during year | $ 468 | $ 4,300 | $ 224 |
Cash received from stock option exercises | 500 | 9,200 | 400 |
Administrative expenses | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock based compensation expense | $ 34,000 | $ 32,000 | $ 28,000 |
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance based share granted, percent of nonvested restricted stock units outstanding | 35.00% | ||
Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized | 7,400 | ||
Shares reserved for issuance | 15,000 | ||
Shares available for future grants | 8,000 | ||
Employee stock purchase plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized | 750 | ||
Discount allowed on employee stock purchase plan | 15.00% | ||
Number of share purchased under stock option plan | 106 | ||
Stock option plan, average purchase price | $ 9.82 | ||
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Range of vested shares of original grant amount | 0.00% | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Range of vested shares of original grant amount | 200.00% | ||
Maximum | Employee stock purchase plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares reserved for issuance | 1,000 |
Stock-Based Compensation - Summ
Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Detail) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($)$ / sharesshares | |
Weighted Average Exercise Price | |
Average remaining contractual life exercisable | 2 years 2 months 12 days |
Average remaining contractual life outstanding | 2 years 2 months 12 days |
Beginning balance (in dollars per share) | $ / shares | $ 16 |
Granted (in dollars per share) | $ / shares | 0 |
Exercised (in dollars per share) | $ / shares | 7.29 |
Forfeited (in dollars per share) | $ / shares | 16.40 |
Ending balance (in dollars per share) | $ / shares | 16.84 |
Exercisable at end of period (in dollars per share) | $ / shares | $ 16.84 |
Option Outstanding | |
Beginning balance (in shares) | shares | 1.1 |
Granted (in shares) | shares | 0 |
Exercised (in shares) | shares | 0.1 |
Forfeited (in shares) | shares | 0.3 |
Ending balance (in shares) | shares | 0.7 |
Exercisable at end of period (in shares) | shares | 0.7 |
Aggregate Intrinsic Value | |
Beginning balance | $ | $ 0.3 |
Ending balance | $ | 0.2 |
Exercisable at end of period | $ | $ 0.2 |
Stock-Based Compensation - Su_2
Stock-Based Compensation - Summary of Nonvested Restricted Stock Unit Activity and Related Information (Detail) shares in Millions | 12 Months Ended | |
Dec. 31, 2019$ / sharesshares | ||
Nonvested Shares | ||
Beginning Balance | shares | 5.4 | |
Granted | shares | 3.8 | |
Forfeited | shares | (0.1) | |
Vested | shares | (3.2) | |
Ending balance | shares | 5.9 | |
Weighted-Average Fair Value | ||
Beginning Balance | $ / shares | $ 15.01 | [1] |
Granted | $ / shares | 13.16 | [1] |
Forfeited | $ / shares | 13.12 | [1] |
Vested | $ / shares | 13.92 | [1] |
Ending Balance | $ / shares | $ 14.78 | [1] |
[1] | 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. |
Stock-Based Compensation - Othe
Stock-Based Compensation - Other Restricted Stock Unit (Detail) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items] | ||||
Weighted-average grant date fair value of restricted stock units granted during the year, per share | [1] | $ 13.16 | ||
Restricted Stock Units | ||||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items] | ||||
Weighted-average grant date fair value of restricted stock units granted during the year, per share | $ 13.16 | $ 16.74 | $ 13.76 | |
Total fair value of restricted stock units vested during the year (millions) | $ 45 | $ 26 | $ 33 | |
[1] | 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. |
Stockholders' Equity - Addition
Stockholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items] | |||
Proceeds from common stock | $ 2 | $ 10 | $ 672 |
Stock Repurchase Program, Authorized Amount | $ 400 | ||
Stock Repurchased During Period, Shares | 5,700 | ||
Share Repurchase, Average Price Per Share | $ 10.16 | ||
Transaction costs related to partnerships | $ 6 | ||
Common Stock | |||
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items] | |||
Stock Issued During Period, Shares, New Issues | 51,675 | ||
Proceeds from common stock | $ 670 | ||
Sale of Stock, Price Per Share | $ 12.97 | ||
Over-Allotment Option [Member] | Common Stock | |||
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items] | |||
Stock Issued During Period, Shares, New Issues | 6,675 | ||
Minimum | |||
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items] | |||
Noncontrolling interest, future contribution percentage | 80.00% | ||
Maximum | |||
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items] | |||
Noncontrolling interest, future contribution percentage | 85.00% |
Contingent Liabilities and Co_3
Contingent Liabilities and Commitments - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2015 | |
Loss Contingencies [Line Items] | ||||
Asset Retirement Obligation | $ 97 | $ 72 | $ 39 | |
Service commitment period | 7 years | |||
Total rent expenses | 25 | $ 19 | ||
Powder River [Member] | ||||
Loss Contingencies [Line Items] | ||||
Asset Retirement Obligation | $ 46 | |||
Surface Use Agreement Payments | $ 6 | |||
Royalty Litigation | ||||
Loss Contingencies [Line Items] | ||||
Loss contingencies associated with royalty litigation | $ 10 | $ 11 |
Contingent Liabilities and Co_4
Contingent Liabilities and Commitments - Commitments Under Contracts (Detail) $ in Millions | Dec. 31, 2019USD ($) |
Long-term Purchase Commitment [Line Items] | |
2020 | $ 167 |
2021 | 142 |
2022 | 130 |
2023 | 115 |
2024 | 112 |
Thereafter | 347 |
Total | 1,013 |
Other Liabilities | 36 |
Gas Transportation and Storage [Member] | |
Long-term Purchase Commitment [Line Items] | |
2020 | 114 |
2021 | 94 |
2022 | 87 |
2023 | 75 |
2024 | 76 |
Thereafter | 315 |
Total | 761 |
Other Liabilities | 21 |
Midstream Services [Member] | |
Long-term Purchase Commitment [Line Items] | |
2020 | 53 |
2021 | 48 |
2022 | 43 |
2023 | 40 |
2024 | 36 |
Thereafter | 32 |
Total | 252 |
Other Liabilities | $ 15 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term debt, Fair Value | [1] | $ 2,400 | $ 2,414 |
Long-term Debt | 2,229 | 2,509 | |
Energy Related Derivative | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Energy derivative assets | 67 | 178 | |
Energy derivative liabilities | 91 | 37 | |
Level 1 | Energy Related Derivative | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Energy derivative assets | 0 | 0 | |
Energy derivative liabilities | 0 | 0 | |
Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term debt, Fair Value | [1] | 2,400 | 2,414 |
Level 2 | Energy Related Derivative | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Energy derivative assets | 67 | 175 | |
Energy derivative liabilities | 91 | 37 | |
Level 3 | Energy Related Derivative | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Energy derivative assets | 0 | 3 | |
Energy derivative liabilities | 0 | $ 0 | |
Level 3 | Minimum | Energy Related Derivative | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Energy derivative assets | $ 1 | ||
[1] | The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of December 31, 2019 and 2018, respectively. |
Fair Value Measurements - Impai
Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2017 | Dec. 31, 2019 | Dec. 31, 2017 | Dec. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | $ 0 | |||
Impairment of Oil and Gas Properties | $ 60 | |||
Permian [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Gain (Loss) on Disposition of Proved Property | $ 103 | |||
Fair Value of Leasehold Exchanges | $ 200 | |||
Energy Related Derivative | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Energy derivative assets | 67 | $ 178 | ||
Energy Related Derivative | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Energy derivative assets | $ 0 | $ 3 |
Derivatives and Concentration_3
Derivatives and Concentration of Credit Risk - Derivatives related to production (Detail) - Derivatives related to production - Short Position [Member] BTU / d in Thousands | 12 Months Ended | |
Dec. 31, 2019bbl / dBTU / d$ / bbl$ / MMBtu | [2] | |
Price Risk Derivative [Member] | 2020 [Member] | Crude Oil [Member] | WTI | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 65,129 | [1],[3] |
Underlying, Derivative Energy Measure | 57.07 | [3],[4] |
Basis Swap [Member] | 2020 [Member] | Crude Oil [Member] | Midland-Cushing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 7,486 | [1] |
Underlying, Derivative | (1.31) | [4] |
Basis Swap [Member] | 2020 [Member] | Crude Oil [Member] | Brent/WTI [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 5,000 | [1] |
Underlying, Derivative Energy Measure | 8.36 | [4] |
Basis Swap [Member] | 2020 [Member] | Natural Gas | Waha [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | BTU / d | 60 | [1] |
Underlying, Derivative | $ / MMBtu | (0.79) | [4] |
Basis Swap [Member] | 2021 [Member] | Crude Oil [Member] | Brent/WTI [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 1,000 | [1] |
Underlying, Derivative Energy Measure | 8 | [4] |
Basis Swap [Member] | 2021 [Member] | Natural Gas | Waha [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | BTU / d | 70 | [1] |
Underlying, Derivative | $ / MMBtu | (0.59) | [4] |
Basis Swap [Member] | 2022 [Member] | Crude Oil [Member] | Brent/WTI [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 1,000 | [1] |
Underlying, Derivative Energy Measure | 7.75 | [4] |
Basis Swap [Member] | 2022 [Member] | Natural Gas | Waha [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | BTU / d | 70 | [1] |
Underlying, Derivative | $ / MMBtu | (0.57) | [4] |
Basis Swap [Member] | 2023 [Member] | Natural Gas | Waha [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | BTU / d | 70 | [1] |
Underlying, Derivative | $ / MMBtu | (0.51) | [4] |
Swaption [Member] | 2021 [Member] | Crude Oil [Member] | WTI | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 20,000 | [1] |
Underlying, Derivative Energy Measure | 57.02 | [4] |
Put Option [Member] | 2020 [Member] | Crude Oil [Member] | WTI | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | bbl / d | 20,000 | [1] |
Put Option [Member] | 2020 [Member] | Minimum | Crude Oil [Member] | WTI | ||
Derivative [Line Items] | ||
Underlying, Derivative Energy Measure | 53.33 | [4] |
Put Option [Member] | 2020 [Member] | Maximum | Crude Oil [Member] | WTI | ||
Derivative [Line Items] | ||
Underlying, Derivative Energy Measure | 63.48 | [4] |
[1] | Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day. | |
[2] | Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. | |
[3] | Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests | |
[4] | The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.(d) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests. |
Derivatives and Concentration_4
Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk - Fair Values and Gains (Losses) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
DerivativeGainLoss [Line Items] | ||||||||||||
Net gain (loss) on derivatives | $ (199) | $ 175 | $ 78 | $ (207) | $ 443 | $ (139) | $ (154) | $ (69) | $ (153) | $ 81 | $ 3 | |
Energy Related Derivative | ||||||||||||
DerivativeGainLoss [Line Items] | ||||||||||||
Net gain (loss) on derivatives | [1] | (150) | 78 | 3 | ||||||||
Derivative, Cost of Hedge | 237 | |||||||||||
Derivative, Cash Received on Hedge | 12 | 4 | ||||||||||
Derivatives Related to Physical Marketing Agreements | ||||||||||||
DerivativeGainLoss [Line Items] | ||||||||||||
Net gain (loss) on derivatives | [2] | (3) | 3 | 0 | ||||||||
Derivative, Cost of Hedge | $ 1 | $ 1 | $ 1 | |||||||||
[1] | Includes settlements totaling $12 million for the year ended December 31, 2019, payments totaling $237 million for the year ended December 31, 2018, and settlements totaling $4 million for the year ended December 31, | |||||||||||
[2] | Includes payments totaling less than $1 million for the years ended December 31, 2019, 2018 and 2017. |
Derivatives and Concentration_5
Derivatives and Concentration of Credit Risk - Offsetting of derivative assets and liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative Asset [Abstract] | |||
Gross Amount Presented on Balance Sheet | $ 67 | $ 178 | |
Netting Adjustment | [1] | (45) | (37) |
Net Amount | 22 | 141 | |
Derivative Liability [Abstract] | |||
Gross Amount Presented on Balance Sheet | (91) | (37) | |
Netting adjustment | [1] | 45 | 37 |
Net Amount | $ (46) | $ 0 | |
[1] | With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts. |
Derivatives and Concentration_6
Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk - Credit risk related features (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Credit Derivatives [Line Items] | ||
Increase (Decrease) in Derivative Liabilities | $ (1) | |
Derivative, Net Liability Position, Aggregate Fair Value | 1 | |
Additional Collateral, Aggregate Fair Value | $ 1 | |
Maximum | ||
Credit Derivatives [Line Items] | ||
Increase (Decrease) in Derivative Liabilities | $ (1) | |
Derivative, Net Liability Position, Aggregate Fair Value | 46 | |
Additional Collateral, Aggregate Fair Value | $ 46 |
Derivatives and Concentration_7
Derivatives and Concentration of Credit Risk - Concentration of Credit Risk (Detail) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017 | |
Concentration Risk [Line Items] | |||
Accounts Receivable, Net | $ 450 | $ 405 | |
Income Taxes Receivable | 19 | 38 | |
Maximum Potential Future Exposure On Credit Risk Derivatives Gross | 67 | ||
Maximum Potential Future Exposure On Credit Risk Derivatives Net | $ 22 | ||
Number of largest net counter party positions investment grade | 5 | ||
Percentage of net credit exposure from derivatives | 98.00% | ||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ 40 | ||
Other Products And Services [Member] | |||
Concentration Risk [Line Items] | |||
Accounts Receivable, Net | 336 | 269 | |
Other Ownership Interest [Member] | |||
Concentration Risk [Line Items] | |||
Accounts Receivable, Net | 88 | 98 | |
Other Receivables [Member] | |||
Concentration Risk [Line Items] | |||
Accounts Receivable, Net | $ 7 | $ 0 | |
United Energy Trading [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 20.00% | 23.00% | |
Occidental [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 18.00% | 16.00% | |
Crestwood [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 21.00% | ||
St. Paul Refining [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 16.00% | ||
Delek Refining [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 10.00% | ||
BP Products North America, Inc [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 11.00% | ||
NGL Energy Partners [Member] | NGL Crude Logistics [Member] | Sales Revenue, Net [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 13.00% | 14.00% | 13.00% |
NGL Energy Partners [Member] | Minimum | Operating Expense [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 2.00% |
Pending Felix Acquisition (Deta
Pending Felix Acquisition (Details) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020USD ($) | Dec. 31, 2019USD ($)aWell$ / sharesshares | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Business Acquisition [Line Items] | ||||
Payments to Acquire Businesses, Gross | $ 0 | $ 0 | $ 799 | |
Interest Expense | 159 | $ 163 | $ 188 | |
Senior Notes Due Twenty Thirty [Member] | Subsequent Event [Member] | ||||
Business Acquisition [Line Items] | ||||
Proceeds from Issuance of Debt | $ 900 | |||
Debt instrument stated interest rate | 4.50% | |||
Felix [Member] | ||||
Business Acquisition [Line Items] | ||||
Unadjusted purchase price | 2,500 | |||
Payments to Acquire Businesses, Gross | $ 900 | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 152,963,671 | |||
Unadjusted equity consideration | $ 1,600 | |||
Business Acquisition, Share Price | $ / shares | $ 10.46 | |||
Interest Expense | $ 3 | |||
Business Acquisition, Transaction Costs | $ 3 | |||
Gas and Oil Area, Developed, Net | a | 58,500 | |||
Number of productive benches | 6 | |||
Gross drillable locations | Well | 1,500 |
Quarterly Financial Data Quarte
Quarterly Financial Data Quarterly Financial Data-Summarized Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Data [Line Items] | |||||||||||
Net gain (loss) on derivatives | $ (199) | $ 175 | $ 78 | $ (207) | $ 443 | $ (139) | $ (154) | $ (69) | $ (153) | $ 81 | $ 3 |
Total revenues | 443 | 795 | 695 | 359 | 1,022 | 484 | 430 | 374 | 2,292 | 2,310 | 1,045 |
Operating Costs and Expenses | 472 | 454 | 422 | 410 | 447 | 413 | 388 | 322 | |||
Operating Income (Loss) | (130) | 242 | 181 | (149) | 525 | 26 | (3) | 6 | 144 | 554 | 98 |
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest | (121) | 122 | 305 | (48) | 353 | (6) | (79) | (26) | 258 | 242 | 24 |
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest | (1) | (1) | 0 | 0 | 1 | (1) | (2) | (89) | (2) | (91) | (40) |
Net loss attributable to WPX Energy, Inc. | (122) | 121 | 305 | (48) | 354 | (7) | (81) | (115) | 256 | 151 | (16) |
Income (loss) from continuing operations attributable to WPX | (121) | 122 | 305 | (48) | 353 | (6) | (83) | (30) | 258 | 234 | 9 |
Income (loss) from discontinued operations attributable to WPX | (1) | (1) | 0 | 0 | 1 | (1) | (2) | (89) | (2) | (91) | (40) |
Net Income (Loss) Available to Common Stockholders, Basic | $ (122) | $ 121 | $ 305 | $ (48) | $ 354 | $ (7) | $ (85) | $ (119) | $ 256 | $ 143 | $ (31) |
Income (loss) from continuing operations, per basic share | $ (0.29) | $ 0.29 | $ 0.72 | $ (0.11) | $ 0.84 | $ (0.01) | $ (0.21) | $ (0.07) | $ 0.62 | $ 0.57 | $ 0.02 |
Discontinued operation, income (loss) from discontinued operation, net of tax, per basic share | 0 | 0 | 0 | (0.23) | (0.01) | (0.22) | (0.10) | ||||
Earnings per share, basic | (0.29) | 0.29 | 0.72 | (0.11) | 0.84 | (0.01) | (0.21) | (0.30) | 0.61 | 0.35 | (0.08) |
Income (loss) from continuing operations, per diluted share | (0.29) | 0.29 | 0.72 | (0.11) | 0.83 | (0.01) | (0.21) | (0.07) | 0.61 | 0.57 | 0.02 |
Discontinued operation, income (loss) from discontinued operation, net of tax, per diluted share | 0 | 0 | 0 | (0.23) | 0 | (0.22) | (0.10) | ||||
Earnings per share, diluted | $ (0.29) | $ 0.29 | $ 0.72 | $ (0.11) | $ 0.83 | $ (0.01) | $ (0.21) | $ (0.30) | $ 0.61 | $ 0.35 | $ (0.08) |
Oil and Gas [Member] | |||||||||||
Quarterly Financial Data [Line Items] | |||||||||||
Revenue from contract with customer, including assessed tax | $ 601 | $ 581 | $ 558 | $ 507 | $ 544 | $ 554 | $ 520 | $ 407 | $ 2,247 | $ 2,025 | $ 1,016 |
Oil and Gas, Refining and Marketing [Member] | |||||||||||
Quarterly Financial Data [Line Items] | |||||||||||
Revenue from contract with customer, including assessed tax | $ 39 | $ 38 | $ 58 | $ 59 | $ 36 | $ 68 | $ 64 | $ 36 | $ 194 | $ 204 | $ 25 |
Quarterly Financial Data - Addi
Quarterly Financial Data - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Data [Line Items] | ||||||||||
Equity Method Investment, Realized Gain (Loss) on Disposal | $ 380 | $ 0 | $ 0 | |||||||
Gain (Loss) on Disposition of Proved Property | 0 | |||||||||
Contractual Obligation | $ 1,013 | 1,013 | ||||||||
Gain (Loss) on Extinguishment of Debt | $ (47) | $ (71) | $ (71) | (47) | (71) | (17) | ||||
Other—net | 18 | $ 7 | $ 15 | |||||||
San Juan Gallup [Member] | ||||||||||
Quarterly Financial Data [Line Items] | ||||||||||
Gain (Loss) on Disposition of Proved Property | $ 138 | |||||||||
Pending Litigation [Member] | ||||||||||
Quarterly Financial Data [Line Items] | ||||||||||
Other—net | $ 11 | |||||||||
Oryxx II Pipeline | ||||||||||
Quarterly Financial Data [Line Items] | ||||||||||
Equity Method Investment, Realized Gain (Loss) on Disposal | $ 247 | $ 247 | ||||||||
Whitewater [Member] | ||||||||||
Quarterly Financial Data [Line Items] | ||||||||||
Equity Method Investment, Realized Gain (Loss) on Disposal | $ 7 | $ 126 | ||||||||
Guarantee Type, Other [Member] | San Juan Gallup [Member] | ||||||||||
Quarterly Financial Data [Line Items] | ||||||||||
Contractual Obligation | $ 9 |
Supplemental Oil and Gas Disc_3
Supplemental Oil and Gas Disclosures - Capitalization Cost (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Proved Properties | $ 8,928 | $ 7,612 |
Unproved properties | 1,765 | 1,891 |
Total property costs | 10,693 | 9,503 |
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities | 3,491 | 2,542 |
Net capitalized costs | 7,202 | 6,961 |
Equipment and facilities in support of oil and gas production excluded from capitalization | $ 350 | $ 276 |
Supplemental Oil and Gas Disc_4
Supplemental Oil and Gas Disclosures - Cost Incurred (Detail) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($)MMBoe | Dec. 31, 2017USD ($)MMBoe | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Acquisition | $ 115 | $ 68 | $ 864 |
Exploration | 8 | 7 | 5 |
Development | 1,099 | 1,350 | 1,048 |
Total costs incurred | $ 1,222 | 1,425 | 1,917 |
Permian [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | 13 | 200 | |
San Juan [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Development | $ 24 | $ 168 | |
Oil [Member] | Permian [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved Developed Reserves (Energy) | MMBoe | 0.6 | 23.8 |
Supplemental Oil and Gas Disc_5
Supplemental Oil and Gas Disclosures - Proved Reserves (Detail) | 12 Months Ended | |||
Dec. 31, 2019MMBoeMMBblsMMcf | Dec. 31, 2018MMBoeMMBblsMMcf | Dec. 31, 2017MMBoeMMcfMMBbls | Dec. 31, 2016MMBoeMMBblsMMcf | |
Reserve Quantities [Line Items] | ||||
Computation Of Oil Natural Gas And Ngl Reserves | Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. | |||
Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | (10.7) | 0 | 4.7 | |
Proved Developed and Undeveloped Reserves, Net | 295.8 | 291.3 | 263.7 | 174.6 |
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | (3.7) | (27.6) | (1.7) | |
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | 56.7 | 84.5 | 86.7 | |
Proved Developed and Undeveloped Reserves, Production | (37.8) | (30.8) | (22.4) | |
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | 1.5 | 21.8 | ||
Proved Undeveloped Reserve (Volume) | 111.5 | 134.9 | 133.4 | |
Proved Developed Reserves (Volume) | 184.3 | 156.4 | 130.3 | |
Natural Gas | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMcf | 41,400 | (11,400) | (8,400) | |
Proved Developed and Undeveloped Reserves, Net | MMcf | 740,700 | 617,700 | 591,000 | 734,500 |
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MMcf | (10,700) | (79,800) | (312,500) | |
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | MMcf | 170,700 | 176,900 | 194,500 | |
Proved Developed and Undeveloped Reserves, Production | MMcf | (78,400) | (63,800) | (75,900) | |
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | MMcf | 4,800 | 58,800 | ||
Proved Undeveloped Reserve (Volume) | MMcf | 284,200 | 252,300 | 269,800 | |
Proved Developed Reserves (Volume) | MMcf | 456,500 | 365,400 | 321,200 | |
Natural Gas Liquids | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 8.6 | 5.3 | (1.1) | |
Proved Developed and Undeveloped Reserves, Net | 108.3 | 85 | 74 | 49.5 |
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | (0.8) | (10.4) | (0.8) | |
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | 25.5 | 22.7 | 23.6 | |
Proved Developed and Undeveloped Reserves, Production | (10) | (7.2) | (5) | |
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | 0.6 | 7.8 | ||
Proved Undeveloped Reserve (Volume) | 42.8 | 36.6 | 35.2 | |
Proved Developed Reserves (Volume) | 65.5 | 48.4 | 38.8 | |
All products | ||||
Reserve Quantities [Line Items] | ||||
Beginning Balance | MMBoe | 527.6 | 479.3 | 436.2 | 346.4 |
Revisions | MMBoe | 4.8 | 3.4 | 2.3 | |
Purchases | MMBoe | 2.9 | 39.4 | ||
Divestitures | MMBoe | (6.3) | (51.3) | (54.6) | |
Extensions and discoveries | MMBoe | 110.7 | 136.7 | 142.7 | |
Production | MMBoe | (60.9) | (48.6) | (40) | |
Proved Developed Reserves (Energy) | MMBoe | 325.9 | 265.8 | 222.7 | |
Proved Undeveloped Reserves (Energy) | MMBoe | 201.7 | 213.5 | 213.5 | |
Proved Developed Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Purchases | MMBoe | 23.8 | |||
Extensions and discoveries | MMBoe | 42 | 52 | 46 | |
Proved Undeveloped Reserves [Member] [Member] | ||||
Reserve Quantities [Line Items] | ||||
Extensions and discoveries | MMBoe | 68 | 85 | 97 | |
San Juan [Member] | Proved Developed Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Divestitures | MMBoe | (40) | (28.7) | ||
San Juan [Member] | Proved Undeveloped Reserves [Member] [Member] | ||||
Reserve Quantities [Line Items] | ||||
Divestitures | MMBoe | (11) | (16.6) | ||
Negative [Member] | ||||
Reserve Quantities [Line Items] | ||||
Revisions | MMBoe | (16) | (5) | (22) | |
Positive [Member] | ||||
Reserve Quantities [Line Items] | ||||
Revisions | MMBoe | 21 | 9 | 24 |
Supplemental Oil and Gas Disc_6
Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 18,012 | $ 20,963 | ||
Future production costs | 8,407 | 7,615 | ||
Future development costs | 1,469 | 2,345 | ||
Future income tax provisions | 772 | 1,366 | ||
Future net cash flows | 7,364 | 9,637 | ||
Less 10 percent annual discount for estimated timing of cash flows | (3,233) | (4,446) | ||
Standardized measure of discounted future net cash inflows | $ 4,131 | $ 5,191 | $ 3,161 | $ 1,038 |
Supplemental Oil and Gas Disc_7
Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Standardized measure of discounted future net cash flows beginning of period | $ 5,191 | $ 3,161 | $ 1,038 |
Sales of oil and gas produced, net of operating costs | (1,515) | (1,541) | (894) |
Net change in prices and production costs | (2,247) | 2,004 | 1,385 |
Extensions, discoveries and improved recovery, less estimated future costs | 667 | 1,341 | 816 |
Development costs incurred during year | 636 | 654 | 345 |
Changes in estimated future development costs | 585 | (35) | 105 |
Purchase of reserves in place, less estimated future costs | 0 | 27 | 305 |
Sale of reserves in place, loss estimated future costs | (63) | (409) | 20 |
Revisions of previous quantity estimates | 85 | 75 | 30 |
Accretion of discount | 548 | 324 | 104 |
Net change in income taxes | 260 | (396) | (83) |
Other | (16) | (14) | (10) |
Net changes | (1,060) | 2,030 | 2,123 |
Standardized measure of discounted future net cash flows end of period | $ 4,131 | $ 5,191 | $ 3,161 |
Supplemental Oil and Gas Disc_8
Supplemental Oil and Gas Disclosures - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2019$ / bbl$ / Mcfe | Dec. 31, 2018$ / bbl$ / Mcfe | Dec. 31, 2017$ / bbl$ / Mcfe | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Weighted average natural gas price | $ / Mcfe | 0.97 | 1.21 | 1.67 |
Average NGL price | 13.23 | 26.76 | 21.16 |
Weighted Average Oil Per Barrel Price | 53.62 | 61.57 | 46.39 |
Discount Rate | 10.00% |
II-Valuation and Qualifying A_2
II-Valuation and Qualifying Accounts (Detail) - USD ($) $ in Millions | 12 Months Ended | ||||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||
Price-risk management credit reserves-liabilities [Member] | |||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount | [1],[2] | $ 0 | $ 4 | $ 5 | |||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense | [1],[2] | 0 | 0 | ||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease) | [1],[2] | (4) | (1) | ||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | [1],[2] | 0 | 0 | ||||
SEC Schedule, 12-09, Allowance, Notes Receivable | |||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount | [3] | $ 9 | 0 | 2 | 3 | ||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense | [3] | 9 | 0 | 0 | |||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease) | [3] | 0 | 0 | 0 | |||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | [3] | 0 | 2 | 1 | |||
SEC Schedule, 12-09, Valuation Allowance, Deferred Tax Asset [Member] | |||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount | [3] | 216 | 213 | 195 | [4] | $ 151 | [4] |
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense | [3] | 3 | 18 | 44 | [4] | ||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Period Increase (Decrease) | [3] | 0 | 0 | 0 | [4] | ||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | [3] | $ 0 | $ 0 | $ 0 | [4] | ||
[1] | Deducted from related liabilities. | ||||||
[2] | Included in revenues. | ||||||
[3] | Deducted from related assets. | ||||||
[4] | Includes impact of the Tax Cuts and Jobs Act enacted rate reduction |