Document And Entity Information
Document And Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | May 04, 2018 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Trading Symbol | PXD | |
Entity Registrant Name | PIONEER NATURAL RESOURCES CO | |
Entity Central Index Key | 1,038,357 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 170,427,473 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 1,001 | $ 896 |
Short-term investments | 722 | 1,213 |
Accounts receivable: | ||
Trade, net | 826 | 644 |
Due from affiliates | 0 | 1 |
Income taxes receivable | 7 | 7 |
Inventories | 218 | 212 |
Assets held for sale | 20 | 0 |
Derivatives | 7 | 11 |
Other | 23 | 23 |
Total current assets | 2,824 | 3,007 |
Oil and gas properties, using the successful efforts method of accounting: | ||
Proved properties | 20,892 | 20,404 |
Unproved properties | 568 | 558 |
Accumulated depletion, depreciation and amortization | (9,230) | (9,196) |
Total property, plant and equipment | 12,230 | 11,766 |
Long-term investments | 93 | 66 |
Goodwill | 269 | 270 |
Other property and equipment, net | 1,799 | 1,762 |
Other assets, net | 108 | 132 |
Total Assets | 17,323 | 17,003 |
Accounts payable: | ||
Trade | 1,222 | 1,174 |
Due to affiliates | 48 | 108 |
Interest payable | 38 | 59 |
Income taxes payable | 1 | 0 |
Current portion of long-term debt | 449 | 449 |
Liabilities held for sale | 6 | 0 |
Derivatives | 333 | 232 |
Other | 153 | 106 |
Total current liabilities | 2,250 | 2,128 |
Long-term debt | 2,284 | 2,283 |
Derivatives | 54 | 23 |
Deferred income taxes | 928 | 899 |
Other liabilities | 405 | 391 |
Equity: | ||
Common stock, $.01 par value | 2 | 2 |
Additional paid-in capital | 8,991 | 8,974 |
Treasury stock at cost | (294) | (249) |
Retained earnings | 2,698 | 2,547 |
Total equity attributable to common stockholders | 11,397 | 11,274 |
Noncontrolling interests in consolidated subsidiaries | 5 | 5 |
Total equity | 11,402 | 11,279 |
Commitments and contingencies | ||
Total Liabilities and Equity | $ 17,323 | $ 17,003 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Mar. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (usd per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 500,000,000 | 500,000,000 |
Common stock, shares issued | 174,288,821 | 173,796,743 |
Treasury stock, shares | 3,869,865 | 3,608,132 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Revenues and other income: | ||
Sales of purchased oil and gas | $ 1,070 | $ 316 |
Interest and other | 18 | 13 |
Derivative gains (losses), net | (208) | 151 |
Gain on disposition of assets, net | 4 | 11 |
Total revenues and other income | 2,150 | 1,300 |
Costs and expenses: | ||
Oil and gas | 1,266 | 809 |
Oil and gas production | 213 | 141 |
Production and ad valorem taxes | 76 | 47 |
Depletion, depreciation and amortization | 357 | 337 |
Purchased oil and gas | 1,054 | 335 |
Impairment of oil and gas properties | 0 | 285 |
Exploration and abandonments | 35 | 33 |
General and administrative | 90 | 84 |
Accretion of discount on asset retirement obligations | 4 | 5 |
Interest | 36 | 46 |
Other | 57 | 60 |
Costs and Expenses | 1,922 | 1,373 |
Income (loss) before income taxes | 228 | (73) |
Income tax benefit (provision) | (50) | 31 |
Net income (loss) attributable to common stockholders | 178 | (42) |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ 178 | $ (42) |
Basic and diluted net income (loss) per share attributable to common stockholders (usd per share) | $ 1.04 | $ (0.25) |
Weighted average shares outstanding: | ||
Weighted average shares, basic | 170 | 170 |
Weighted average shares, diluted | 171 | 170 |
Dividends declared per share (usd per share) | $ 0.16 | $ 0.04 |
Consolidated Statement Of Equit
Consolidated Statement Of Equity - 3 months ended Mar. 31, 2018 - USD ($) shares in Thousands, $ in Millions | Total | Common Stock | Additional Paid-in Capital | Treasury Stock | Retained Earnings | Noncontrolling Interests |
Beginning Balance, shares at Dec. 31, 2017 | 170,189 | |||||
Beginning Balance at Dec. 31, 2017 | $ 11,279 | $ 2 | $ 8,974 | $ (249) | $ 2,547 | $ 5 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Dividends declared ($0.16 per share) | (27) | (27) | ||||
Purchases of treasury stock, shares | (262) | |||||
Purchases of treasury stock | (45) | (45) | ||||
Compensation costs: | ||||||
Vested compensation awards, shares | 492 | |||||
Vested compensation awards | 0 | $ 0 | 0 | |||
Compensation costs included in net income | 17 | 17 | 0 | |||
Net income | 178 | 178 | 0 | |||
Ending Balance, shares at Mar. 31, 2018 | 170,419 | |||||
Ending Balance at Mar. 31, 2018 | $ 11,402 | $ 2 | $ 8,991 | $ (294) | $ 2,698 | $ 5 |
Consolidated Statement Of Equi6
Consolidated Statement Of Equity (Parenthetical) - $ / shares | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Statement of Stockholders' Equity [Abstract] | ||
Dividends declared per share (usd per share) | $ 0.16 | $ 0.04 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Cash flows from operating activities: | ||
Net income (loss) | $ 178 | $ (42) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depletion, depreciation and amortization | 357 | 337 |
Impairment of oil and gas properties | 0 | 285 |
Exploration expenses, including dry holes | 7 | 10 |
Deferred income taxes | 50 | (31) |
Gain on disposition of assets, net | (4) | (11) |
Accretion of discount on asset retirement obligations | 4 | 5 |
Interest expense | 1 | 1 |
Derivative related activity | 136 | (141) |
Amortization of stock-based compensation | 17 | 22 |
Other | 20 | 25 |
Change in operating assets and liabilities: | ||
Accounts receivable | (181) | 92 |
Inventories | (6) | (19) |
Investments | 4 | 4 |
Other current assets | (3) | (6) |
Accounts payable | (9) | (153) |
Interest payable | (21) | (29) |
Income taxes payable | 1 | 0 |
Other current liabilities | 3 | 15 |
Net cash provided by operating activities | 554 | 364 |
Cash flows from investing activities: | ||
Proceeds from disposition of assets | 4 | 78 |
Proceeds from investments | 555 | 458 |
Purchase of investments | (94) | (315) |
Additions to oil and gas properties | (818) | (433) |
Additions to other assets and other property and equipment, net | (51) | (86) |
Net cash used in investing activities | (404) | (298) |
Cash flows from financing activities: | ||
Principal payments on long-term debt | 0 | (485) |
Purchases of treasury stock | (45) | (36) |
Net cash used in financing activities | (45) | (521) |
Net increase (decrease) in cash and cash equivalents | 105 | (455) |
Cash and cash equivalents, beginning of period | 896 | 1,118 |
Cash and cash equivalents, end of period | $ 1,001 | $ 663 |
Organization And Nature Of Oper
Organization And Nature Of Operations | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization And Nature Of Operations | Organization and Nature of Operations Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company that explores for, develops and produces oil, natural gas liquids ("NGLs") and gas within the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeast Colorado and the West Panhandle field in the Texas Panhandle. |
Basis of Presentation
Basis of Presentation | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2018 and for the three months ended March 31, 2018 and 2017 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 . Certain reclassifications have been made to the 2017 financial statement and footnote amounts in order to conform to the 2018 presentation. Assets held for sale. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell. See Note 3 for additional information about the Company's divestitures. Adoption of New Accounting Standards. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09 ("ASC 606") "Revenue from Contracts with Customers," which supersedes the revenue recognition requirements in ASC 605 “Revenue Recognition” ("ASC 605"), and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method. See Note 11 for a discussion of the impact to the Company's recognition of revenue associated with the adoption of ASC 606. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. The Company adopted this standard on January 1, 2017. See Note 14 for a discussion of the impact to the Company's income tax provision associated with the adoption of ASU 2016-09. New accounting pronouncements. In February 2016, the FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company anticipates that the adoption of ASU 2016-02 for its leasing arrangements will likely (i) increase the Company's recorded assets and liabilities, (ii) increase depreciation, depletion and amortization expense, (iii) increase interest expense and (iv) decrease lease/rental expense. The Company is currently evaluating each of its lease arrangements and has not determined the aggregate amount of change expected for each category. |
Divestitures
Divestitures | 3 Months Ended |
Mar. 31, 2018 | |
Business Combinations [Abstract] | |
Divestitures | Divestitures In February 2018, the Company announced its intention to divest its properties in the South Texas, Raton and West Panhandle fields and focus its efforts and capital resources on its Permian Basin assets. No assurance can be given that the sales will be completed in accordance with the Company's plan or on terms and at prices acceptable to the Company. In March 2018, the Company entered into a purchase and sale agreement with an unaffiliated third party to sell approximately 10,200 net acres in the western portion of the Eagle Ford Shale ("West Eagle Ford Shale") for cash proceeds, before normal closing adjustments, of approximately $103 million , of which $22 million was received in March 2018. The Company classified the West Eagle Ford Shale assets and liabilities as held for sale in the accompanying consolidated balance sheet as of March 31, 2018 . These asset and liabilities were composed of the following as of March 31, 2018 (the Company had no assets held for sale as of December 31, 2017): March 31, 2018 (in millions) Composition of assets included in assets held for sale: Current assets $ 19 Goodwill 1 Total assets $ 20 Composition of liabilities included in liabilities held for sale: Other liabilities 6 Total liabilities $ 6 See Note 16 for additional information about the completion of the sale of the Company's West Eagle Ford Shale assets subsequent to March 31, 2018. During the three months ended March 31, 2017 , the Company completed the sales of nonstrategic proved and unproved properties in the Permian Basin for cash proceeds of $72 million , which resulted in a gain of $10 million . |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows: • Level 1 – quoted prices for identical assets or liabilities in active markets. • Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3 – unobservable inputs for the asset or liability. Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurement as of March 31, 2018 Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value as of March 31, 2018 (in millions) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Deferred compensation plan assets 92 — — 92 Total assets 92 7 — 99 Liabilities: Commodity derivatives — 387 — 387 Total liabilities — 387 — 387 Total recurring fair value measurements $ 92 $ (380 ) $ — $ (288 ) Fair Value Measurement as of December 31, 2017 Using Quoted Prices Significant Significant Fair value as of December 31, 2017 (in millions) Assets: Commodity derivatives $ — $ 11 $ — $ 11 Deferred compensation plan assets 95 — — 95 Total assets 95 11 — 106 Liabilities: Commodity derivatives — 255 — 255 Total liabilities — 255 — 255 Total recurring fair value measurements $ 95 $ (244 ) $ — $ (149 ) Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives. The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts and collar contracts with short puts, which is based on active and independent market-quoted volatility factors. Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of March 31, 2018 and December 31, 2017 , the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Proved oil and gas properties . As a result of the Company's proved property impairment assessments, the Company recognized a noncash impairment charge of $285 million to reduce the carrying value of the Raton field during the three months ended March 31, 2017 to its estimated fair value of $186 million . The Company calculated the fair value of the Raton field as of March 31, 2017 using a discounted future cash flow model. Significant Level 3 assumptions associated with the calculation of the Raton field's discounted future cash flows as of March 31, 2017 included management's longer-term commodity price outlook ("Management's Price Outlook") for oil of $53.65 per barrel ("Bbl") and gas of $3.00 per million British thermal units ("MMBtu") and management's outlook for (i) production, (ii) capital expenditures, (iii) production costs and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. It is reasonably possible that the Company's estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future adjustments, both positive and negative, to proved and risk-adjusted probable and possible oil and gas reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these reserves. Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of March 31, 2018 and December 31, 2017 are as follows: March 31, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 815 $ 817 $ 1,279 $ 1,277 Current portion of long-term debt $ 449 $ 451 $ 449 $ 457 Long-term debt $ 2,284 $ 2,423 $ 2,283 $ 2,479 Commercial paper, corporate bonds and time deposits. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. The investments are carried at amortized cost and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The carrying values of held-to-maturity investments are adjusted for amortization of premiums and accretion of discounts over the remaining life of the investment. Income related to these investments is recorded in interest and other income in the Company's consolidated statements of operations. The Company's investments in corporate bonds represent Level 1 inputs in the hierarchy, while other investments represent Level 2 inputs in the hierarchy. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. The following tables provide the components of the Company's cash and cash equivalents and investments as of March 31, 2018 and December 31, 2017 : March 31, 2018 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Deposits Total (in millions) Cash and cash equivalents $ 931 $ 20 $ — $ 50 $ 1,001 Short-term investments — 125 398 199 722 Long-term investments — — 93 — 93 $ 931 $ 145 $ 491 $ 249 $ 1,816 December 31, 2017 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 846 $ — $ — $ 50 $ 896 Short-term investments — 124 642 447 1,213 Long-term investments — — 66 — 66 $ 846 $ 124 $ 708 $ 497 $ 2,175 Debt obligations. The Company's debt obligations are composed of its senior notes whose fair value is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy. The Company's senior notes represent debt securities that are quoted but not actively traded on major exchanges; therefore, fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges. The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations. |
Derivative Financial Instrument
Derivative Financial Instruments | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | Derivative Financial Instruments The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness. Periodically, the Company may pay a premium to enter into commodity contracts. Premiums paid, if any, have been nominal in relation to the value of the underlying asset in the contract. The Company recognizes the nominal premium payments as an increase to the value of derivative assets when paid. All derivatives are adjusted to fair value as of each balance sheet date. Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and the actual index prices at which the oil is sold. The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of March 31, 2018 and the weighted average oil prices for those contracts: 2018 Year Ending December 31, 2019 Second Quarter Third Quarter Fourth Quarter Collar contracts: Volume (Bbl) 3,000 3,000 3,000 — Price per Bbl: Ceiling $ 58.05 $ 58.05 $ 58.05 $ — Floor $ 45.00 $ 45.00 $ 45.00 $ — Collar contracts with short puts: Volume (Bbl) 149,000 154,000 159,000 65,000 Price per Bbl: Ceiling $ 57.79 $ 57.70 $ 57.62 $ 60.74 Floor $ 47.42 $ 47.34 $ 47.26 $ 52.69 Short put $ 37.38 $ 37.31 $ 37.23 $ 42.69 NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu, Texas or Conway, Kansas NGL component product prices. The Company uses derivative contracts to manage NGL component price volatility. The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of March 31, 2018 and the weighted average NGL prices for those contracts: 2018 Year Ending December 31, 2019 Second Quarter Third Quarter Fourth Quarter Ethane basis swap contracts (a): Volume (MMBtu) 6,920 6,920 6,920 6,920 Price differential ($/MMBtu) $ 1.60 $ 1.60 $ 1.60 $ 1.60 ____________________ (a) The ethane basis swap contracts reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The ethane basis swap contracts fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane. Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to HH gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold. The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of March 31, 2018 and the weighted average gas prices for those contracts: 2018 Year Ending December 31, 2019 Second Quarter Third Quarter Fourth Quarter Swap contracts: Volume (MMBtu) 100,000 100,000 100,000 — Price per MMBtu $ 3.00 $ 3.00 $ 3.00 $ — Collar contracts with short puts: Volume (MMBtu) 50,000 50,000 50,000 — Price per MMBtu: Ceiling $ 3.40 $ 3.40 $ 3.40 $ — Floor $ 2.75 $ 2.75 $ 2.75 $ — Short put $ 2.25 $ 2.25 $ 2.25 $ — Basis swap contracts (a): Southern California index swap volume (MMBtu) (b) 40,000 80,000 66,522 84,932 Price differential ($/MMBtu) $ 0.30 $ 0.30 $ 0.50 $ 0.33 ____________________ (a) Subsequent to March 31, 2018 , the Company entered into additional basis swap contracts that fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the HH index price used in swap contracts and collar contracts with short puts for (i) 20,000 MMBtu per day of July 2018 through September 2019 production with a price differential of $1.54 per MMBtu and (ii) 30,000 MMBtu per day of January through September 2019 production with a price differential of $1.47 per MMBtu. (b) The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California. Marketing derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swap contracts to mitigate price risk. The following table sets forth the volumes per day associated with the Company's outstanding marketing derivative contracts as of March 31, 2018 and the weighted average prices for those contracts: 2018 Second Quarter Third Quarter Average Daily Oil Transportation Commitments Associated with Derivatives (Bbl): Basis swap contracts: Louisiana Light Sweet index swap volume (a) (b) 10,000 6,739 Price differential ($/Bbl) $ 3.18 $ 3.18 Magellan East Houston index swap volume (a) 8,659 2,022 Price differential ($/Bbl) $ 3.29 $ 3.30 ____________________ (a) The referenced basis swap contracts fix the basis differentials between NYMEX WTI and Louisiana Light Sweet or Magellan East Houston oil prices for Permian Basin oil forecasted for sale in the Gulf Coast region. (b) Subsequent to March 31, 2018 , the Company liquidated its Louisiana Light Sweet basis swap contracts for 10,000 Bbl per day of June 2018 through August 2018 transportation commitments for a nominal gain. Tabular disclosure of derivative financial instruments . All of the Company's derivatives are accounted for as non-hedge derivatives as of March 31, 2018 and December 31, 2017 , and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following: Fair Value of Derivative Instruments as of March 31, 2018 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 14 $ (7 ) $ 7 Commodity price derivatives Derivatives - noncurrent $ 8 $ (8 ) — $ 7 Liability Derivatives: Commodity price derivatives Derivatives - current $ 340 $ (7 ) $ 333 Commodity price derivatives Derivatives - noncurrent $ 62 $ (8 ) 54 $ 387 Fair Value of Derivative Instruments as of December 31, 2017 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 13 $ (2 ) $ 11 Commodity price derivatives Derivatives - noncurrent $ 3 $ (3 ) — $ 11 Liability Derivatives: Commodity price derivatives Derivatives - current $ 234 $ (2 ) $ 232 Commodity price derivatives Derivatives - noncurrent $ 26 $ (3 ) 23 $ 255 The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recognized in Earnings on Derivatives Three Months Ended 2018 2017 (in millions) Commodity price derivatives Derivative gains (losses), net $ (208 ) $ 151 Derivative Counterparties . The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures. |
Exploratory Costs
Exploratory Costs | 3 Months Ended |
Mar. 31, 2018 | |
Extractive Industries [Abstract] | |
Exploratory Costs | Exploratory Costs The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense. The following table reflects the Company's capitalized exploratory well and project activity during the three months ended March 31, 2018 : Three Months Ended March 31, 2018 (in millions) Beginning capitalized exploratory well costs $ 505 Additions to exploratory well costs pending the determination of proved reserves 582 Reclassification due to determination of proved reserves (607 ) Exploratory well costs charged to exploration and abandonment expense (4 ) Ending capitalized exploratory well costs $ 476 The following table provides an aging as of March 31, 2018 and December 31, 2017 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed: March 31, 2018 December 31, 2017 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 464 $ 493 More than one year 12 12 $ 476 $ 505 Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year 7 7 The projects with exploratory well costs that have been suspended for a period greater than one year as of March 31, 2018 are in the Eagle Ford Shale area. The Company is evaluating both the well performance of similar wells completed in 2017 and whether to drill additional wells near these wells in order for all of the wells in the area to be fracture stimulated as a package, thereby improving the resource recovery for the area. The Company expects to complete its evaluation of these seven wells during 2018. |
Long-term Debt
Long-term Debt | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-term Debt | Long-term Debt Credit facility. The Company's long-term debt consists of senior notes, a revolving corporate credit facility (the "Credit Facility") and the effects of issuance costs and discounts. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in August 2020. As of March 31, 2018 , the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants. Senior notes. The Company's 6.65% senior notes (the " 6.65% Senior Notes") matured and were repaid in March 2017. The Company funded the $485 million repayment of the 6.65% Senior Notes with cash on hand. The Company's 6.875% senior notes (the " 6.875% Senior Notes"), with an outstanding debt principal balance of $450 million , mature in May 2018 and are classified as current in the accompanying consolidated balance sheets as of March 31, 2018 and December 31, 2017 . See Note 16 for additional information regarding the repayment of the Company's 6.875% Senior Notes in May 2018. |
Incentive Plans
Incentive Plans | 3 Months Ended |
Mar. 31, 2018 | |
Compensation Related Costs [Abstract] | |
Incentive Plans | Incentive Plans Stock-based compensation. For the three months ended March 31, 2018 , the Company recorded $23 million of stock-based compensation expense for all plans, as compared to $30 million for the same period in 2017 . As of March 31, 2018 , there was $163 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $35 million attributable to stock-based awards that are expected to be settled on their vesting date in cash, rather than in equity shares ("Liability Awards"). The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of March 31, 2018 and December 31, 2017 , accounts payable – due to affiliates included $4 million and $20 million , respectively, of liabilities attributable to Liability Awards. The following table summarizes the activity that occurred during the three months ended March 31, 2018 for restricted stock awards and performance units issued by Pioneer: Restricted Stock Equity Awards Restricted Stock Liability Awards Performance Units Outstanding as of December 31, 2017 916,223 252,735 163,158 Awards granted 369,170 108,129 62,541 Awards forfeited (11,986 ) (2,652 ) (1,285 ) Awards vested (395,682 ) (121,776 ) — Outstanding as of March 31, 2018 877,725 236,436 224,414 As of March 31, 2018 and December 31, 2017 , the Company also had 138,493 stock options outstanding and exercisable. There were no stock options exercised during the three months ended March 31, 2018 . |
Asset Retirement Obligations
Asset Retirement Obligations | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company's asset retirement obligation activity during the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Beginning asset retirement obligations $ 271 $ 297 New wells placed on production 1 1 Changes in estimates 2 — Obligations reclassified to liabilities held for sale (6 ) — Liabilities settled (9 ) (6 ) Accretion of discount 4 5 Ending asset retirement obligations $ 263 $ 297 The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of March 31, 2018 and December 31, 2017 , the current portion of the Company's asset retirement obligations was $40 million and $41 million , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Legal actions. The Company is a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company does not believe these obligations are probable of having a material impact on its liquidity, financial position or future results of operations. Lease agreements. In June 2017, the Company entered into a 20 -year operating lease for the Company's new corporate headquarters that is currently being constructed in Irving, Texas. Annual base rent is expected to be $33 million and lease payments are expected to commence once the building is complete, which is anticipated to occur during the second half of 2019. The Company has a variable equity interest in the entity that is constructing the building. The Company is not the primary beneficiary of the variable interest entity and only has a profit sharing interest after certain economic returns are achieved. The Company has no exposure to the variable interest entity's losses or future liabilities, if any. The Company is the deemed owner of the building (for accounting purposes) during the construction period and is following the build-to-suit accounting guidance. Accordingly, as of March 31, 2018 , the Company has capitalized $79 million of construction costs, including capitalized interest, within other property and equipment and has recognized a corresponding build-to-suit lease liability. The recording of these assets and liabilities are considered noncash investing and financing items, respectively, for purposes of the consolidated statements of cash flows. Firm purchase, gathering, processing, transportation, and fractionation commitments. The Company from time to time enters into, and as of March 31, 2018 was a party to, take-or-pay agreements, which include contractual commitments to purchase sand and water for use in the Company's drilling operations and contractual commitments with midstream service companies and pipeline carriers for future gathering, processing, transportation, storage and fractionation. These commitments are normal and customary for the Company's business activities. |
Revenue Recognition
Revenue Recognition | 3 Months Ended |
Mar. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | Revenue Recognition Impact of ASC 606 adoption. On January 1, 2018, the Company adopted ASC 606 by applying the modified retrospective method to all revenue contracts as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting under ASC 605. The Company completed a detailed review of its revenue contracts, which represent all of the Company's revenue streams including oil, NGL and gas sales and sales of purchased oil and gas, to determine the effect of the new standard for the three months ended March 31, 2018. The Company did not record a change to its opening retained earnings as of January 1, 2018 as there was no material change to the timing or pattern of revenue recognition due to the adoption of ASC 606. The adoption of ASC 606 as of January 1, 2018 had the following impact on the Company's results of operations for the three months ended March 31, 2018: Three Months Ended March 31, 2018 As Reported ASC 605 (Without Adoption of ASC 606) Effect of Change Higher (Lower) (in millions) Revenues and other income: Oil and gas $ 1,266 $ 1,223 $ 43 Costs and expenses: Oil and gas production $ 213 $ 170 $ 43 Changes in oil and gas revenues and oil and gas production costs (specifically gathering, processing and transportation costs) are due to the conclusion under the control model in ASC 606 that the third-party processor or transporter is only providing gas processing or transportation services and that the Company remains the principal owner of the commodity until sold to the ultimate purchaser. This is a change from ASC 605 where the Company historically recorded gas processing fees as a reduction of revenue recognized by the Company, as these fees were considered necessary to separate the wet gas stream into its sellable components (i.e. dry gas and individual NGL components). Under ASC 605, third-party processing and transportation companies were determined to have control of the commodities being processed and transported. As a result of adopting ASC 606, the Company has modified its presentation of revenues and expenses for these arrangements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party purchasers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the purchaser, are now presented as oil and gas production costs. Disaggregated revenue from contracts with purchasers. Revenues on sales of oil, NGLs, gas and purchased oil and gas are recognized when control of the product is transferred to the purchaser and payment can be reasonably assured. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, distance from the well to the pipeline or market, commodity quality and prevailing supply and demand conditions. As such, the prices of oil, NGLs and gas generally fluctuate based on the relevant market index rates. The following table provides information about disaggregated revenue from contracts with purchasers by product type: Three Months Ended March 31, 2018 (in millions) Oil sales $ 1,013 NGL sales 165 Gas sales 88 Total oil and gas sales 1,266 Sales of purchased oil and gas 1,070 Total revenue derived from contracts with purchasers $ 2,336 Oil sales . Sales under the Company's oil contracts are generally considered performed when the Company sells oil production at the wellhead and receives an agreed-upon index price, net of any price differentials. The Company recognizes revenue when control transfers to the purchaser at the wellhead based on the net price received. NGL and gas sales . Sales under the Company's gas processing contracts are recognized when the Company delivers gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity's system. The midstream processing entity gathers and processes the gas and remits proceeds to the Company for the resulting sales of NGLs and gas. In many cases, the Company elects to take its NGLs and residue gas in-kind at the tailgate of the midstream entity's processing plant and subsequently market the products itself. When the Company elects to take-in-kind, it delivers NGLs and gas to a third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. The Company evaluated whether it was the principal or the agent in the natural gas processing transactions and concluded that it is the principal when it has the ability to take-in-kind, which is the case in the majority of the Company's gas processing and transportation contracts. Therefore, beginning January 1, 2018, the Company began recognizing revenue on a gross basis, with the gathering, processing and transportation costs associated with its take-in-kind arrangements being recognized as oil and gas production costs in the Company's accompanying consolidated statement of operations. Sales of purchased oil and gas . The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to the Gulf Coast refinery or international export markets and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The transportation costs associated with these transactions are presented as a component of purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. Performance obligations and contract balances. The majority of the Company's product sale commitments are short-term in nature with a contract term of one year or less. The Company typically satisfies its performance obligations upon transfer of control as described above in Disaggregated revenue from contracts with purchasers and records the related revenue in the month production is delivered to the purchaser. Settlement statements for sales of oil, NGLs and gas and sales of purchased oil and gas may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The implementation of ASC 606 has not changed existing controls around revenue estimates and the accrual process. Historically, differences between the Company's revenue estimates and actual revenue received have not been significant. As of March 31, 2018, the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $793 million . |
Interest and Other Income
Interest and Other Income | 3 Months Ended |
Mar. 31, 2018 | |
Interest and Other Income [Abstract] | |
Interest and Other Income | Interest and Other Income The following table provides the components of the Company's interest and other income for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Interest income $ 7 $ 6 Deferred compensation plan income 4 2 Seismic data sales 3 — Severance and sales tax refunds 2 3 Other income 2 2 Total interest and other income $ 18 $ 13 |
Other Expense
Other Expense | 3 Months Ended |
Mar. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Other Expense | Other Expense The following table provides the components of the Company's other expense for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Transportation commitment charges (a) $ 34 $ 40 Loss from vertical integration services (b) 6 5 Other 17 15 Total other expense $ 57 $ 60 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three months ended March 31, 2018 , these vertical integration net margins included $34 million of revenues and $40 million of costs and expenses. For the same period in 2017, these vertical integration net margins included $19 million of revenues and $24 million of costs and expenses. |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Company's income tax benefit (provision) consisted of the following for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Deferred tax benefit (provision) $ (50 ) $ 31 For the three months ended March 31, 2018 , the Company's effective tax rate, excluding income attributable to noncontrolling interests, was 22 percent , as compared to an effective rate of 42 percent for the same period in 2017 . The U.S. statutory rate for the three months ended March 31, 2018 was 21 percent , reflecting the reduction in the federal corporate income tax rate from 35 percent to 21 percent beginning in 2018 as a result of the Tax Cuts and Jobs Act that was enacted in December 2017. The Company's effective tax rate for the three months ended March 31, 2017 differs from the U.S. statutory rate in effect during 2017 of 35 percent primarily due to recognizing excess tax benefits of $8 million associated with the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which requires excess tax benefits or deficiencies associated with the vesting of long-term incentive awards to be recorded as income tax expense or benefit in the statement of operations rather than as an adjustment to additional paid-in capital in the balance sheet. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. As of March 31, 2018 and December 31, 2017 , the Company had cumulative unrecognized tax benefits of $127 million and $124 million , respectively, resulting from research and experimental expenditures related to horizontal drilling and completions innovations. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. The Company expects to substantially resolve the uncertainties associated with the unrecognized tax benefit by December 2018 . The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2012 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2012. As of March 31, 2018 , no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position. |
Net Income (Loss) Per Share
Net Income (Loss) Per Share | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Net Income (Loss) Per Share | Net Income (Loss) Per Share The following table reconciles the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Net income (loss) attributable to common stockholders $ 178 $ (42 ) Participating share-based earnings (1 ) — Basic and diluted net income (loss) attributable to common stockholders $ 177 $ (42 ) The following table is a reconciliation of basic weighted average shares outstanding to diluted weighted average shares outstanding for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Basic weighted average shares outstanding 170 170 Dilution attributable to stock-based compensation awards 1 — Diluted weighted average shares outstanding 171 170 Stock repurchase program . In February 2018, the Company's board of directors (the "Board") approved a $100 million common stock repurchase program to offset the impact of dilution associated with annual employee stock awards, of which $83 million remained available for use to purchase shares as of March 31, 2018 . During the three months ended March 31, 2018 , the Company purchased $17 million of common stock pursuant to the program. |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events Divestitures. In April 2018, the sale of the West Eagle Ford Shale assets was completed, and during April 2018 the Company received the remaining cash proceeds of $81 million . Associated with the sale of the West Eagle Ford Shale assets, the Company expects to recognize a gain on unproved properties sold of $75 million to $85 million (after normal closing adjustments) during the second quarter of 2018. See Note 3 for additional information about the Company's sale of its West Eagle Ford Shale assets. Senior notes. The Company's outstanding 6.875% Senior Notes matured on May 1, 2018. The Company funded the payment of the $450 million principal balance with cash on hand. See Note 7 for additional information regarding the Company's 6.875% Senior Notes. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Presentation | Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2018 and for the three months ended March 31, 2018 and 2017 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 . Certain reclassifications have been made to the 2017 financial statement and footnote amounts in order to conform to the 2018 presentation. |
New accounting pronouncements | New accounting pronouncements. In February 2016, the FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company anticipates that the adoption of ASU 2016-02 for its leasing arrangements will likely (i) increase the Company's recorded assets and liabilities, (ii) increase depreciation, depletion and amortization expense, (iii) increase interest expense and (iv) decrease lease/rental expense. The Company is currently evaluating each of its lease arrangements and has not determined the aggregate amount of change expected for each category. |
Divestitures (Tables)
Divestitures (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Business Combinations [Abstract] | |
Assets and Liabilities Held for Sale | These asset and liabilities were composed of the following as of March 31, 2018 (the Company had no assets held for sale as of December 31, 2017): March 31, 2018 (in millions) Composition of assets included in assets held for sale: Current assets $ 19 Goodwill 1 Total assets $ 20 Composition of liabilities included in liabilities held for sale: Other liabilities 6 Total liabilities $ 6 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of assets and liabilities measured at fair value on a recurring basis | The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurement as of March 31, 2018 Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value as of March 31, 2018 (in millions) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Deferred compensation plan assets 92 — — 92 Total assets 92 7 — 99 Liabilities: Commodity derivatives — 387 — 387 Total liabilities — 387 — 387 Total recurring fair value measurements $ 92 $ (380 ) $ — $ (288 ) Fair Value Measurement as of December 31, 2017 Using Quoted Prices Significant Significant Fair value as of December 31, 2017 (in millions) Assets: Commodity derivatives $ — $ 11 $ — $ 11 Deferred compensation plan assets 95 — — 95 Total assets 95 11 — 106 Liabilities: Commodity derivatives — 255 — 255 Total liabilities — 255 — 255 Total recurring fair value measurements $ 95 $ (244 ) $ — $ (149 ) |
Schedule of carrying values and financial instruments not carried at fair value | Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of March 31, 2018 and December 31, 2017 are as follows: March 31, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 815 $ 817 $ 1,279 $ 1,277 Current portion of long-term debt $ 449 $ 451 $ 449 $ 457 Long-term debt $ 2,284 $ 2,423 $ 2,283 $ 2,479 |
Cash and cash equivalents and investments | The following tables provide the components of the Company's cash and cash equivalents and investments as of March 31, 2018 and December 31, 2017 : March 31, 2018 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Deposits Total (in millions) Cash and cash equivalents $ 931 $ 20 $ — $ 50 $ 1,001 Short-term investments — 125 398 199 722 Long-term investments — — 93 — 93 $ 931 $ 145 $ 491 $ 249 $ 1,816 December 31, 2017 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 846 $ — $ — $ 50 $ 896 Short-term investments — 124 642 447 1,213 Long-term investments — — 66 — 66 $ 846 $ 124 $ 708 $ 497 $ 2,175 |
Derivative Financial Instrume27
Derivative Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of oil derivative contracts volume and weighted average price | The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of March 31, 2018 and the weighted average oil prices for those contracts: 2018 Year Ending December 31, 2019 Second Quarter Third Quarter Fourth Quarter Collar contracts: Volume (Bbl) 3,000 3,000 3,000 — Price per Bbl: Ceiling $ 58.05 $ 58.05 $ 58.05 $ — Floor $ 45.00 $ 45.00 $ 45.00 $ — Collar contracts with short puts: Volume (Bbl) 149,000 154,000 159,000 65,000 Price per Bbl: Ceiling $ 57.79 $ 57.70 $ 57.62 $ 60.74 Floor $ 47.42 $ 47.34 $ 47.26 $ 52.69 Short put $ 37.38 $ 37.31 $ 37.23 $ 42.69 |
Schedule of NGL derivative volumes and weighted average prices | The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of March 31, 2018 and the weighted average NGL prices for those contracts: 2018 Year Ending December 31, 2019 Second Quarter Third Quarter Fourth Quarter Ethane basis swap contracts (a): Volume (MMBtu) 6,920 6,920 6,920 6,920 Price differential ($/MMBtu) $ 1.60 $ 1.60 $ 1.60 $ 1.60 ____________________ (a) The ethane basis swap contracts reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The ethane basis swap contracts fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane. |
Schedule of gas derivative volume and weighted average prices | The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of March 31, 2018 and the weighted average gas prices for those contracts: 2018 Year Ending December 31, 2019 Second Quarter Third Quarter Fourth Quarter Swap contracts: Volume (MMBtu) 100,000 100,000 100,000 — Price per MMBtu $ 3.00 $ 3.00 $ 3.00 $ — Collar contracts with short puts: Volume (MMBtu) 50,000 50,000 50,000 — Price per MMBtu: Ceiling $ 3.40 $ 3.40 $ 3.40 $ — Floor $ 2.75 $ 2.75 $ 2.75 $ — Short put $ 2.25 $ 2.25 $ 2.25 $ — Basis swap contracts (a): Southern California index swap volume (MMBtu) (b) 40,000 80,000 66,522 84,932 Price differential ($/MMBtu) $ 0.30 $ 0.30 $ 0.50 $ 0.33 ____________________ (a) Subsequent to March 31, 2018 , the Company entered into additional basis swap contracts that fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the HH index price used in swap contracts and collar contracts with short puts for (i) 20,000 MMBtu per day of July 2018 through September 2019 production with a price differential of $1.54 per MMBtu and (ii) 30,000 MMBtu per day of January through September 2019 production with a price differential of $1.47 per MMBtu. (b) The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California. |
Schedule of Marketing Derivative Contracts Volume and Price | The following table sets forth the volumes per day associated with the Company's outstanding marketing derivative contracts as of March 31, 2018 and the weighted average prices for those contracts: 2018 Second Quarter Third Quarter Average Daily Oil Transportation Commitments Associated with Derivatives (Bbl): Basis swap contracts: Louisiana Light Sweet index swap volume (a) (b) 10,000 6,739 Price differential ($/Bbl) $ 3.18 $ 3.18 Magellan East Houston index swap volume (a) 8,659 2,022 Price differential ($/Bbl) $ 3.29 $ 3.30 |
Offsetting asset and liability | The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following: Fair Value of Derivative Instruments as of March 31, 2018 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 14 $ (7 ) $ 7 Commodity price derivatives Derivatives - noncurrent $ 8 $ (8 ) — $ 7 Liability Derivatives: Commodity price derivatives Derivatives - current $ 340 $ (7 ) $ 333 Commodity price derivatives Derivatives - noncurrent $ 62 $ (8 ) 54 $ 387 Fair Value of Derivative Instruments as of December 31, 2017 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 13 $ (2 ) $ 11 Commodity price derivatives Derivatives - noncurrent $ 3 $ (3 ) — $ 11 Liability Derivatives: Commodity price derivatives Derivatives - current $ 234 $ (2 ) $ 232 Commodity price derivatives Derivatives - noncurrent $ 26 $ (3 ) 23 $ 255 |
Schedule of derivative gains and losses recognized on statement of operations | The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recognized in Earnings on Derivatives Three Months Ended 2018 2017 (in millions) Commodity price derivatives Derivative gains (losses), net $ (208 ) $ 151 |
Exploratory Costs (Tables)
Exploratory Costs (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Extractive Industries [Abstract] | |
Capitalized exploratory well and project activity | The following table reflects the Company's capitalized exploratory well and project activity during the three months ended March 31, 2018 : Three Months Ended March 31, 2018 (in millions) Beginning capitalized exploratory well costs $ 505 Additions to exploratory well costs pending the determination of proved reserves 582 Reclassification due to determination of proved reserves (607 ) Exploratory well costs charged to exploration and abandonment expense (4 ) Ending capitalized exploratory well costs $ 476 |
Capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized | The following table provides an aging as of March 31, 2018 and December 31, 2017 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed: March 31, 2018 December 31, 2017 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 464 $ 493 More than one year 12 12 $ 476 $ 505 Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year 7 7 |
Incentive Plans (Tables)
Incentive Plans (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Compensation Related Costs [Abstract] | |
Schedule of share based incentive award activity | The following table summarizes the activity that occurred during the three months ended March 31, 2018 for restricted stock awards and performance units issued by Pioneer: Restricted Stock Equity Awards Restricted Stock Liability Awards Performance Units Outstanding as of December 31, 2017 916,223 252,735 163,158 Awards granted 369,170 108,129 62,541 Awards forfeited (11,986 ) (2,652 ) (1,285 ) Awards vested (395,682 ) (121,776 ) — Outstanding as of March 31, 2018 877,725 236,436 224,414 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation [Abstract] | |
Schedule of asset retirement obligations | The following table summarizes the Company's asset retirement obligation activity during the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Beginning asset retirement obligations $ 271 $ 297 New wells placed on production 1 1 Changes in estimates 2 — Obligations reclassified to liabilities held for sale (6 ) — Liabilities settled (9 ) (6 ) Accretion of discount 4 5 Ending asset retirement obligations $ 263 $ 297 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Adoption of ASC 606 | The adoption of ASC 606 as of January 1, 2018 had the following impact on the Company's results of operations for the three months ended March 31, 2018: Three Months Ended March 31, 2018 As Reported ASC 605 (Without Adoption of ASC 606) Effect of Change Higher (Lower) (in millions) Revenues and other income: Oil and gas $ 1,266 $ 1,223 $ 43 Costs and expenses: Oil and gas production $ 213 $ 170 $ 43 |
Disaggregation of Revenue | The following table provides information about disaggregated revenue from contracts with purchasers by product type: Three Months Ended March 31, 2018 (in millions) Oil sales $ 1,013 NGL sales 165 Gas sales 88 Total oil and gas sales 1,266 Sales of purchased oil and gas 1,070 Total revenue derived from contracts with purchasers $ 2,336 |
Interest and Other Income (Tabl
Interest and Other Income (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Interest and Other Income [Abstract] | |
Components of interest and other income | The following table provides the components of the Company's interest and other income for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Interest income $ 7 $ 6 Deferred compensation plan income 4 2 Seismic data sales 3 — Severance and sales tax refunds 2 3 Other income 2 2 Total interest and other income $ 18 $ 13 |
Other Expense (Tables)
Other Expense (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Schedule of components of other expense | The following table provides the components of the Company's other expense for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Transportation commitment charges (a) $ 34 $ 40 Loss from vertical integration services (b) 6 5 Other 17 15 Total other expense $ 57 $ 60 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three months ended March 31, 2018 , these vertical integration net margins included $34 million of revenues and $40 million of costs and expenses. For the same period in 2017, these vertical integration net margins included $19 million of revenues and $24 million of costs and expenses. |
Income Taxes (Tables)
Income Taxes (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income tax (provisions) benefits attributable to income from continuing operations | The Company's income tax benefit (provision) consisted of the following for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Deferred tax benefit (provision) $ (50 ) $ 31 |
Net Income (Loss) Per Share (Ta
Net Income (Loss) Per Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Reconciliation of earnings attributable to common stockholders, basic and diluted | The following table reconciles the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three months ended March 31, 2018 and 2017 : Three Months Ended 2018 2017 (in millions) Net income (loss) attributable to common stockholders $ 178 $ (42 ) Participating share-based earnings (1 ) — Basic and diluted net income (loss) attributable to common stockholders $ 177 $ (42 ) |
Schedule of Weighted Average Number of Shares [Table Text Block] | Three Months Ended 2018 2017 (in millions) Basic weighted average shares outstanding 170 170 Dilution attributable to stock-based compensation awards 1 — Diluted weighted average shares outstanding 171 170 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Divestitures) (Details) $ in Millions | 1 Months Ended | 3 Months Ended | |
Mar. 31, 2018USD ($)a | Mar. 31, 2018USD ($)a | Mar. 31, 2017USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Cash proceeds | $ 4 | $ 78 | |
Gain on disposition of assets, net | $ 4 | $ 11 | |
West Eagle Ford Shale | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Net acres | a | 10,200 | 10,200 | |
Cash proceeds, before normal closing adjustments | $ 103 | $ 103 | |
Cash proceeds | $ 22 | ||
Permian Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Cash proceeds | 72 | ||
Gain on disposition of assets, net | $ 10 |
Acquisitions and Divestitures37
Acquisitions and Divestitures (Assets and Liabilities Held for Sale) (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Composition of assets included in assets held for sale: | ||
Total assets | $ 20 | $ 0 |
Composition of liabilities included in liabilities held for sale: | ||
Total liabilities | 6 | $ 0 |
West Eagle Ford Shale | ||
Composition of assets included in assets held for sale: | ||
Current assets | 19 | |
Goodwill | 1 | |
Total assets | 20 | |
Composition of liabilities included in liabilities held for sale: | ||
Other liabilities | 6 | |
Total liabilities | $ 6 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Assets: | ||
Deferred compensation plan assets | $ 92 | $ 95 |
Total assets | 99 | 106 |
Liabilities: | ||
Total liabilities | 387 | 255 |
Total recurring fair value measurements | (288) | (149) |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets: | ||
Deferred compensation plan assets | 92 | 95 |
Total assets | 92 | 95 |
Liabilities: | ||
Total liabilities | 0 | 0 |
Total recurring fair value measurements | 92 | 95 |
Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Deferred compensation plan assets | 0 | 0 |
Total assets | 7 | 11 |
Liabilities: | ||
Total liabilities | 387 | 255 |
Total recurring fair value measurements | (380) | (244) |
Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Deferred compensation plan assets | 0 | 0 |
Total assets | 0 | 0 |
Liabilities: | ||
Total liabilities | 0 | 0 |
Total recurring fair value measurements | 0 | 0 |
Commodity derivatives | ||
Assets: | ||
Derivative assets | 7 | 11 |
Liabilities: | ||
Commodity derivatives | 387 | 255 |
Commodity derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets: | ||
Derivative assets | 0 | 0 |
Liabilities: | ||
Commodity derivatives | 0 | 0 |
Commodity derivatives | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Derivative assets | 7 | 11 |
Liabilities: | ||
Commodity derivatives | 387 | 255 |
Commodity derivatives | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Derivative assets | 0 | 0 |
Liabilities: | ||
Commodity derivatives | $ 0 | $ 0 |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) $ in Millions | 1 Months Ended | 3 Months Ended | |
Mar. 31, 2017USD ($)$ / MMBTU$ / bbl | Mar. 31, 2018USD ($) | Mar. 31, 2017USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment of oil and gas properties | $ 0 | $ (285) | |
Raton | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment of oil and gas properties | $ (285) | ||
Estimated fair value | $ 186 | $ 186 | |
Management oil price outlook per barrel | $ / bbl | 53.65 | ||
Management gas price outlook per millions of BTU | $ / MMBTU | 3 | ||
Discount rate | 10.00% |
Fair Value Measurements (Sche40
Fair Value Measurements (Schedule Of Carrying Values And Financial Instruments Not Carried At Fair Value) (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Current portion of long-term debt | $ 449 | $ 449 |
Long-term debt | 2,284 | 2,283 |
Carrying Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commercial paper, corporate bonds and time deposits | 815 | 1,279 |
Current portion of long-term debt | 449 | 449 |
Long-term debt | 2,284 | 2,283 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commercial paper, corporate bonds and time deposits | 817 | 1,277 |
Current portion of long-term debt | 451 | 457 |
Long-term debt | $ 2,423 | $ 2,479 |
Fair Value Measurements (Sche41
Fair Value Measurements (Schedule of Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | $ 1,001 | $ 896 | $ 663 | $ 1,118 |
Short-term investments | 722 | 1,213 | ||
Long-term investments | 93 | 66 | ||
Total cash and cash equivalents and investments | 1,816 | 2,175 | ||
Cash | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 931 | 846 | ||
Short-term investments | 0 | 0 | ||
Long-term investments | 0 | 0 | ||
Total cash and cash equivalents and investments | 931 | 846 | ||
Commercial Paper | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 20 | 0 | ||
Short-term investments | 125 | 124 | ||
Long-term investments | 0 | 0 | ||
Total cash and cash equivalents and investments | 145 | 124 | ||
Corporate Bonds | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 0 | 0 | ||
Short-term investments | 398 | 642 | ||
Long-term investments | 93 | 66 | ||
Total cash and cash equivalents and investments | 491 | 708 | ||
Time Deposits | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 50 | 50 | ||
Short-term investments | 199 | 447 | ||
Long-term investments | 0 | 0 | ||
Total cash and cash equivalents and investments | $ 249 | $ 497 |
Derivative Financial Instrume42
Derivative Financial Instruments (Schedule Of Oil Derivative Contracts Volume And Weighted Average Prices) (Details) | Mar. 31, 2018bbl / d$ / bbl |
Oil contracts | Collar contract for Q2 | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 3,000 |
Oil contracts | Collar contract for Q3 | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 3,000 |
Oil contracts | Collar contract for Q4 | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 3,000 |
Oil contracts | Collar Contracts for next year | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 0 |
Oil contracts | Collar contracts with short puts for Q2 | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 149,000 |
Oil contracts | Collar contracts with short puts for Q3 | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 154,000 |
Oil contracts | Collar contracts with short puts for Q4 | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 159,000 |
Oil contracts | Collar contracts with short puts for next year | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 65,000 |
Oil contracts, price per bbl | Collar contract for Q2 | |
Derivative [Line Items] | |
Ceiling, price per barrel | 58.05 |
Floor, price per barrel | 45 |
Oil contracts, price per bbl | Collar contract for Q3 | |
Derivative [Line Items] | |
Ceiling, price per barrel | 58.05 |
Floor, price per barrel | 45 |
Oil contracts, price per bbl | Collar contract for Q4 | |
Derivative [Line Items] | |
Ceiling, price per barrel | 58.05 |
Floor, price per barrel | 45 |
Oil contracts, price per bbl | Collar Contracts for next year | |
Derivative [Line Items] | |
Ceiling, price per barrel | 0 |
Floor, price per barrel | 0 |
Oil contracts, price per bbl | Collar contracts with short puts for Q2 | |
Derivative [Line Items] | |
Ceiling, price per barrel | 57.79 |
Floor, price per barrel | 47.42 |
Oil contracts, price per bbl | Collar contracts with short puts for Q3 | |
Derivative [Line Items] | |
Ceiling, price per barrel | 57.70 |
Floor, price per barrel | 47.34 |
Oil contracts, price per bbl | Collar contracts with short puts for Q4 | |
Derivative [Line Items] | |
Ceiling, price per barrel | 57.62 |
Floor, price per barrel | 47.26 |
Oil contracts, price per bbl | Collar contracts with short puts for next year | |
Derivative [Line Items] | |
Ceiling, price per barrel | 60.74 |
Floor, price per barrel | 52.69 |
Short put | Collar contracts with short puts for Q2 | |
Derivative [Line Items] | |
Short put, price per barrel | 37.38 |
Short put | Collar contracts with short puts for Q3 | |
Derivative [Line Items] | |
Short put, price per barrel | 37.31 |
Short put | Collar contracts with short puts for Q4 | |
Derivative [Line Items] | |
Short put, price per barrel | 37.23 |
Short put | Collar contracts with short puts for next year | |
Derivative [Line Items] | |
Short put, price per barrel | 42.69 |
Derivative Financial Instrume43
Derivative Financial Instruments (Schedule of NGL Derivative Contracts Volume and Weighted Average Prices) (Details) - Ethane | Mar. 31, 2018bbl / dMMBTU / d$ / MMBTU |
NGL contract, MMBtu Equivalent | |
Derivative [Line Items] | |
Volume, barrels per day | 6,920 |
NGL contract, MMBtu Equivalent | Basis Swap Contracts for Q2 | |
Derivative [Line Items] | |
Volume, barrels per day | 6,920 |
NGL contract, MMBtu Equivalent | Basis Swap Contracts for Q3 | |
Derivative [Line Items] | |
Volume, barrels per day | 6,920 |
NGL contract, MMBtu Equivalent | Basis swap contracts for Q4 | |
Derivative [Line Items] | |
Volume, barrels per day | 6,920 |
NGL contract, MMBtu Equivalent | Basis swap contracts for next year | |
Derivative [Line Items] | |
Volume, barrels per day | 6,920 |
NGL contract, price per MMBtu Equivalent | Basis Swap Contracts for Q2 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis Swap Contracts for Q3 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for Q4 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for next year | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, in BBLS | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 2,500 |
Derivative Financial Instrume44
Derivative Financial Instruments (Schedule of Gas Derivative Contracts Volume and Weighted Average Prices) (Details) | May 04, 2018MMBTU / d$ / MMBTU | Mar. 31, 2018MMBTU / d$ / MMBTU |
Swap contracts for Q2 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Swap contracts for Q2 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3 | |
Swap contracts for Q3 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Swap contracts for Q3 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3 | |
Swap contracts for Q4 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Swap contracts for Q4 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3 | |
Swap contracts for next year | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Swap contracts for next year | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 0 | |
Collar contracts with short puts for Q2 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 50,000 | |
Collar contracts with short puts for Q2 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.40 | |
Floor, price per barrel | 2.75 | |
Short put, price per barrel | 2.25 | |
Collar contracts with short puts for Q3 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 50,000 | |
Collar contracts with short puts for Q3 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.40 | |
Floor, price per barrel | 2.75 | |
Short put, price per barrel | 2.25 | |
Collar contracts with short puts for Q4 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 50,000 | |
Collar contracts with short puts for Q4 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.40 | |
Floor, price per barrel | 2.75 | |
Short put, price per barrel | 2.25 | |
Collar contracts with short puts for next year | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Collar contracts with short puts for next year | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 0 | |
Floor, price per barrel | 0 | |
Short put, price per barrel | 0 | |
Basis Swap Contracts for Q2 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 40,000 | |
Basis Swap Contracts for Q2 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.30 | |
Basis Swap Contracts for Q3 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 80,000 | |
Basis Swap Contracts for Q3 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.30 | |
Basis swap contracts for Q4 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 66,522 | |
Basis swap contracts for Q4 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.50 | |
Basis swap contracts for next year | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 84,932 | |
Basis swap contracts for next year | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.33 | |
Basis Swap Contracts for July 2018 Through September 2019 | Gas contracts, in MMBTU | Southern California | Subsequent event | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 20,000 | |
Price differential, dollars per barrel | 1.54 | |
Basis Swap Contracts for January 2019 Through September 2019 | Gas contracts, in MMBTU | Southern California | Subsequent event | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 30,000 | |
Price differential, dollars per barrel | 1.47 |
Derivative Financial Instrume45
Derivative Financial Instruments (Schedule of Marketing Derivative Contracts Volume and Price) (Details) - Oil index swap contracts | Mar. 31, 2018bbl / d$ / bbl |
Louisiana Light Sweet | Second Quarter | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | 10,000 |
Price differential, dollars per barrel | $ / bbl | 3.18 |
Louisiana Light Sweet | Third Quarter | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | 6,739 |
Price differential, dollars per barrel | $ / bbl | 3.18 |
Louisiana Light Sweet | Index Swap Contracts for June 2018 Through August 2018 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | 10,000 |
Magellan East Houston | Second Quarter | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | 8,659 |
Price differential, dollars per barrel | $ / bbl | 3.29 |
Magellan East Houston | Third Quarter | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | 2,022 |
Price differential, dollars per barrel | $ / bbl | 3.30 |
Derivative Financial Instrume46
Derivative Financial Instruments (Schedule Of Derivative Instruments) (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Derivative [Line Items] | ||
Net Fair Value Presented in the Consolidated Balance Sheet, Asset Derivatives - current | $ 7 | $ 11 |
Net Fair Value Presented in the Consolidated Balance Sheet, Liabilities Derivatives - current | 333 | 232 |
Net Fair Value Presented in the Consolidated Balance Sheet, Liabilities Derivatives - noncurrent | 54 | 23 |
Derivatives not designated as hedging instruments | ||
Derivative [Line Items] | ||
Net Fair Value Presented in the Consolidated Balance Sheet, Asset Derivatives | 7 | 11 |
Net Fair Value Presented in the Consolidated Balance Sheet, Liabilities Derivatives | 387 | 255 |
Derivatives not designated as hedging instruments | Commodity price derivatives | Derivatives - current | ||
Derivative [Line Items] | ||
Asset Derivatives, Fair Value | 14 | 13 |
Gross Amounts Offset in the Consolidated Balance Sheet, Assets Derivatives | (7) | (2) |
Net Fair Value Presented in the Consolidated Balance Sheet, Asset Derivatives - current | 7 | 11 |
Liability Derivatives, Fair Value | 340 | 234 |
Gross Amounts Offset in the Consolidated Balance Sheet. Liabilities Derivatives | (7) | (2) |
Net Fair Value Presented in the Consolidated Balance Sheet, Liabilities Derivatives - current | 333 | 232 |
Derivatives not designated as hedging instruments | Commodity price derivatives | Derivatives - noncurrent | ||
Derivative [Line Items] | ||
Asset Derivatives, Fair Value | 8 | 3 |
Gross Amounts Offset in the Consolidated Balance Sheet, Assets Derivatives | (8) | (3) |
Net Fair Value Presented in the Consolidated Balance Sheet, Asset Derivatives - noncurrent | 0 | 0 |
Liability Derivatives, Fair Value | 62 | 26 |
Gross Amounts Offset in the Consolidated Balance Sheet. Liabilities Derivatives | (8) | (3) |
Net Fair Value Presented in the Consolidated Balance Sheet, Liabilities Derivatives - noncurrent | $ 54 | $ 23 |
Derivative Financial Instrume47
Derivative Financial Instruments (Schedule Of Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Derivative [Line Items] | ||
Derivative gains (losses), net | $ (208) | $ 151 |
Derivative gains (losses), net | Commodity price derivatives | ||
Derivative [Line Items] | ||
Derivative gains (losses), net | $ (208) | $ 151 |
Exploratory Costs (Schedule Of
Exploratory Costs (Schedule Of Capitalized Exploratory Well And Project Activity) (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |
Beginning capitalized exploratory well costs | $ 505 |
Additions to exploratory well costs pending the determination of proved reserves | 582 |
Reclassification due to determination of proved reserves | (607) |
Exploratory well costs charged to exploration and abandonment expense | (4) |
Ending capitalized exploratory well costs | $ 476 |
Exploratory Costs (Capitalized
Exploratory Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Capitalized exploratory well costs that have been suspended: | ||
One year or less | $ 464 | $ 493 |
More than one year | 12 | 12 |
Total | $ 476 | $ 505 |
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year | 7 | 7 |
Exploratory Costs (Narrative) (
Exploratory Costs (Narrative) (Details) | Mar. 31, 2018 | Dec. 31, 2017 |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year | 7 | 7 |
Eagle Ford Shale area | ||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year | 7 |
Long-term Debt (Details)
Long-term Debt (Details) - USD ($) | May 01, 2018 | Mar. 31, 2018 | Mar. 31, 2017 |
Debt Instrument [Line Items] | |||
Aggregate loan commitments | $ 1,500,000,000 | ||
Outstanding borrowing | 0 | ||
Repayments | $ 0 | $ 485,000,000 | |
6.65% Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.65% | ||
Repayments | $ 485,000,000 | ||
6.875% Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.875% | ||
Subsequent event | 6.875% Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.875% | ||
Repayments | $ 450,000,000 |
Incentive Plans Incentive Plans
Incentive Plans Incentive Plans (Stock-based compensation) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Compensation Related Costs [Abstract] | |||
Stock-based compensation expense | $ 23 | $ 30 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized stock-based compensation expense | $ 163 | ||
Remaining vesting period | 3 years | ||
Restricted Stock Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized stock-based compensation expense | $ 35 | ||
Restricted Stock Liability Awards | Affiliates | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Due to affiliates | $ 4 | $ 20 |
Incentive Plans Incentive Pla53
Incentive Plans Incentive Plans (Share Based Incentive Award Activity) (Details) - shares | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Restricted Stock Equity Awards | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Beginning balance outstanding, shares | 916,223 | |
Awards granted, shares | 369,170 | |
Awards forfeited, shares | (11,986) | |
Awards vested, shares | (395,682) | |
Ending balance outstanding, shares | 877,725 | |
Restricted Stock Liability Awards | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Beginning balance outstanding, shares | 252,735 | |
Awards granted, shares | 108,129 | |
Awards forfeited, shares | (2,652) | |
Awards vested, shares | (121,776) | |
Ending balance outstanding, shares | 236,436 | |
Performance Units | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Beginning balance outstanding, shares | 163,158 | |
Awards granted, shares | 62,541 | |
Awards forfeited, shares | (1,285) | |
Awards vested, shares | 0 | |
Ending balance outstanding, shares | 224,414 | |
Stock Options | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Stock options outstanding, shares | 138,493 | 138,493,000 |
Exercise of stock options, shares | 0 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning asset retirement obligations | $ 271 | $ 297 | |
New wells placed on production | 1 | 1 | |
Changes in estimates | 2 | 0 | |
Obligations reclassified to liabilities held for sale | (6) | 0 | |
Liabilities settled | (9) | (6) | |
Accretion of discount | 4 | 5 | |
Ending asset retirement obligations | 263 | $ 297 | |
Asset retirement obligations, current portions | $ 40 | $ 41 |
Commitments and Contingencies (
Commitments and Contingencies (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended |
Jun. 30, 2017 | Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | ||
Operating lease term | 20 years | |
Annual base rent | $ 33 | |
Capitalized construction costs | $ 79 |
Revenue Recognition (Schedule o
Revenue Recognition (Schedule of Adoption of ASC 606) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Oil and gas | $ 1,266 | $ 809 |
Oil and gas production | 213 | $ 141 |
Accounting Standards Update 2014-09 [Member] | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Oil and gas | 1,266 | |
Oil and gas production | 213 | |
ASC 605 (Without Adoption of ASC 606) | Accounting Standards Update 2014-09 [Member] | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Oil and gas | 1,223 | |
Oil and gas production | 170 | |
Effect of Change Higher (Lower) | Accounting Standards Update 2014-09 [Member] | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Oil and gas | 43 | |
Oil and gas production | $ 43 |
Revenue Recognition (Disaggrega
Revenue Recognition (Disaggregation of Revenue) (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Disaggregation of Revenue [Line Items] | |
Total revenue derived from contracts with purchasers | $ 2,336 |
Oil sales | |
Disaggregation of Revenue [Line Items] | |
Total revenue derived from contracts with purchasers | 1,013 |
NGL sales | |
Disaggregation of Revenue [Line Items] | |
Total revenue derived from contracts with purchasers | 165 |
Gas sales | |
Disaggregation of Revenue [Line Items] | |
Total revenue derived from contracts with purchasers | 88 |
Total oil and gas sales | |
Disaggregation of Revenue [Line Items] | |
Total revenue derived from contracts with purchasers | 1,266 |
Sales of purchased oil and gas | |
Disaggregation of Revenue [Line Items] | |
Total revenue derived from contracts with purchasers | $ 1,070 |
Revenue Recognition (Narrative)
Revenue Recognition (Narrative) (Details) $ in Millions | Mar. 31, 2018USD ($) |
Revenue from Contract with Customer [Abstract] | |
Accounts receivable balance representing amounts due or billable | $ 793 |
Interest and Other Income (Comp
Interest and Other Income (Components Of Interest And Other Income) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Interest and Other Income [Abstract] | ||
Interest income | $ 7 | $ 6 |
Deferred compensation plan income | 4 | 2 |
Seismic data sales | 3 | 0 |
Severance and sales tax refunds | 2 | 3 |
Other income | 2 | 2 |
Total interest and other income | $ 18 | $ 13 |
Other Expense (Schedule Of Comp
Other Expense (Schedule Of Components Of Other Expense) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Other Income and Expenses [Abstract] | ||
Transportation commitment charges | $ 34 | $ 40 |
Loss from vertical integration services | 6 | 5 |
Other | 17 | 15 |
Total other expense | 57 | 60 |
Vertical integration net margins, revenue | 34 | 19 |
Vertical integration net margins, costs and expenses | $ 40 | $ 24 |
Income Taxes (Income tax (provi
Income Taxes (Income tax (provisions) benefits attributable to income from continuing operations) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | ||
Deferred income taxes | $ 50 | $ (31) |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Effective tax rate | 22.00% | 42.00% | |
U.S. statutory rate | 21.00% | ||
Recognizing excess tax benefits associated with the adoption of ASU 2016-09 | $ 8 | ||
Unrecognized Tax Benefits | $ 127 | $ 124 |
Net Income (Loss) Per Share (Re
Net Income (Loss) Per Share (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Earnings Per Share [Abstract] | ||
Net income (loss) attributable to common stockholders | $ 178,000 | $ (42,000) |
Participating share-based earnings | (1,000) | 0 |
Basic income (loss) from continuing operations attributable to common stockholders | 177,000 | (42,000) |
Diluted income (loss) from continuing operations attributable to common stockholders | $ 177,000 | $ (42,000) |
Net Income (Loss) Per Share (Na
Net Income (Loss) Per Share (Narrative) (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Feb. 28, 2018 |
Earnings Per Share [Abstract] | ||
Authorized amount | $ 100 | |
Remaining authorized amount | $ 83 | |
Common stock purchased | $ 17 |
Net Income (Loss) Per Share Net
Net Income (Loss) Per Share Net Income (Loss) Per Share (Schedule of Weighted Average Number of Shares) (Details) - shares shares in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Weighted average shares, basic | 170,000 | 170,000 |
Incremental Common Shares Attributable to Dilutive Effect of Call Options and Warrants | 1,000 | 0 |
Weighted average shares, diluted | 171,000 | 170,000 |
Subsequent Events Subsequent Ev
Subsequent Events Subsequent Events (Details) - USD ($) $ in Millions | May 01, 2018 | Apr. 30, 2018 | Mar. 31, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Mar. 31, 2017 |
Subsequent Event [Line Items] | ||||||
Cash proceeds | $ 4 | $ 78 | ||||
Principal payments on long-term debt | $ 0 | $ 485 | ||||
6.875% Senior notes | ||||||
Subsequent Event [Line Items] | ||||||
Stated interest rate | 6.875% | 6.875% | ||||
West Eagle Ford Shale | ||||||
Subsequent Event [Line Items] | ||||||
Cash proceeds | $ 22 | |||||
Minimum | Forecast | West Eagle Ford Shale | ||||||
Subsequent Event [Line Items] | ||||||
Gain on disposal | $ (75) | |||||
Maximum | Forecast | West Eagle Ford Shale | ||||||
Subsequent Event [Line Items] | ||||||
Gain on disposal | $ (85) | |||||
Subsequent event | 6.875% Senior notes | ||||||
Subsequent Event [Line Items] | ||||||
Stated interest rate | 6.875% | |||||
Principal payments on long-term debt | $ 450 | |||||
Subsequent event | West Eagle Ford Shale | ||||||
Subsequent Event [Line Items] | ||||||
Cash proceeds | $ 81 |