Organization And Nature Of Oper
Organization And Nature Of Operations | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Organization and Nature of OperationsPioneer 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 in the Permian Basin in West Texas. |
Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 18, 2020 | Jun. 30, 2019 | |
Cover page. | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 1-13245 | ||
Entity Registrant Name | PIONEER NATURAL RESOURCES CO | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 75-2702753 | ||
Entity Address, Address Line One | 777 Hidden Ridge | ||
Entity Address, City or Town | Irving | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 75038 | ||
City Area Code | 972 | ||
Local Phone Number | 444-9001 | ||
Title of 12(b) Security | Common Stock, par value $.01 per share | ||
Trading Symbol | PXD | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 25,544,329,552 | ||
Entity Common Stock, Shares Outstanding | 165,714,771 | ||
Entity Central Index Key | 0001038357 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 631 | $ 825 |
Restricted cash | 74 | 0 |
Short-term investments | 0 | 443 |
Accounts receivable: | ||
Trade, net | 1,032 | 694 |
Due from affiliates | 3 | 120 |
Income taxes receivable | 7 | 7 |
Inventories | 205 | 242 |
Derivatives | 32 | 52 |
Investment in affiliate | 187 | 172 |
Other | 20 | 25 |
Total current assets | 2,191 | 2,580 |
Oil and gas properties, using the successful efforts method of accounting: | ||
Proved properties | 22,444 | 21,165 |
Unproved properties | 584 | 601 |
Accumulated depletion, depreciation and amortization | (8,583) | (8,218) |
Total oil and gas properties, net | 14,445 | 13,548 |
Other property and equipment, net | 1,632 | 1,291 |
Operating lease right-of-use assets | 280 | |
Long-term investments | 0 | 125 |
Goodwill | 261 | 264 |
Other assets | 258 | 95 |
Total Assets | 19,067 | 17,903 |
Accounts payable: | ||
Trade | 1,221 | 1,441 |
Due to affiliates | 190 | 183 |
Interest payable | 53 | 53 |
Income taxes payable | 3 | 2 |
Current portion of long-term debt | 450 | 0 |
Derivatives | 12 | 27 |
Operating leases | 136 | |
Other | 431 | 112 |
Total current liabilities | 2,496 | 1,818 |
Long-term debt | 1,839 | 2,284 |
Derivatives | 8 | 0 |
Deferred income taxes | 1,389 | 1,152 |
Operating leases | 170 | |
Other liabilities | 1,046 | 538 |
Equity: | ||
Common stock, $.01 par value | 2 | 2 |
Additional paid-in capital | 9,161 | 9,062 |
Treasury Stock at cost | (1,069) | (423) |
Retained earnings | 4,025 | 3,470 |
Total equity | 12,119 | 12,111 |
Commitments and contingencies | ||
Total Liabilities and Stockholders' Equity | $ 19,067 | $ 17,903 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Common stock, par value | $ 0.01 | |
Common stock, shares authorized | 500,000,000 | |
Common stock, shares issued | 175,057,889 | 174,321,171 |
Treasury stock, shares | 9,511,248 | 4,822,069 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues and other income: | |||
Revenue | $ 9,671 | $ 9,379 | |
Interest and other | 76 | 38 | $ 53 |
Derivative gain (loss), net | 34 | (292) | (100) |
Gain (loss) on disposition of assets, net | (477) | 290 | 208 |
Revenues | 9,304 | 9,415 | 5,455 |
Costs and expenses: | |||
Production and ad valorem taxes | 299 | 284 | 215 |
Depletion, depreciation and amortization | 1,711 | 1,534 | 1,400 |
Impairment of oil and gas properties | 0 | 77 | 285 |
Exploration and abandonments | 58 | 114 | 106 |
General and administrative | 324 | 381 | 326 |
Accretion of discount on asset retirement obligations | 10 | 14 | 19 |
Interest | 121 | 126 | 153 |
Other | 448 | 849 | 244 |
Costs and Expenses | 8,317 | 8,164 | 5,146 |
Income before income taxes | 987 | 1,251 | 309 |
Income tax (provision) benefit | (231) | (276) | 524 |
Net income | 756 | 975 | 833 |
Net loss attributable to noncontrolling interests | 0 | 3 | 0 |
Net income attributable to common stockholders | $ 756 | $ 978 | $ 833 |
Net income per share attributable to common stockholders: | |||
Basic (usd per share) | $ 4.50 | $ 5.71 | $ 4.86 |
Diluted (usd per share) | $ 4.50 | $ 5.70 | $ 4.85 |
Basic and diluted weighted average shares outstanding | 167 | 171 | 170 |
Oil and gas | |||
Revenues and other income: | |||
Revenue | $ 4,916 | $ 4,991 | $ 3,518 |
Costs and expenses: | |||
Cost of revenue | 874 | 855 | 591 |
Sales of purchased oil and gas | |||
Revenues and other income: | |||
Revenue | 4,755 | 4,388 | 1,776 |
Costs and expenses: | |||
Cost of revenue | $ 4,472 | $ 3,930 | $ 1,807 |
Consolidated Statements Of Stoc
Consolidated Statements Of Stockholders' Equity - 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, 2016 | 169,724 | |||||
Beginning Balance at Dec. 31, 2016 | $ 10,411 | $ 2 | $ 8,892 | $ (218) | $ 1,728 | $ 7 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Dividends declared | (14) | (14) | ||||
Exercise of long-term incentive plan stock options and employee stock purchases | 6 | 1 | 5 | |||
Exercise of long-term incentive plan stock options and employee stock purchases, shares | 81 | |||||
Purchase of treasury stock, shares | (191) | |||||
Purchase of treasury stock | (36) | (36) | ||||
Compensation costs: | ||||||
Vested compensation awards, net, shares | 575 | |||||
Vested compensation awards, net | 0 | |||||
Compensation costs included in net income | 79 | 79 | ||||
Noncontrolling Interest, Increase from Subsidiary Equity Issuance | 0 | 2 | (2) | |||
Net income (loss) | 833 | 833 | ||||
Ending Balance, shares at Dec. 31, 2017 | 170,189 | |||||
Ending Balance at Dec. 31, 2017 | $ 11,279 | $ 2 | 8,974 | (249) | 2,547 | 5 |
Compensation costs: | ||||||
Dividends declared (usd per share) | $ 0.08 | |||||
Dividends declared | $ (55) | (55) | ||||
Exercise of long-term incentive plan stock options and employee stock purchases | 8 | 3 | 5 | |||
Exercise of long-term incentive plan stock options and employee stock purchases, shares | 58 | |||||
Purchase of treasury stock, shares | (1,272) | |||||
Purchase of treasury stock | (179) | (179) | ||||
Vested compensation awards, net, shares | 524 | |||||
Vested compensation awards, net | 0 | |||||
Compensation costs included in net income | 85 | 85 | ||||
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests | (2) | 0 | (2) | |||
Net income (loss) | 975 | 978 | (3) | |||
Ending Balance, shares at Dec. 31, 2018 | 169,499 | |||||
Ending Balance at Dec. 31, 2018 | $ 12,111 | $ 2 | 9,062 | (423) | 3,470 | $ 0 |
Compensation costs: | ||||||
Dividends declared (usd per share) | $ 0.32 | |||||
Dividends declared | $ (201) | (201) | ||||
Exercise of long-term incentive plan stock options and employee stock purchases | 6 | (1) | 7 | |||
Exercise of long-term incentive plan stock options and employee stock purchases, shares | 64 | |||||
Purchase of treasury stock, shares | (4,753) | |||||
Purchase of treasury stock | (653) | (653) | ||||
Vested compensation awards, net, shares | 737 | |||||
Vested compensation awards, net | 0 | |||||
Compensation costs included in net income | 100 | 100 | ||||
Net income (loss) | 756 | 756 | ||||
Ending Balance, shares at Dec. 31, 2019 | 165,547 | |||||
Ending Balance at Dec. 31, 2019 | $ 12,119 | $ 2 | $ 9,161 | $ (1,069) | $ 4,025 | |
Compensation costs: | ||||||
Dividends declared (usd per share) | $ 1.20 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities: | |||
Net income | $ 756 | $ 975 | $ 833 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depletion, depreciation and amortization | 1,711 | 1,534 | 1,400 |
Impairment of oil and gas properties | 0 | 77 | 285 |
Impairment of inventory and other property and equipment | 38 | 11 | 2 |
Exploration expenses, including dry holes | 8 | 27 | 22 |
Deferred income taxes | 236 | 274 | (519) |
(Gain) loss on disposition of assets, net | 477 | (290) | (208) |
Accretion of discount on asset retirement obligations | 10 | 14 | 19 |
Interest expense | 9 | 5 | 5 |
Derivative related activity | 13 | (270) | 174 |
Amortization of stock-based compensation | 100 | 85 | 79 |
Investment in affiliate valuation adjustment | (15) | 0 | 0 |
Contingent consideration valuation adjustment | 45 | 0 | 0 |
Other | 105 | 658 | 85 |
Change in operating assets and liabilities: | |||
Accounts receivable | (227) | (52) | (120) |
Inventories | (20) | (70) | (35) |
Other assets | (33) | 3 | (3) |
Accounts payable | (7) | 321 | 134 |
Interest payable | 0 | (5) | (9) |
Other liabilities | (91) | (55) | (45) |
Net cash provided by operating activities | 3,115 | 3,242 | 2,099 |
Cash flows from investing activities: | |||
Proceeds from disposition of assets, net of cash sold | 149 | 469 | 352 |
Proceeds from investments | 624 | 1,373 | 1,467 |
Purchase of investments | 0 | (669) | (904) |
Additions to oil and gas properties | (2,988) | (3,520) | (2,365) |
Additions to other assets and other property and equipment, net | (232) | (263) | (342) |
Net cash used in investing activities | (2,447) | (2,610) | (1,792) |
Cash flows from financing activities: | |||
Principal payments on long-term debt | 0 | (450) | (485) |
Payments of other liabilities | (14) | (23) | 0 |
Exercise of long-term incentive plan stock options and employee stock purchases | 6 | 8 | 6 |
Purchases of treasury stock | (653) | (179) | (36) |
Payments of financing fees | 0 | (4) | 0 |
Dividends paid | (127) | (55) | (14) |
Net cash used in financing activities | (788) | (703) | (529) |
Net decrease in cash, cash equivalents and restricted cash | (120) | (71) | (222) |
Cash, cash equivalents and restricted cash, beginning of period | 825 | 896 | 1,118 |
Cash, cash equivalents and restricted cash, end of period | $ 705 | $ 825 | $ 896 |
Exploratory Well Costs
Exploratory Well Costs | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Exploratory Well Costs | Exploratory Well 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 included in proved properties in the consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are recorded as exploration and abandonments expense. Capitalized exploratory well project activity is as follows: Year Ended December 31, 2019 2018 (in millions) Beginning capitalized exploratory well costs $ 509 $ 505 Additions to exploratory well costs pending the determination of proved reserves 2,172 2,585 Reclassification due to determination of proved reserves (2,011) (2,557) Disposition of assets (6) (1) Exploratory well costs charged to exploration and abandonment expense (4) (23) Ending capitalized exploratory well costs $ 660 $ 509 Aging 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, are as follows: As of December 31, 2019 2018 2017 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 660 $ 509 $ 493 More than one year — — 12 $ 660 $ 509 $ 505 Number of projects with exploratory well costs that have been suspended for a period greater than one year — — 7 |
Exploratory Well Costs (Tables)
Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Capitalized exploratory well and project activity | Capitalized exploratory well project activity is as follows: Year Ended December 31, 2019 2018 (in millions) Beginning capitalized exploratory well costs $ 509 $ 505 Additions to exploratory well costs pending the determination of proved reserves 2,172 2,585 Reclassification due to determination of proved reserves (2,011) (2,557) Disposition of assets (6) (1) Exploratory well costs charged to exploration and abandonment expense (4) (23) Ending capitalized exploratory well costs $ 660 $ 509 |
Capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized | Aging 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, are as follows: As of December 31, 2019 2018 2017 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 660 $ 509 $ 493 More than one year — — 12 $ 660 $ 509 $ 505 Number of projects with exploratory well costs that have been suspended for a period greater than one year — — 7 |
Exploratory Well Costs (Capital
Exploratory Well Costs (Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ||
Beginning capitalized exploratory well costs | $ 509 | $ 505 |
Additions to exploratory well costs pending the determination of proved reserves | 2,172 | 2,585 |
Reclassification due to determination of proved reserves | (2,011) | (2,557) |
Disposition of assets | (6) | (1) |
Exploratory well costs charged to exploration and abandonment expense | (4) | (23) |
Ending capitalized exploratory well costs | $ 660 | $ 509 |
Exploratory Well Costs (Capit_2
Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Capitalized exploratory well costs that have been suspended: | |||
One year or less | $ 660 | $ 509 | $ 493 |
More than one year | 0 | 0 | 12 |
Total | $ 660 | $ 509 | $ 505 |
Number of projects with exploratory well costs that have been suspended for a period greater than one year | 0 | 0 | 7 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | NOTE 2. Summary of Significant Accounting Policies Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period's presentation. Use of estimates in the preparation of financial statements. Preparation of the Company's consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of proved and unproved oil and gas properties and goodwill, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized. Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less. Restricted cash. The Company's restricted cash includes funds held in escrow to cover future deficiency fee payments in connection with the Company's 2019 sale of its Eagle Ford assets and other remaining assets in South Texas (the "South Texas Divestiture"). Beginning in 2021, the required escrow balance declines and, to the extent there is any remaining balance after the payment of deficiency fees, the balance will become unrestricted and revert to the Company on March 31, 2023. Interest income related to restricted cash is recorded in interest and other income in the consolidated statements of operations. Investments. 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. 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 included in short-term investments or long-term investments in the consolidated balance sheets based on their maturity dates. As of December 31, 2019, the Company has no investments classified as held-to-maturity. As of December 31, 2018, the Company's investments were carried at amortized cost and classified as held-to-maturity as the Company had the intent and ability to hold them until they mature. The carrying values of held-to-maturity investments were adjusted for amortization of premiums and accretion of discounts over the remaining life of the investment. Income related to these investments was recorded in interest and other income in the consolidated statements of operations. Accounts receivable. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers. T he Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. The Company's allowance for doubtful accounts totaled $2 million for each of the years ended December 31, 2019 and 2018. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and are recorded in other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas maintenance materials and repair parts, water, chemicals and other operating supplies. The materials and supplies inventory is primarily acquired for use in future drilling and production operations or repair operations and is carried at the lower of cost or market, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories included in the Company's consolidated balance sheets and are recorded in other expense in the consolidated statements of operations. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, NGLs and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations. The components of inventories are as follows: As of December 31, 2019 2018 (in millions) Materials and supplies (a) $ 75 $ 128 Commodities 130 114 Total inventories $ 205 $ 242 ____________________ (a) As of December 31, 2019 and 2018, the Company's materials and supplies inventories were net of valuation allowances of $2 million and $5 million, respectively. Investment in affiliate. In December 2018, the Company completed the sale of its pressure pumping assets to ProPetro Holding Corp. ("ProPetro") in exchange for cash and 16.6 million shares of ProPetro's common stock, representing an ownership interest in ProPetro of 16 percent. Additionally, in October 2019, Phillip A. Gobe, a nonemployee member of the Company's board of directors, was appointed by the board of directors of ProPetro to serve as its Executive Chairman. Mark S. Berg, the Company's Executive Vice President, Corporate Operations, continues to serve as a member of the ProPetro board of directors under the Company's right to designate a director to the board of directors of ProPetro so long as the Company owns five percent or more of ProPetro's outstanding common stock. Based on the Company's ownership in ProPetro and representation on the ProPetro board of directors, ProPetro is considered an affiliate and deemed to be a related party. The Company uses the fair value option to account for its equity method investment in ProPetro with any changes in fair value recorded in interest and other income in the consolidated statements of operations. The carrying value of the Company's investment in ProPetro is included in investment in affiliate in the consolidated balance sheets. See Note 4 and Note 12 for additional information. Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note 6 for additional information. As of December 31, 2019, the Company owns interests in 11 gas processing plants, including the related gathering systems. The Company's ownership interests in the gas processing plants are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. The operators of the plants process the Company's and third-party gas volumes for a fee. The Company's share of revenues and expenses derived from volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Revenues generated from the processing plants and treating facilities for the years ended December 31, 2019, 2018 and 2017 were $90 million, $78 million and $60 million, respectively. Expenses attributable to the processing plants and treating facilities for the same respective periods were $43 million, $36 million and $26 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Impairment charges for proved oil and gas properties are recorded in impairment of oil and gas properties in the consolidated statements of operations. See Note 4 for additional information. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time. Impairment charges for unproved oil and gas properties are recorded in exploration and abandonments in the consolidated statements of operations. Goodwill. Goodwill is assessed for impairment whenever it is likely that events or circumstances indicate the carrying value of a reporting unit exceeds its fair value, but no less often than annually. An impairment charge is recorded for the amount by which the carrying amount exceeds the fair value of a reporting unit in the period it is determined to be impaired. The Company performed its annual qualitative assessment of goodwill during the third quarter of 2019 to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount. Based on the results of the assessment, the Company determined it was not likely that the carrying value of the Company's reporting unit exceeded its fair value. Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $382 million and $854 million as of December 31, 2019 and 2018, respectively, are as follows: As of December 31, 2019 2018 (in millions) Land and buildings (a) $ 877 $ 380 Water infrastructure (b) 404 343 Construction-in-progress and capitalized interest (c) 152 311 Information technology 120 143 Transport and field equipment (d) 35 50 Furniture and fixtures 28 15 Proved and unproved sand properties (e) 16 36 Leasehold improvements — 13 Total other property and equipment, net $ 1,632 $ 1,291 ____________________ (a) Includes land, buildings, any related improvements to land and buildings, and a finance lease entered into by the Company for its new corporate headquarters in Irving, Texas. See Note 10 for additional information. (b) Includes costs for pipeline infrastructure and water supply wells. (c) Includes capitalized costs and capitalized interest on other property and equipment not yet placed in service. (d) Includes vehicles and well servicing equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, construction equipment and fishing tools, that are used on Company-operated properties. (e) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years. Equipment, vehicles, furniture and fixtures and information technology assets are generally depreciated over three three The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. Leases. The Company enters into leases for drilling rigs, storage tanks, equipment and buildings and recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. See Note 10 for additional information. Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. The Company includes the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the consolidated balance sheets and expenditures are included as cash used in operating activities in the consolidated statements of cash flows. See Note 9 for additional information. Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. Revenue recognition. On January 1, 2018, the Company adopted Accounting Standards Codification ("ASC") 606, "Revenue from Contracts with Customers," ("ASC 606") using the modified retrospective transition method. The adoption did not require an adjustment to retained earnings as there was no material change to the timing or pattern of revenue recognition due to the adoption of ASC 606. The Company recognizes revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. 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 the sales revenue when (i) control/custody transfers to the purchaser at the wellhead and (ii) the net price is fixed and determinable. NGL and gas sales . Under the majority of the Company’s gas processing contracts, gas is delivered to a midstream processing entity and the Company elects to take residue gas and NGLs in-kind at the tailgate. The Company recognizes revenue when the products are delivered (custody transfer) to the ultimate third-party purchaser at a contractually agreed-upon delivery point at a specified index price. Sales of purchased oil and gas. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate oil ("WTI") and gas sales to Gulf Coast refineries and LNG facilities, international export markets and to satisfy unused gas 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 both the risk and rewards of ownership, including credit risk, of the commodities purchased and the responsibility to deliver the commodities sold. Transportation costs associated with these transactions are presented on a net basis in purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are recorded as other expense in the consolidated statements of operations. See Note 14 and Note 16 for additional information. Derivatives. All of the Company's derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. 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 Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. The Company's credit risk related to derivatives is a counterparty's failure to perform under derivative contracts owed to the Company. 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. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 for additional information. Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date. The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all of the deferred tax assets will not be realized. 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. 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. See Note 17 for additional information. The Company records any tax-related interest charges as interest expense and any tax-related penalties as other expense in the consolidated statements of operations. Stock-based compensation. Stock-based compensation expense for restricted stock, restricted stock units and performance units expected to be settled in the Company's common stock ("Equity Awards") is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of estimated forfeitures, on a straight line basis over the requisite service period of the respective award. The fair value of Equity Awards, except performance unit awards, is determined on the grant date or modification date, as applicable, using the prior day's closing stock price. The fair value of performance unit awards is determined using the Monte Carlo simulation model. Equity Awards are net settled by withholding shares of the Company's common stock to satisfy income tax withholding payments due upon vesting. Remaining vested shares are remitted to individual employee brokerage accounts. Shares to be delivered upon vesting of Equity Awards are made available from authorized, but unissued shares or shares held as treasury stock. Restricted stock awards expected to be settled in cash on their vesting dates, rather than in common stock ("Liability Awards"), are included in accounts payable – due to affiliates in the consolidated balance sheets. The fair value of Liability Awards is determined on the grant date using the prior day's closing stock price. The Company recognizes the value of Liability Awards on a straight line basis over the requisite service period of the award. Liability Awards are marked to fair value as of each balance sheet date using the closing stock price on the balance sheet date. Changes in the fair value of Liability Awards are recorded as increases or decreases to stock-based compensation expense. Equity Awards and Liability awards participate in dividends during vesting periods and generally vest over three years. Segments. Based upon how the Company is organized and managed, the Company has one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. Adoption of new accounting standards. In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" ("ASC 842"), which supersedes the lease recognition requirements in ASC 840, "Leases" ("ASC 840"), and requires lessees to recognize lease assets and lease liabilities for those leases previously classified as operating leases. The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU 2018-11, "Leases (Topic 842) Targeted Improvements," in which ASC 842 is applied at the adoption date, while the comparative periods will continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. ASC 842 allowed for the election of certain practical expedients at adoption to ease the burden of implementation. At implementation, the Company elected to (i) maintain the historical lease classification for leases prior to January 1, 2019, (ii) maintain the historical accounting treatment for land easements that existed at adoption, (iii) use historical practices in assessing the lease term of existing contracts at adoption, (iv) combine lease and non-lease components of a contract as a single lease and (v) not record short-term leases in the consolidated balance sheet, all in accordance with ASC 842. The adoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on the Company's cash flows. The Company did not record a change to its opening retained earnings as of January 1, 2019, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842. New accounting pronouncements. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. Entities will use the modified retrospective approach to apply the standard's provisions and record a cumulative-effect adjustment to retained earnings for additional receivable loss allowances, if any, as of the beginning of the first reporting period in which the guidance is adopted. While the Company continues to prepare for the adoption of ASU 2016-13 on January 1, 2020, the Company does not expect that it will have a material impact on its consolidated financial statements. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions, Divestitures, Decommissioning and Restructuring Activities Acquisitions. During 2019, 2018 and 2017, the Company spent a total of $28 million, $65 million and $136 million, respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities in the Spraberry/Wolfcamp field of the Permian Basin. Divestitures. The Company's significant divestitures are as follows: • In December 2019, the Company completed the sale of certain vertical and horizontal wells and approximately 4,500 undeveloped acres in Glasscock County of the Permian Basin to an unaffiliated third party for net cash proceeds of $64 million. The Company recorded a gain of $10 million associated with the sale. • In July 2019, the Company completed the sale of certain vertical wells and approximately 1,400 undeveloped acres in Martin County of the Permian Basin to an unaffiliated third party for net cash proceeds of $27 million. The Company recorded a gain of $26 million associated with the sale. • In June 2019, the Company completed the sale of certain vertical wells and approximately 1,900 undeveloped acres in Martin County of the Permian Basin to an unaffiliated third party for net cash proceeds of $38 million. The Company recorded a gain of $31 million associated with the sale. • In May 2019, the Company completed the South Texas Divestiture to an unaffiliated third party in exchange for total consideration having an estimated fair value of $210 million. The fair value of the consideration included (i) net cash proceeds of $2 million, (ii) $136 million in contingent consideration and (iii) a $72 million receivable associated with estimated deficiency fees to be paid by the buyer. Of the total consideration, $208 million is considered a noncash investing activity for the year December 31, 2019. The Company recorded a loss of $525 million and recognized employee-related charges of $19 million associated with the sale. Contingent Consideration. Per the terms of the purchase and sale agreement, the Company is entitled to receive contingent consideration of up to $450 million based on future annual oil and NGL prices during each of the years from 2020 to 2024. The Company determined the fair value of the contingent consideration as of the date of the sale to be $136 million using an option pricing model. The contingent consideration is included in noncurrent other assets in the consolidated balance sheets. The Company revalues the contingent consideration each reporting period and records the resulting valuation changes in interest and other income in the consolidated statements of operations. See Note 4 , Note 5 and Note 15 for additional information. Deficiency Fee Obligation. The Company transferred its long-term midstream agreements and associated minimum volume commitments ("MVC") to the buyer. However, the Company retained the obligation to pay 100 percent of any deficiency fees associated with the MVC from January 2019 through July 2022. The Company determined the fair value of the deficiency fee obligation as of the date of the sale to be $348 million using a probability weighted present value model. The deficiency fee obligation is included in current or noncurrent liabilities in the consolidated balance sheets based on the forecasted timing of payments. See Note 4 for additional information. Deficiency Fee Receivable. The buyer is required to reimburse the Company for up to 20 percent of the deficiency fees paid under the transferred midstream agreements from January 2019 through July 2022. Such reimbursement will be paid by the buyer in installments beginning in 2023 through 2025. The Company determined the fair value of the deficiency fee receivable as of the date of the sale to be $72 million using a credit risk-adjusted valuation model. The deficiency fee receivable is included in noncurrent other assets in the consolidated balance sheets. See Note 4 and Note 11 for additional information. Restricted Cash. As of the date of the sale, the Company deposited $75 million into an escrow account to be used to fund future deficiency fee payments. Beginning in 2021, the required escrow balance will decline to $50 million and, to the extent that there is any remaining balance after the payment of deficiency fees, the balance will become unrestricted and revert to the Company on March 31, 2023. • In December 2018, the Company completed the sale of its pressure pumping assets to ProPetro in exchange for total consideration of $282 million, comprised of 16.6 million shares of ProPetro's common stock, which was delivered as of the date of the sale and had a fair value of $172 million, and $110 million in cash, which was received during the first quarter of 2019. During 2018, the Company recorded a gain of $30 million, employee-related charges of $19 million, contract termination charges of $13 million and other divestiture-related charges of $6 million associated with the sale. During 2019, the Company reduced the gain associated with the sale by $10 million and recorded additional employee-related charges of $1 million. See Note 12 for additional information. • In December 2018, the Company completed the sale of approximately 2,900 net acres in the Sinor Nest (Lower Wilcox) oil field in South Texas to an unaffiliated third party for net cash proceeds of $105 million. During 2018, the Company recorded a gain of $54 million associated with the sale. • In August 2018, the Company completed the sale of its assets in the West Panhandle gas and liquids field to an unaffiliated third party for net cash proceeds of $170 million. During 2018, the Company recorded a gain of $127 million and employee-related charges of $7 million associated with the sale. • In July 2018, the Company completed the sale of its gas field assets in the Raton Basin to an unaffiliated third party for net cash proceeds of $54 million. The Company recorded a noncash impairment charge of $77 million in June 2018 to reduce the carrying value of its Raton Basin assets to their estimated fair value less costs to sell as the assets were considered held for sale. During 2018, the Company recorded a gain of $2 million, other divestiture-related charges of $117 million, including $111 million of deficiency charges related to certain firm transportation contracts retained by the Company and employee-related charges of $6 million associated with the sale. • In April 2018, the Company completed the sale of approximately 10,200 net acres in the West Eagle Ford Shale gas and liquids field to an unaffiliated third party for net cash proceeds of $100 million. During 2018, the Company recorded a gain of $75 million associated with the sale. • In April 2017, the Company completed the sale of approximately 20,500 acres in the Martin County region of the Permian Basin to an unaffiliated third party for net cash proceeds of $264 million. During 2017, the Company recorded a gain of $194 million associated with the sale. • Other. During 2019, 2018 and 2017, the Company sold other proved and unproved properties, inventory and other property and equipment and recorded a net loss of $9 million, and net gains of $1 million and $14 million, respectively. The net gain of $14 million for 2017 is primarily related to the sale of nonstrategic proved and unproved properties in the Permian Basin for cash proceeds of $77 million. Decommissioning. In November 2018, the Company announced plans to close its sand mine located in Brady, Texas and transition its proppant supply requirements to West Texas sand sources. During 2018, the Company recorded $443 million of accelerated depreciation and $7 million of employee-related charges associated with the pending shutdown. During 2019, the Company recorded $23 million of accelerated depreciation, $13 million of inventory and other property and equipment impairment charges and $12 million of sand mine closure-related costs. Restructuring. During 2019, the Company implemented a corporate restructuring program to align its cost structure with the needs of a Permian Basin-focused company, which resulted in an approximately 25 percent employee reduction. The restructuring occurred in three phases (collectively, the "Corporate Restructuring Program") as follows: • In March 2019, the Company made certain changes to its leadership and organizational structure, which included the early retirement and departure of certain officers of the Company. • In April 2019, the Company adopted a voluntary separation program ("VSP") for certain eligible employees, and • In May 2019, the Company implemented an involuntary separation program ("ISP"). During 2019, the Company recorded $159 million of employee-related charges associated with the Corporate Restructuring Program, including $26 million of noncash stock-based compensation expense related to the accelerated vesting of certain equity awards. See Note 8 and Note 16 for additional information. Employee-related costs are primarily recorded in other expense in the consolidated statements of operations. Obligations associated with employee-related charges are included in accounts payable - due to affiliates in the consolidated balance sheets. The changes in employee-related obligations are as follows: Year Ended December 31, 2019 2018 (in millions) Beginning employee-related obligations $ 27 $ — Additions (a) 155 39 Cash payments (176) (12) Ending employee-related obligations $ 6 $ 27 ____________________ (a) Additions for the year ended December 31, 2019 primarily include $133 million of charges related to the Corporate Restructuring Program and $19 million of charges related primarily to the South Texas Divestiture. For the year ended December 31, 2018, additions primarily relate to the 2018 divestitures. |
Disclosures About Fair Value Me
Disclosures About Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Company determines fair value based on the price that would be received from selling an asset or 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 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 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, typically reflecting management's estimate of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore determined using model-based techniques, including discounted cash flow models. Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis are as follows: As of December 31, 2019 Fair Value Measurements Quoted Prices in Significant Other Significant Total (in millions) Assets: Commodity derivatives $ — $ 32 $ — $ 32 Deferred compensation plan assets 85 — — 85 Investment in affiliate 187 — — 187 Contingent consideration — 91 — 91 Total assets 272 123 — 395 Liabilities: Commodity derivatives — 20 — 20 Total recurring fair value measurements $ 272 $ 103 $ — $ 375 As of December 31, 2018 Fair Value Measurements Quoted Prices in Significant Other Significant Total (in millions) Assets: Commodity derivatives $ — $ 52 $ — $ 52 Deferred compensation plan assets 82 — — 82 Investment in affiliate — 172 — 172 Total assets 82 224 — 306 Liabilities: Commodity derivatives — 27 — 27 Total recurring fair value measurements $ 82 $ 197 $ — $ 279 Commodity price derivatives. The Company's commodity derivatives primarily represent oil, NGL and gas swap contracts, collar contracts, collar contracts with short puts and basis swap contracts. The asset and liability measurements for the Company's commodity derivative contracts are determined using Level 2 inputs. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity price derivatives. The asset and liability values attributable to the Company's commodity price 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 include investments in equity and mutual fund securities that are actively traded on major exchanges. The fair value of these investments is determined using Level 1 inputs based on observable prices on major exchanges. Investment in affiliate . The Company elected the fair value option for measuring its equity method investment in ProPetro. The fair value of its investment in ProPetro is determined using Level 1 inputs based on observable prices on a major exchange. As of December 31, 2018, the fair value of the Company's investment in ProPetro was determined using Level 2 inputs, including the quoted market price for the stock adjusted to reflect a value discount due to restrictions on the Company's ability to sell the investment prior to July 1, 2019. See Note 12 and Note 15 for additional information. Contingent consideration. The Company has a right to receive contingent consideration in conjunction with the South Texas Divestiture of up to $450 million based on future oil and NGL prices during each of the years from 2020 to 2024. The fair value of the contingent consideration is determined using Level 2 inputs based on an option pricing model using quoted future commodity prices from active markets, implied volatility factors and counterparty credit risk assessments. See Note 3 and Note 5 for additional information. 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 and 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. Other assets. During the year ended December 31, 2019, the Company impaired the remaining $13 million of inventory and other property and equipment related to the decommissioning of the Company's Brady, Texas sand mine, as these assets had no remaining future economic value. In addition, the Company recognized a $16 million impairment charge related to pressure pumping assets that had no future benefit to the Company. See Note 16 for additional information. South Texas Divestiture. The Company recorded a deficiency fee obligation and related deficiency fee receivable in conjunction with the South Texas Divestiture. The fair value of the deficiency fee obligation and deficiency fee receivable was determined using Level 3 inputs based on a probability-weighted forecast that considers historical results, market conditions and various development plans to arrive at the estimated present value of the deficiency payments and corresponding receipts. The present value of the future cash payments and expected cash receipts were determined using a 2.9 percent and 3.2 percent discount rate, respectively, based on the estimated timing of future payments and receipts and the Company's counterparty credit risk assessments. See N o te 3 and Note 11 for additional information. Proved oil and gas properties. As a result of the the Company's proved property impairment assessments, the Company recorded noncash impairment charges to reduce the carrying values of its Raton Basin gas field assets during the year ended December 31, 2017. Impairment charges for proved oil and gas properties are recorded as impairment of oil and gas properties in the consolidated statements of operations. The Company calculated the fair value of the Raton Basin gas field assets using a discounted cash flow model. Level 3 inputs used to calculate the discounted future cash flows included management's longer-term commodity price outlooks ("Management's Price Outlooks") and management's outlooks 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 ten percent to determine fair value. The fair value and fair value adjustments for proved properties, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks are as follows: Fair Fair Value Management's Price Outlooks Oil Gas (in millions) Raton Basin March 2017 $ 186 $ (285) $ 53.65 $ 3.00 Sale of Raton Basin assets. In June 2018, the Company recognized impairment charges of $77 million to reduce the carrying value of its Raton Basin gas field assets to the agreed upon sales price for these assets, which were sold in July 2018. The impairment charges included $65 million attributable to proved oil and gas properties and $12 million of other property and equipment. The Company also recorded other divestiture-related charges of $111 million attributable to deficiency charges related to certain firm transportation contracts retained by the Company. The fair value of these contracts was determined using Level 2 inputs, including an annual discount rate of 4.4 percent, to discount the expected future cash flows. See Note 3 for additional information. Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets are as follows: As of December 31, 2019 As of December 31, 2018 Carrying Fair Carrying Fair (in millions) Assets: Cash and cash equivalents: Cash (a) $ 631 $ 631 $ 775 $ 775 Time deposits (a) — — 50 50 Total $ 631 $ 631 $ 825 $ 825 Restricted cash (a) $ 74 $ 74 $ — $ — Short-term investments: Commercial paper (b) $ — $ — $ 53 $ 53 Corporate bonds (c) — — 290 288 Time deposits (b) — — 100 100 Total $ — $ — $ 443 $ 441 Long-term investments: Corporate bonds (c) $ — $ — $ 125 $ 125 Liabilities: Current portion of long-term debt (d) $ 450 $ 451 $ — $ — Long-term debt (d) $ 1,839 $ 1,995 $ 2,284 $ 2,374 ______________________ (a) Fair value approximates carrying value due to the short-term nature of the instruments. (b) Fair value is determined using Level 2 inputs. (c) Fair value is determined using Level 1 inputs. (d) Fair value is determined using Level 2 inputs. The Company's senior notes are quoted but not actively traded on major exchanges; therefore, fair value is based on periodic values as quoted on 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 | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | Derivative Financial Instruments The Company primarily utilizes commodity swap contracts, collar contracts, collar contracts with short puts and basis swap contracts 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. Oil production derivatives. The Company sells its oil production at the lease and the sales contracts governing such oil production are tied directly to, or are correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company also enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. To diversify the oil prices it receives, the Company enters into purchase transactions with third parties and separate sale transactions with third parties for a portion of the Company's oil sales to Gulf Coast refineries or international export markets at prices that are highly correlated with Brent oil prices. As a result, the Company will generally use Brent derivative contracts to manage future oil price volatility. Volumes per day associated with outstanding oil derivative contracts as of December 31, 2019 and the weighted average oil prices for those contracts are as follows: 2020 Year Ending December 31, 2021 First Second Quarter Third Quarter Fourth Quarter Brent swap contracts: Volume per day (Bbl) 3,407 — — — — Price per Bbl $ 60.86 $ — $ — $ — $ — Brent collar contracts with short puts: Volume per day (Bbl) 145,500 135,500 115,500 115,500 7,000 Price per Bbl: Ceiling $ 68.46 $ 68.84 $ 69.78 $ 69.78 $ 65.37 Floor $ 61.64 $ 61.76 $ 62.06 $ 62.06 $ 60.00 Short put $ 53.45 $ 53.48 $ 53.56 $ 53.56 $ 52.00 Brent call contracts sold: Volume per day (Bbl) (a) — — — — 13,000 Price per Bbl: $ — $ — $ — $ — $ 72.10 ______________________ (a) The referenced call contracts were sold in exchange for higher ceiling prices on certain 2020 collar contracts with short puts. NGL production derivatives. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to Mont Belvieu, Texas NGL component product prices. The Company uses derivative contracts to manage the NGL component product price volatility. As of December 31, 2019 the Company did not have any NGL derivative contracts outstanding. Gas production derivatives. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("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. Volumes per day associated with outstanding gas derivative contracts as of December 31, 2019 and the weighted average gas prices for those contracts are as follows: 2020 First Second Quarter Third Quarter Fourth Quarter Swap contracts: Volume per day (MMBtu) (a) — 30,000 30,000 10,109 Price per MMBtu $ — $ 2.41 $ 2.41 $ 2.41 Basis swap contracts: Permian Basin index swap volume per day (MMBtu) (a) (b) — 30,000 30,000 10,109 Price differential ($/MMBtu) $ — $ (1.68) $ (1.68) $ (1.68) ______________________ (a) Between January 1, 2020 and February 18, 2020, the Company entered into additional (i) swap contracts for 10,000 MMBtu per day of November 2020 through March 2021 production at an average fixed price of $2.46 per MMBtu and (ii) basis swap contracts of 10,000 MMbtu per day of November 2020 through March 2021 production with an average price differential of $1.46 per MMBtu. (b) The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the NYMEX index prices used in swap contracts. Interest rate derivatives. The Company had no interest rate derivative contracts outstanding as of December 31, 2019, however, between January 1, 2020 and February 18, 2020, the Company entered into interest rate derivative contracts whereby the Company will receive a fixed five-year average treasury rate of 1.39% on a notional amount of $100 million and a fixed 10-year average treasury rate of 1.57% on a notional amount of $300 million. Contingent consideration. The Company's right to receive contingent consideration in conjunction with the South Texas Divestiture was determined to be a derivative financial instrument that is not designated as a hedging instrument. The contingent consideration of up to $450 million is based on oil and NGL prices during each of the years from 2020 to 2024. See Note 3 and Note 4 for additional information. Fair value. The fair value of derivative financial instruments not designated as hedging instruments is as follows: As of December 31, 2019 Type Consolidated Fair Gross Amounts Net Fair Value (in millions) Assets: Commodity price derivatives Derivatives - current $ 32 $ — $ 32 Contingent consideration Other assets - noncurrent $ 91 $ — $ 91 Liabilities: Commodity price derivatives Derivatives - current $ 12 $ — $ 12 Commodity price derivatives Derivatives - noncurrent $ 8 $ — $ 8 As of December 31, 2018 Type Consolidated Fair Gross Amounts Net Fair Value (in millions) Assets: Commodity price derivatives Derivatives - current $ 59 $ (7) $ 52 Liabilities: Commodity price derivatives Derivatives - current $ 34 $ (7) $ 27 Gains and losses recorded on derivative contracts are as follows: Derivatives Not Designated Location of Gain/(Loss) Year Ended December 31, 2019 2018 2017 (in millions) Commodity price derivatives Derivative gain (loss), net $ 34 $ (292) $ (99) Interest rate derivatives Derivative gain (loss), net $ — $ — $ (1) Contingent consideration Interest and other income $ (45) $ — $ — 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. Net derivative assets (liabilities) associated with the Company's open commodity derivatives by counterparty are as follows: As of December 31, 2019 (in millions) Wells Fargo Bank $ 15 JP Morgan Chase 5 Scotia Bank 3 Royal Bank of Canada 1 Bank of Montreal (1) J Aron & Company (1) Merrill Lynch (1) Nextera Energy Power Marketing (2) Citibank (7) $ 12 See Note 2 |
Long-term Debt and Interest Exp
Long-term Debt and Interest Expense | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Long-term Debt and Interest Expense | Long-term Debt and Interest Expense The components of long-term debt, including the effects of issuance costs and issuance discounts, are as follows: As of December 31, 2019 2018 (in millions) Outstanding debt principal balances: 7.50% senior notes due 2020 $ 450 $ 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 2,300 2,300 Issuance costs and discounts (11) (16) Total debt 2,289 2,284 Less current portion of long-term debt 450 — Long-term debt $ 1,839 $ 2,284 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 (the "Syndicate") and has aggregate loan commitments of $1.5 billion. The Credit Facility has a maturity date of October 2023. As of December 31, 2019, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants. Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Revolving loans represent loans made ratably by the Syndicate in accordance with their respective commitments under the Credit Facility and bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.25 percent based upon the Company's debt rating or (b) a base Eurodollar rate, plus a margin (the "Applicable Margin"), which is currently 1.25 percent and is also determined by the Company's debt rating. Swing line loans represent loans made by a subset of the lenders in the Syndicate and may not exceed $150 million. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.15 percent). Borrowings under the Credit Facility are general unsecured obligations. The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed 0.65 to 1.0. As of December 31, 2019, the Company was in compliance with all of its debt covenants. Senior notes. The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually. Principal payments scheduled to be made on the Company's long-term debt are as follows (in millions): 2020 $ 450 2021 $ 500 2022 $ 600 2023 $ — 2024 $ — Thereafter $ 750 Interest expense activity is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Cash payments for interest $ 117 $ 133 $ 164 Accretion of finance lease 4 — — Amortization of issuance discounts 1 1 1 Amortization of capitalized loan fees 4 4 4 Net changes in accruals — (6) (9) Interest incurred 126 132 160 Less capitalized interest (5) (6) (7) Total interest expense $ 121 $ 126 $ 153 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2019 | |
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. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. Asset retirement obligations activity is as follows: Year Ended December 31, 2019 2018 (in millions) Beginning asset retirement obligations $ 183 $ 271 New wells placed on production 5 1 Changes in estimates (a) 82 16 Dispositions (37) (89) Liabilities settled (52) (30) Accretion of discount 10 14 Ending asset retirement obligations 191 183 Less current portion of asset retirement obligations 73 25 Asset retirement obligations, long term $ 118 $ 158 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The 2019 change in estimate is primarily due to accelerating the forecasted timing of abandoning certain of the Company's vertical oil and |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | Leases As of December 31, 2018, the Company was the deemed owner (for accounting purposes) of the Company's new corporate headquarters (the "Hidden Ridge Building") during the construction period and accounted for this deemed ownership following the build-to-suit accounting guidance under ASC 840. On January 1, 2019, upon implementation of ASC 842, the Company was no longer considered the deemed owner of the Hidden Ridge Building and the Company derecognized the build-to-suit asset of $217 million and liability of $219 million. The Company had a variable interest in the entity responsible for constructing the Hidden Ridge Building. The Company was not the primary beneficiary of the variable interest entity and only had a profit sharing interest after certain economic returns were achieved. The Company had no exposure to the variable interest entity's losses or future liabilities, if any. In December 2019, the Company sold its interest in the variable interest entity for net cash proceeds of $56 million and recognized a net gain on the sale of the building of $56 million, which is recorded in interest and other in the consolidated statement of operations. The Company has no continuing involvement in entity subsequent to the sale. See Note 15 for additional information. The Company recognized a finance lease upon commencement of the Hidden Ridge Building lease in October 2019, the balances of which are as follows: Consolidated Balance Sheet Location As of December 31, 2019 (in millions) Finance lease right-of-use asset Other property and equipment, net $ 556 Finance lease liability Other liabilities - current $ 16 Finance lease liability Other liabilities - noncurrent $ 556 In November 2019, the Company recorded accelerated amortization of $28 million in other expense in the consolidated statements of operations to fully amortize the remaining operating lease right-of-use asset associated with its former corporate headquarters. As of December 31, 2019, the consolidated balance sheet includes $27 million of operating lease liabilities related to its former corporate headquarters. See Note 16 for additional information. The components of lease costs, including amounts recoverable from joint operating partners, are as follows: Year Ended December 31, 2019 (in millions) Finance lease cost: Amortization of right-of-use asset (a) $ 7 Interest on lease liability 4 Operating lease cost (b) 200 Short-term lease cost (c) 33 Variable lease cost (d) 73 Total lease cost $ 317 _____________________ (a) Represents straight-line rent cost associated with the Company's finance lease right-of-use asset. (b) Represents straight-line rent cost associated with the Company's operating lease right-of-use assets. (c) Represents costs associated with short-term leases (those with a contractual term of 12 months or less) that are not included in the consolidated balance sheets. (d) Variable lease costs are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and gas properties. For the year ended December 31, 2019, cash paid of $103 million for operating, short-term and variable leases and $4 million for finance leases is included in net cash provided by operating activities and $1 million of finance lease principal payments is included in net cash used in financing activities in the consolidated statements of cash flows. For the same period, the Company also incurred operating and variable lease costs associated with drilling operations of $180 million, which is capitalized as additions to oil and gas properties and is included in investing cash flows in the consolidated statements of cash flows. The changes in lease liabilities are as follows: Year Ended December 31, 2019 Operating Finance (in millions) Beginning lease liabilities (a) $ 325 $ — Liabilities assumed in exchange for new right-of-use assets (b) 142 573 Contract modifications (c) 4 — Dispositions (1) — Liabilities settled (177) (5) Accretion of discount (d) 13 4 Ending lease liabilities (e) $ 306 $ 572 ______________________ (a) Represents January 1, 2019 balance upon adoption of ASC 842. (b) Represents noncash leasing activity. The weighted-average discount rate used in 2019 to determine the present value of future operating and finance lease payments is 3.3 percent and 3.0 percent, respectively. (c) Represents changes in lease liabilities due to modifications of original contract terms. (d) Represents imputed interest on discounted future cash payments. (e) As of December 31, 2019, the weighted-average remaining lease term of the Company's operating and finance leases is three Maturities of lease obligations are as follows: As of December 31, 2019 Operating Finance (in millions) 2020 $ 149 $ 33 2021 92 33 2022 47 34 2023 13 35 2024 8 35 Thereafter 18 603 Total lease payments 327 773 Less present value discount (21) (201) Present value of lease liabilities $ 306 $ 572 At December 31, 2019, the Company has commitments for additional operating leases of approximately $38 million expected to commence in 2020 with lease terms of 4 years. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $15 million. Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation. Legal actions. The Company is 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 these proceedings and claims will not have a material adverse effect on the Company's consolidated 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. Environmental. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs. 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 preclosing matters, including matters of litigation, environmental contingencies, royalty and income taxes. Also associated with its divestiture transactions, the Company has issued and received guarantees to facilitate the transfer of contractual obligations, such as firm transportation agreements or gathering and processing arrangements. The Company does not recognize a liability if the fair value of the obligation is immaterial or the likelihood of making payments under these guarantees is remote. South Texas Divestiture. In conjunction with the South Texas Divestiture, the Company transferred its long-term midstream agreements and associated MVC's to the buyer. However, the Company retained the obligation to pay 100 percent of any deficiency fees associated with the MVC's from January 2019 through July 2022. The buyer is required to reimburse the Company for 18 percent of the deficiency fees paid by the Company from January 2019 through July 2022; such reimbursement will be paid by the buyer in installments beginning in 2023 through 2025. Assuming 100 percent of the MVC's are paid as deficiency fees, the maximum amount of future payments for this obligation would be approximately $620 million as of December 31, 2019. The Company's estimated deficiency fee obligation as of December 31, 2019 is $394 million, of which $153 million is included in other current liabilities in the consolidated balance sheets. The corresponding estimated deficiency fee receivable from the buyer of $69 million is included in noncurrent other assets in the consolidated balance sheets. The Company has received credit support for the deficiency fee receivable and contingent consideration of up to $325 million. Raton transportation commitments. In July 2018, the Company completed the sale of its gas field assets in the Raton Basin to an unaffiliated third party and transferred certain gas transportation commitments, which extend through 2032, to the buyer for which the Company has provided a guarantee. Assuming 100 percent of the remaining commitments are paid by the Company under its guarantee, the maximum amount of future payments would be approximately $90 million as of December 31, 2019. The Company has received credit support for the commitments of up to $50 million. During 2019, the Company paid $12 million in gas transportation fees associated with the transferred commitment and was fully reimbursed. West Eagle Ford Shale commitments. In April 2018, the Company completed the sale of its West Eagle Ford Shale gas and liquids field to an unaffiliated third party and transferred certain gas and liquids transportation commitments, which extend through 2022, to the buyer for which the Company has provided a guarantee. Assuming 100 percent of the remaining commitments are paid by the Company under its guarantee, the maximum amount of future payments would be approximately $20 million as of December 31, 2019. The Company has received credit support for the commitments of up to $19 million. Certain contractual obligations were retained by the Company after the South Texas Divestiture, the divestiture of the Company's gas field assets in the Raton Basin, the divestiture of the Company's pressure pumping assets and the decommissioning of the Company's sand mine operations in Brady, Texas. These contracts were primarily related to firm transportation and storage agreements in which the Company is unlikely to realize any benefit. The estimated obligations are included in other current or noncurrent liabilities in the consolidated balance sheets. The changes in contract obligations are as follows: Year Ended December 31, 2019 (in millions) Beginning contract obligations $111 Additions (a) 400 Liabilities settled (51) Accretion of discount 10 Changes in estimate (b) (2) Ending contract obligations $ 468 ______________________ (a) Additions include a $348 million deficiency fee obligation related to the South Texas Divestiture, $49 million of South Texas accrued deficiency fees from January 2019 through April 2019, $2 million of sand storage deficiencies associated with the sale of pressure pumping assets and $1 million related to sand mine decommissioning. (b) Represents the difference between estimated and actual liabilities settled. Texas Commission on Environmental Quality ("TCEQ") enforcement action. The TCEQ pursued an enforcement action against the Company, including monetary sanctions, due to various alleged air emissions occurring during the Company's ownership in 2016 and 2017 of the Fain gas plant in the West Panhandle region of Texas, which was sold during 2018. Effective as of October 25, 2019, the Company and the TCEQ entered into an agreed order that provides for the Company making a final penalty payment of $188,400. By letter dated November 1, 2019, the Company was informed by the TCEQ that it had fulfilled the requirements of the order. Firm commitments. The Company from time to time enters into, and is 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, fractionation and storage. These commitments are normal and customary for the Company's business activities. Certain future minimum gathering, processing, transportation, fractionation and storage fees are based upon rates and tariffs that are subject to change over the terms of the commitments. Minimum firm commitments are as follows: As of December 31, 2019 Firm Commitments (in millions) 2020 $ 532 2021 534 2022 471 2023 407 2024 412 Thereafter 1,784 Total minimum firm commitments $ 4,140 Gas delivery commitments. The Company has contracts that require delivery of fixed volumes of gas. The Company intends to fulfill its short-term and long-term obligations with production or from purchases of third party volumes. Delivery commitments for gas are as follows: As of December 31, 2019 (MMBtu per day) 2020 196,557 2021 175,000 2022 175,000 2023 175,000 2024 150,137 Thereafter 156,164 Total gas delivery commitments 1,027,858 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions In December 2018, the Company completed the sale of its pressure pumping assets to ProPetro in exchange for 16.6 million shares of ProPetro common stock and $110 million of cash that was received during the first quarter of 2019. ProPetro is considered a related party as the shares received represent 16 percent of ProPetro's outstanding common stock. In addition to the sale of equipment and related facilities, the Company entered into a long-term agreement with ProPetro for it to provide pressure pumping and related services. The costs of these services are capitalized in oil and gas properties as incurred. See Note 3 for additional information. In October 2019, Phillip A. Gobe, a nonemployee member of the Company's board of directors, was appointed by the board of directors of ProPetro to serve as its Executive Chairman. Mark S. Berg, the Company's Executive Vice President Corporate/Vertically Integrated Operations, continues to serve as a member of the ProPetro board of directors under the Company's right to designate a director to the board of directors of ProPetro so long as the Company owns five percent or more of ProPetro's outstanding common stock. Transactions and balances with ProPetro are as follows: Year Ended December 31, 2019 2018 (in millions) Pressure pumping related services charges (a) $ 461 $ 111 ____________________ (a) Represents pressure pumping and related services provided by ProPetro as part of a long-term agreement. The 2018 amount represents charges associated with the pressure pumping and related services performed by ProPetro in the normal course of business prior to the Company's sale of its pressure pumping assets to ProPetro. As of December 31, 2019 2018 (in millions) Accounts receivable - due from affiliate (a) $ 3 $ 119 Accounts payable - due to affiliate (b) $ 88 $ 37 ____________________ (a) Represents employee-related charges to be reimbursed by ProPetro. The balance as of December 31, 2018 also includes $110 million of cash consideration received during the first quarter of 2019. (b) Represents pressure pumping and related services provided by ProPetro as part of a long-term agreement. The balance as of December 31, 2018 represents invoices associated with the pressure pumping and related services performed by ProPetro in the normal course of business prior to the Company's sale of its pressure pumping assets to ProPetro. |
Major Customer
Major Customer | 12 Months Ended |
Dec. 31, 2019 | |
Risks and Uncertainties [Abstract] | |
Major Customers | Major Customers Purchasers of the Company's oil, NGL and gas production that individually accounted for ten percent or more of the Company's oil and gas revenues in at least one of the three years ended December 31, 2019 are as follows: Year Ended December 31, 2019 2018 2017 Sunoco Logistics Partners L.P. 33 % 28 % 21 % Occidental Energy Marketing Inc. 20 % 17 % 16 % Plains Marketing L.P. 13 % 15 % 14 % Enterprise Products Partners L.P. 1 % 6 % 11 % The loss of any of these major purchasers of oil, NGL and gas production could have a material adverse effect on the ability of the Company to produce and sell its oil, NGL and gas production. Purchasers of the Company's purchased oil and gas that individually accounted for ten percent or more of the Company's sales of purchased oil and gas in at least one of the three years ended December 31, 2019 are as follows: Year Ended December 31, 2019 2018 2017 Occidental Energy Marketing Inc. 30 % 34 % 39 % BP Energy 5 % 9 % 11 % Exxon Mobil 4 % 5 % 11 % Valero Marketing and Supply Company 2 % 9 % 14 % The loss of any of these major purchasers of purchased oil and gas would not be expected to have an adverse effect on the ability of the Company to sell commodities it purchases from third parties. |
Revenue Recognition (Notes)
Revenue Recognition (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue Recognition [Abstract] | |
Revenue Recognition | Revenue Recognition Disaggregated revenue from contracts with purchasers. Revenues on sales of oil, NGL, 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, NGL and gas generally fluctuate based on the relevant market index rates. Disaggregated revenue from contracts with purchasers by product type is as follows: Year Ended December 31, 2019 2018 (in millions) Oil sales $ 4,168 $ 3,991 NGL sales 510 695 Gas sales 238 305 Total oil and gas sales 4,916 4,991 Sales of purchased oil 4,726 4,339 Sales of purchased gas 29 49 Total sales of purchased oil and gas 4,755 4,388 Total revenue from contracts with purchasers $ 9,671 $ 9,379 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, NGL and gas and sales of purchased oil and gas may not be received for 30 to 60 days after the date the volumes are delivered, and as a result, the Company is required to estimate the amount of volumes 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. As of December 31, 2019 and 2018, the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $968 million and $646 million, respectively. |
Interest And Other Income
Interest And Other Income | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
Interest and Other Income | Interest and Other Income The components of interest and other income are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Gain on sale of variable interest ( Note 10 ) $ 56 $ — $ — Interest income 17 29 32 Deferred compensation plan income (loss) 15 (2) 4 Investment in affiliate valuation adjustment ( Note 4 ) 15 — — Severance and sales tax refunds 6 1 13 Seismic data sales 5 5 — Contingent consideration valuation adjustment ( Note 4 ) (45) — — Other 7 5 4 Total interest and other income $ 76 $ 38 $ 53 |
Other Expense
Other Expense | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
Other Expense | Other Expense The components of other expense are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Restructuring charges (a) $ 159 $ — $ — Transportation commitment charges (b) 74 161 167 Corporate headquarters move-related costs (c) 41 — — Asset impairment (d) 38 11 2 Asset divestiture-related charges (e) 25 170 — Idle drilling and well service equipment charges (f) 25 — — Sand mine decommissioning-related charges (g) 23 443 — Legal and environmental charges 19 21 20 Vertical integration services loss (h) 15 2 17 Other 29 41 38 Total other expense $ 448 $ 849 $ 244 ____________________ (a) Represents employee-related charges associated with the Corporate Restructuring Program. See Note 3 and Note 8 for additional information. (b) Primarily represents firm transportation charges on excess pipeline capacity commitments. (c) Represents costs associated with relocating to the Hidden Ridge Building, including $28 million of accelerated amortization of the operating lease right-of-use asset associated with the Company's former corporate headquarters and$13 million of exit and move-related costs. (d) Primarily represents inventory and other asset impairment charges associated with the decommissioning of the Company's Brady, Texas sand mine and the divestiture of the Company's pumping services assets. See Note 3 and Note 4 for additional information. (e) Primarily represents employee-related charges and contract termination charges associated with the Company's divestitures. See Note 3 for additional information. (f) Primarily represents expenses attributable to idle frac fleet and drilling rig fees that are not chargeable to joint operations. (g) Represents accelerated depreciation related to the decommission of the Company's Brady, Texas sand mine. See Note 3 for additional information. (h) Primarily represents net margins (attributable to third party working interest owners) that result from Company-provided vertically integrated services, 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 years ended December 31, 2019, 2018 and 2017, these vertical integration net margins included $51 million, $128 million and $140 million of gross vertical integration revenues, respectively, and $66 million, $130 million and $157 million of total vertical integration costs and expenses, respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Company and its eligible subsidiaries file a consolidated U.S. federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated U.S. federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by U.S. federal, state, local and foreign taxing authorities. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and based on that information, along with other data, reassesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the U.S. federal, state, local and foreign tax jurisdictions will be utilized prior to their expiration. Enactment of the Tax Cuts and Jobs Act. On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the "Tax Reform Legislation"), which introduced significant changes to the U.S. federal income tax law. The changes that most impact the Company include: • A reduction in the federal corporate income tax rate from 35 percent to 21 percent. The rate reduction is effective for the Company as of January 1, 2018. The application of the rate change on the Company's deferred tax liabilities resulted in a $625 million income tax benefit to the Company during 2017. • Repeal of the corporate alternative minimum tax ("AMT"). The Tax Reform Legislation provides that existing AMT credit carryovers are refundable beginning in 2018. As of December 31, 2019, the Company had AMT credit carryovers of $12 million that are expected to be fully refunded by 2022. • The Tax Reform Legislation preserves the deductibility of intangible drilling costs and provides for 100 percent bonus depreciation on personal tangible property expenditures through 2022. The bonus depreciation percentage will be phased out from 2023 through 2026. The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, that are not expected to materially affect Pioneer. The ultimate impact of the Tax Reform Legislation may differ from the Company's estimates due to changes in the interpretations and assumptions made by the Company as well as additional regulatory guidance that may be issued. Uncertain tax positions . The Company has unrecognized tax benefits ("UTBs") resulting from research and experimental expenditures related to horizontal drilling and completion innovations. In December 2019, the Company and the taxing authorities effectively settled the uncertain tax position for the 2012-2015 tax years. The Company believes it will substantially resolve the uncertainties associated with the remaining UTB within the next twelve months. Unrecognized tax benefit activity is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Beginning unrecognized tax benefits $ 141 $ 124 $ 112 Current year additions — 17 12 Effectively settled tax positions (102) — — Ending unrecognized tax benefits $ 39 $ 141 $ 124 Other tax matters. Net tax refunds are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Tax refunds, net $ (5) $ — $ — The Company files income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. As of December 31, 2019, there are no proposed adjustments in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The earliest open years in the Company's key jurisdictions are as follows: U.S. federal 2012 Various U.S. states 2013 Income tax (provision) benefit is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Current: U.S. federal $ 8 $ — $ 5 U.S. state (3) (2) — Current income tax (provision) benefit 5 (2) 5 Deferred: U.S. federal (224) (258) 526 U.S. state (12) (16) (7) Deferred income tax (provision) benefit (236) (274) 519 Income tax (provision) benefit $ (231) $ (276) $ 524 The effective tax rate for income (loss) is reconciled to the United States federal statutory rate as follows: Year Ended December 31, 2019 2018 2017 (in millions, except percentages) Income before income taxes $ 987 $ 1,251 $ 309 Net loss attributable to noncontrolling interests — 3 — Income attributable to common stockholders before income taxes $ 987 $ 1,254 $ 309 Federal statutory income tax rate 21 % 21 % 35 % Provision for federal income taxes at the statutory rate (207) (263) (108) State income tax provision (net of federal tax) (12) (12) (4) Change in federal income tax rate (a) — — 625 Other (12) (1) 11 Income tax (provision) benefit $ (231) $ (276) $ 524 Effective income tax rate, excluding net loss attributable to noncontrolling interests 23 % 22 % (170 %) ____________________ (a) During 2017, the Company recorded a benefit of $625 million as a result of the Tax Reform Legislation that reduced the federal income tax rate beginning in 2018. Significant components of deferred tax assets and deferred tax liabilities are as follows: As of December 31, 2019 2018 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 996 $ 882 Credit carryforwards (b) 101 111 Deferred interest carryforward (c) 43 — Asset retirement obligations 41 40 Incentive plans 40 48 Net deferred hedge losses — 11 South Texas Divestiture 75 — Lease deferred tax assets 191 — Other 47 51 Deferred tax assets 1,534 1,143 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (2,628) (2,248) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes and differences in lease right of use assets (189) (47) Net deferred hedge gains (4) — South Texas Divestiture (35) — Lease deferred tax liabilities (61) — Other (6) — Deferred tax liabilities (2,923) (2,295) Net deferred tax liability $ (1,389) $ (1,152) ____________________ (a) Net operating loss carryforwards as of December 31, 2019, consist of $5.0 billion of U.S. federal NOLs, which expire between 2032 and 2039 and $177 million of Colorado NOLs that begin to expire in 2027. The Colorado NOL has a fully offsetting valuation allowance. (b) Credit carryforwards as of December 31, 2019, consist of $12 million of U.S. federal minimum tax credits and U.S. federal and Texas credits for research activities of $88 million and $1 million, respectively. The U.S. federal and state research credits as of December 31, 2019 exclude $39 million of unrecognized tax benefits. (c) The deferred interest carryforward represents disallowed interest deductions under IRC Section 163(j) (Limitation on Deduction for Interest on Certain Indebtedness) for the current and prior years. The disallowed interest can be carried forward indefinitely and utilized in future years. |
Net Income Per Share Attributab
Net Income Per Share Attributable To Common Stockholders | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Net Income Per Share Attributable To Common Stockholders | Net Income Per ShareThe Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. Diluted net income per share attributable to common stockholders is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The components of basic and diluted net income per share attributable to common stockholders are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Net income attributable to common stockholders $ 756 $ 978 $ 833 Participating share based earnings (a) (3) (5) (6) Basic and diluted net income attributable to common stockholders $ 753 $ 973 $ 827 Basic and diluted weighted average shares outstanding 167 171 170 ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so. Stock repurchase program . In December 2018, the Company's board of directors authorized a common stock repurchase program that allows the Company to repurchase up to $2 billion of its common stock. Under this stock repurchase program, the Company may repurchase shares from time to time at management's discretion in accordance with applicable securities laws. In addition, the Company may repurchase shares pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Act of 1934, which would permit the Company to repurchase shares at times that may otherwise be prohibited under the Company's insider trading policy. The stock repurchase program has no time limit, may be modified, suspended or terminated at any time by the board of directors. Shares repurchased are as follows: Year Ended December 31, 2019 2018 (a) 2017 (in millions) Shares repurchased $ 622 $ 149 $ — ______________________ (a) During 2018, the Company repurchased $22 million of common stock pursuant to a previously authorized common stock repurchase program and $127 million of common stock pursuant to the current authorized common stock repurchase program. As of December 31, 2019, $1.3 billion remains available for use to repurchase shares under the Company's common stock repurchase program. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events Dividends. On February 19, 2020, the board of directors declared a quarterly cash dividend of $0.55 per share on the Company's outstanding common stock, payable April 14, 2020 to stockholders of record at the close of business on March 31, 2020. Senior Notes. The Company's outstanding 7.50% Senior Notes matured on January 15, 2020. The Company funded the payment of the $450 million principal balance with cash on hand. See Note 7 for additional information. |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Principles of consolidation | Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. |
Reclassifications | Certain reclassifications have been made to prior period amounts to conform to the current period's presentation. |
Use of estimates in the preparation of financial statements | Use of estimates in the preparation of financial statements. Preparation of the Company's consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of proved and unproved oil and gas properties and goodwill, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized. |
Cash and cash equivalents | Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less. Restricted cash. The Company's restricted cash includes funds held in escrow to cover future deficiency fee payments in connection with the Company's 2019 sale of its Eagle Ford assets and other remaining assets in South Texas (the "South Texas Divestiture"). Beginning in 2021, the required escrow balance declines and, to the extent there is any remaining balance after the payment of deficiency fees, the balance will become unrestricted and revert to the Company on March 31, 2023. Interest income related to restricted cash is recorded in interest and other income in the consolidated statements of operations. |
Investments | Investments. 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. 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 included in short-term investments or long-term investments in the consolidated balance sheets based on their maturity dates |
Accounts receivable | Accounts receivable. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers. T he Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. The Company's allowance for doubtful accounts totaled $2 million for each of the years ended December 31, 2019 and 2018. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which |
Inventories | Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas maintenance materials and repair parts, water, chemicals and other operating supplies. The materials and supplies inventory is primarily acquired for use in future drilling and production operations or repair operations and is carried at the lower of cost or market, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories included in the Company's consolidated balance sheets and are recorded in other expense in the consolidated statements of operations. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, NGLs and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations. |
Oil and gas properties | Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note 6 for additional information. As of December 31, 2019, the Company owns interests in 11 gas processing plants, including the related gathering systems. The Company's ownership interests in the gas processing plants are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. The operators of the plants process the Company's and third-party gas volumes for a fee. The Company's share of revenues and expenses derived from volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Revenues generated from the processing plants and treating facilities for the years ended December 31, 2019, 2018 and 2017 were $90 million, $78 million and $60 million, respectively. Expenses attributable to the processing plants and treating facilities for the same respective periods were $43 million, $36 million and $26 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Impairment charges for proved oil and gas properties are recorded in impairment of oil and gas properties in the consolidated statements of operations. See Note 4 for additional information. |
Goodwill | Goodwill. Goodwill is assessed for impairment whenever it is likely that events or circumstances indicate the carrying value of a reporting unit exceeds its fair value, but no less often than annually. An impairment charge is recorded for the amount by which the carrying amount exceeds the fair value of a reporting unit in the period it is determined to be impaired. The Company performed its annual qualitative assessment of goodwill during the third quarter of 2019 to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount. Based on the results of the assessment, the Company determined it was not likely that the carrying value of the Company's reporting unit exceeded its fair value. |
Other property and equipment, net | Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $382 million and $854 million as of December 31, 2019 and 2018, respectively, are as follows: As of December 31, 2019 2018 (in millions) Land and buildings (a) $ 877 $ 380 Water infrastructure (b) 404 343 Construction-in-progress and capitalized interest (c) 152 311 Information technology 120 143 Transport and field equipment (d) 35 50 Furniture and fixtures 28 15 Proved and unproved sand properties (e) 16 36 Leasehold improvements — 13 Total other property and equipment, net $ 1,632 $ 1,291 ____________________ (a) Includes land, buildings, any related improvements to land and buildings, and a finance lease entered into by the Company for its new corporate headquarters in Irving, Texas. See Note 10 for additional information. (b) Includes costs for pipeline infrastructure and water supply wells. (c) Includes capitalized costs and capitalized interest on other property and equipment not yet placed in service. (d) Includes vehicles and well servicing equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, construction equipment and fishing tools, that are used on Company-operated properties. (e) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years. Equipment, vehicles, furniture and fixtures and information technology assets are generally depreciated over three three The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. |
Leases | Leases. The Company enters into leases for drilling rigs, storage tanks, equipment and buildings and recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. See Note 10 for additional information. |
Asset retirement obligations | Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. The Company includes the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the consolidated balance sheets and expenditures are included as cash used in operating activities in the consolidated statements of cash flows. See Note 9 for additional information. |
Treasury stock | Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. |
Revenue recognition | Revenue recognition. On January 1, 2018, the Company adopted Accounting Standards Codification ("ASC") 606, "Revenue from Contracts with Customers," ("ASC 606") using the modified retrospective transition method. The adoption did not require an adjustment to retained earnings as there was no material change to the timing or pattern of revenue recognition due to the adoption of ASC 606. The Company recognizes revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. 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 the sales revenue when (i) control/custody transfers to the purchaser at the wellhead and (ii) the net price is fixed and determinable. NGL and gas sales . Under the majority of the Company’s gas processing contracts, gas is delivered to a midstream processing entity and the Company elects to take residue gas and NGLs in-kind at the tailgate. The Company recognizes revenue when the products are delivered (custody transfer) to the ultimate third-party purchaser at a contractually agreed-upon delivery point at a specified index price. Sales of purchased oil and gas. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate oil ("WTI") and gas sales to Gulf Coast refineries and LNG facilities, international export markets and to satisfy unused gas 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 both the risk and rewards of ownership, including credit risk, of the commodities purchased and the responsibility to deliver the commodities sold. Transportation costs associated with these transactions are presented on a net basis in purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are recorded as other expense in the consolidated statements of operations. See Note 14 and Note 16 for additional information. |
Derivatives | Derivatives. All of the Company's derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. 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 Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. |
Income taxes | Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date. The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all of the deferred tax assets will not be realized. 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. 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. See Note 17 for additional information. |
Stock-based compensation | Stock-based compensation. Stock-based compensation expense for restricted stock, restricted stock units and performance units expected to be settled in the Company's common stock ("Equity Awards") is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of estimated forfeitures, on a straight line basis over the requisite service period of the respective award. The fair value of Equity Awards, except performance unit awards, is determined on the grant date or modification date, as applicable, using the prior day's closing stock price. The fair value of performance unit awards is determined using the Monte Carlo simulation model. Equity Awards are net settled by withholding shares of the Company's common stock to satisfy income tax withholding payments due upon vesting. Remaining vested shares are remitted to individual employee brokerage accounts. Shares to be delivered upon vesting of Equity Awards are made available from authorized, but unissued shares or shares held as treasury stock. Restricted stock awards expected to be settled in cash on their vesting dates, rather than in common stock ("Liability Awards"), are included in accounts payable – due to affiliates in the consolidated balance sheets. The fair value of Liability Awards is determined on the grant date using the prior day's closing stock price. The Company recognizes the value of Liability Awards on a straight line basis over the requisite service period of the award. Liability Awards are marked to fair value as of each balance sheet date using the closing stock price on the balance sheet date. Changes in the fair value of Liability Awards are recorded as increases or decreases to stock-based compensation expense. |
Segments | Segments. Based upon how the Company is organized and managed, the Company has one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. |
New accounting pronouncements | ew accounting standards. In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" ("ASC 842"), which supersedes the lease recognition requirements in ASC 840, "Leases" ("ASC 840"), and requires lessees to recognize lease assets and lease liabilities for those leases previously classified as operating leases. The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU 2018-11, "Leases (Topic 842) Targeted Improvements," in which ASC 842 is applied at the adoption date, while the comparative periods will continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. ASC 842 allowed for the election of certain practical expedients at adoption to ease the burden of implementation. At implementation, the Company elected to (i) maintain the historical lease classification for leases prior to January 1, 2019, (ii) maintain the historical accounting treatment for land easements that existed at adoption, (iii) use historical practices in assessing the lease term of existing contracts at adoption, (iv) combine lease and non-lease components of a contract as a single lease and (v) not record short-term leases in the consolidated balance sheet, all in accordance with ASC 842. The adoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on the Company's cash flows. The Company did not record a change to its opening retained earnings as of January 1, 2019, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842. New accounting pronouncements. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. Entities will use the modified retrospective approach to apply the standard's provisions and record a cumulative-effect adjustment to retained earnings for additional receivable loss allowances, if any, as of the beginning of the first reporting period in which the guidance is adopted. While the Company continues to prepare for the adoption of ASU 2016-13 on January 1, 2020, the Company does not expect that it will have a material impact on its consolidated financial statements. |
Net income (loss) per share | The Company's basic net income per share attributable to common stockholders is computed as (i)Â net income attributable to common stockholders, (ii)Â less participating share- and unit-based basic earnings (iii)Â divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i)Â basic net income attributable to common stockholders, (ii)Â plus diluted adjustments to participating undistributed earnings (iii)Â divided by weighted average diluted shares outstanding. Diluted net income per share attributable to common stockholders is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Schedule of materials and supplies and commodity inventories | The components of inventories are as follows: As of December 31, 2019 2018 (in millions) Materials and supplies (a) $ 75 $ 128 Commodities 130 114 Total inventories $ 205 $ 242 ____________________ |
Schedule of other property and equipment, net | Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $382 million and $854 million as of December 31, 2019 and 2018, respectively, are as follows: As of December 31, 2019 2018 (in millions) Land and buildings (a) $ 877 $ 380 Water infrastructure (b) 404 343 Construction-in-progress and capitalized interest (c) 152 311 Information technology 120 143 Transport and field equipment (d) 35 50 Furniture and fixtures 28 15 Proved and unproved sand properties (e) 16 36 Leasehold improvements — 13 Total other property and equipment, net $ 1,632 $ 1,291 ____________________ (a) Includes land, buildings, any related improvements to land and buildings, and a finance lease entered into by the Company for its new corporate headquarters in Irving, Texas. See Note 10 for additional information. (b) Includes costs for pipeline infrastructure and water supply wells. (c) Includes capitalized costs and capitalized interest on other property and equipment not yet placed in service. (d) Includes vehicles and well servicing equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, construction equipment and fishing tools, that are used on Company-operated properties. (e) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. |
Acquisitions and Divestitures A
Acquisitions and Divestitures Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Schedule of Divestiture-related Charges | Year Ended December 31, 2019 2018 (in millions) Beginning employee-related obligations $ 27 $ — Additions (a) 155 39 Cash payments (176) (12) Ending employee-related obligations $ 6 $ 27 ____________________ (a) Additions for the year ended December 31, 2019 primarily include $133 million of charges related to the Corporate Restructuring Program and $19 million of charges related primarily to the South Texas Divestiture. For the year ended December 31, 2018, additions primarily relate to the 2018 divestitures. |
Disclosures About Fair Value _2
Disclosures About Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Assets and liabilities that are measured at fair value | Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis are as follows: As of December 31, 2019 Fair Value Measurements Quoted Prices in Significant Other Significant Total (in millions) Assets: Commodity derivatives $ — $ 32 $ — $ 32 Deferred compensation plan assets 85 — — 85 Investment in affiliate 187 — — 187 Contingent consideration — 91 — 91 Total assets 272 123 — 395 Liabilities: Commodity derivatives — 20 — 20 Total recurring fair value measurements $ 272 $ 103 $ — $ 375 As of December 31, 2018 Fair Value Measurements Quoted Prices in Significant Other Significant Total (in millions) Assets: Commodity derivatives $ — $ 52 $ — $ 52 Deferred compensation plan assets 82 — — 82 Investment in affiliate — 172 — 172 Total assets 82 224 — 306 Liabilities: Commodity derivatives — 27 — 27 Total recurring fair value measurements $ 82 $ 197 $ — $ 279 |
Fair value and fair value adjustments, nonrecurring | The fair value and fair value adjustments for proved properties, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks are as follows: Fair Fair Value Management's Price Outlooks Oil Gas (in millions) Raton Basin March 2017 $ 186 $ (285) $ 53.65 $ 3.00 |
Carrying values and fair values of financial instruments not carried at fair value | Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets are as follows: As of December 31, 2019 As of December 31, 2018 Carrying Fair Carrying Fair (in millions) Assets: Cash and cash equivalents: Cash (a) $ 631 $ 631 $ 775 $ 775 Time deposits (a) — — 50 50 Total $ 631 $ 631 $ 825 $ 825 Restricted cash (a) $ 74 $ 74 $ — $ — Short-term investments: Commercial paper (b) $ — $ — $ 53 $ 53 Corporate bonds (c) — — 290 288 Time deposits (b) — — 100 100 Total $ — $ — $ 443 $ 441 Long-term investments: Corporate bonds (c) $ — $ — $ 125 $ 125 Liabilities: Current portion of long-term debt (d) $ 450 $ 451 $ — $ — Long-term debt (d) $ 1,839 $ 1,995 $ 2,284 $ 2,374 ______________________ (a) Fair value approximates carrying value due to the short-term nature of the instruments. (b) Fair value is determined using Level 2 inputs. (c) Fair value is determined using Level 1 inputs. (d) Fair value is determined using Level 2 inputs. The Company's senior notes are quoted but not actively traded on major exchanges; therefore, fair value is based on periodic values as quoted on major exchanges. |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Gas Volume And Weighted Average Price | Volumes per day associated with outstanding gas derivative contracts as of December 31, 2019 and the weighted average gas prices for those contracts are as follows: 2020 First Second Quarter Third Quarter Fourth Quarter Swap contracts: Volume per day (MMBtu) (a) — 30,000 30,000 10,109 Price per MMBtu $ — $ 2.41 $ 2.41 $ 2.41 Basis swap contracts: Permian Basin index swap volume per day (MMBtu) (a) (b) — 30,000 30,000 10,109 Price differential ($/MMBtu) $ — $ (1.68) $ (1.68) $ (1.68) ______________________ (a) Between January 1, 2020 and February 18, 2020, the Company entered into additional (i) swap contracts for 10,000 MMBtu per day of November 2020 through March 2021 production at an average fixed price of $2.46 per MMBtu and (ii) basis swap contracts of 10,000 MMbtu per day of November 2020 through March 2021 production with an average price differential of $1.46 per MMBtu. (b) The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the NYMEX index prices used in swap contracts. |
Offsetting asset and liability | The fair value of derivative financial instruments not designated as hedging instruments is as follows: As of December 31, 2019 Type Consolidated Fair Gross Amounts Net Fair Value (in millions) Assets: Commodity price derivatives Derivatives - current $ 32 $ — $ 32 Contingent consideration Other assets - noncurrent $ 91 $ — $ 91 Liabilities: Commodity price derivatives Derivatives - current $ 12 $ — $ 12 Commodity price derivatives Derivatives - noncurrent $ 8 $ — $ 8 As of December 31, 2018 Type Consolidated Fair Gross Amounts Net Fair Value (in millions) Assets: Commodity price derivatives Derivatives - current $ 59 $ (7) $ 52 Liabilities: Commodity price derivatives Derivatives - current $ 34 $ (7) $ 27 |
Schedule of derivative gains and losses recognized on statement of operations | Gains and losses recorded on derivative contracts are as follows: Derivatives Not Designated Location of Gain/(Loss) Year Ended December 31, 2019 2018 2017 (in millions) Commodity price derivatives Derivative gain (loss), net $ 34 $ (292) $ (99) Interest rate derivatives Derivative gain (loss), net $ — $ — $ (1) Contingent consideration Interest and other income $ (45) $ — $ — |
Schedule of derivative assets or liabilities by counterparty | Net derivative assets (liabilities) associated with the Company's open commodity derivatives by counterparty are as follows: As of December 31, 2019 (in millions) Wells Fargo Bank $ 15 JP Morgan Chase 5 Scotia Bank 3 Royal Bank of Canada 1 Bank of Montreal (1) J Aron & Company (1) Merrill Lynch (1) Nextera Energy Power Marketing (2) Citibank (7) $ 12 |
Schedule of Oil Derivative Contracts volume and weighted average price | Volumes per day associated with outstanding oil derivative contracts as of December 31, 2019 and the weighted average oil prices for those contracts are as follows: 2020 Year Ending December 31, 2021 First Second Quarter Third Quarter Fourth Quarter Brent swap contracts: Volume per day (Bbl) 3,407 — — — — Price per Bbl $ 60.86 $ — $ — $ — $ — Brent collar contracts with short puts: Volume per day (Bbl) 145,500 135,500 115,500 115,500 7,000 Price per Bbl: Ceiling $ 68.46 $ 68.84 $ 69.78 $ 69.78 $ 65.37 Floor $ 61.64 $ 61.76 $ 62.06 $ 62.06 $ 60.00 Short put $ 53.45 $ 53.48 $ 53.56 $ 53.56 $ 52.00 Brent call contracts sold: Volume per day (Bbl) (a) — — — — 13,000 Price per Bbl: $ — $ — $ — $ — $ 72.10 ______________________ (a) The referenced call contracts were sold in exchange for higher ceiling prices on certain 2020 collar contracts with short puts. |
Long-term Debt and Interest E_2
Long-term Debt and Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Components of long-term debt | The components of long-term debt, including the effects of issuance costs and issuance discounts, are as follows: As of December 31, 2019 2018 (in millions) Outstanding debt principal balances: 7.50% senior notes due 2020 $ 450 $ 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 2,300 2,300 Issuance costs and discounts (11) (16) Total debt 2,289 2,284 Less current portion of long-term debt 450 — Long-term debt $ 1,839 $ 2,284 |
Principal maturities of long-term debt | Principal payments scheduled to be made on the Company's long-term debt are as follows (in millions): 2020 $ 450 2021 $ 500 2022 $ 600 2023 $ — 2024 $ — Thereafter $ 750 |
Interest expense | Interest expense activity is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Cash payments for interest $ 117 $ 133 $ 164 Accretion of finance lease 4 — — Amortization of issuance discounts 1 1 1 Amortization of capitalized loan fees 4 4 4 Net changes in accruals — (6) (9) Interest incurred 126 132 160 Less capitalized interest (5) (6) (7) Total interest expense $ 121 $ 126 $ 153 |
Incentive Plans (Tables)
Incentive Plans (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Defined Contribution Plan Disclosures | The Company match for the deferred compensation plan is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Deferred compensation plan $ 2 $ 3 $ 3 The Company match for the 401(k) plan is as follows: Year Ended December 31, 2019 2018 2017 (in millions) 401(k) plan $ 27 $ 36 $ 25 |
Number of LTIP shares available for issuance | The number of shares available for grant pursuant to awards under the LTIP is as follows: As of December 31, 2019 Approved and authorized awards 12,600,000 Awards granted under plan (8,371,882) Awards available for future grant 4,228,118 |
Number of ESPP shares available for issuance | The number of shares available for issuance under the ESPP is as follows: As of December 31, 2019 Approved and authorized shares 1,250,000 Shares issued (1,056,938) Shares available for future issuance 193,062 |
Schedule of stock-based compensation expense | Stock-based compensation expense and the associated income tax benefit for awards issued under both the LTIP and ESPP are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Restricted stock - Equity Awards $ 79 $ 65 $ 60 Restricted stock - Liability Awards 19 17 24 Performance unit awards 19 18 17 Employee stock purchase plan 2 2 2 Total stock-based compensation expense $ 119 $ 102 $ 103 Income tax benefit $ 18 $ 17 $ 19 |
Schedule of restricted stock award activity | Restricted stock award activity is as follows: Year Ended December 31, 2019 Equity Awards Liability Awards Number of Shares Weighted Number of shares Beginning incentive compensation awards 799,672 $ 165.10 201,501 Awards granted 713,238 $ 137.23 221,497 Awards forfeited (49,873) $ 147.06 (32,316) Awards vested (638,844) $ 154.89 (143,831) Ending incentive compensation awards 824,193 $ 149.99 246,851 |
Schedule of assumptions to estimate the fair value | Assumptions used to estimate the fair value of performance unit awards granted in each of the following years are as follows: 2019 2018 2017 Risk-free interest rate 2.49% 2.41% 1.42% Range of volatilities 27.7 % - 43.4% 30.4 % - 53.3% 33.6 % - 58.2% |
Schedule of performance unit activity | Performance unit activity is as follows: Year Ended December 31, 2019 Number of Weighted Average Beginning performance unit awards 119,169 $ 251.92 Units granted 86,483 $ 165.84 Units vested (b) (89,437) $ 247.10 Ending performance unit awards 116,215 $ 191.58 _____________________ (a) Amount reflects the number of performance units initially granted. The actual payout of shares upon vesting may be between zero and 250 percent of the performance units included in this table depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. |
Grant-date Fair Value of Vested Performance Units | The grant-date fair value of vested performance units is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Grant-date fair value of vested performance units $ 22 $ 21 $ 18 |
Cash Paid for Awards | Cash paid for vested Liability Awards is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Cash paid for vested Liability Awards $ 20 $ 24 $ 20 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation [Abstract] | |
Schedule of asset retirement obligation activity | Asset retirement obligations activity is as follows: Year Ended December 31, 2019 2018 (in millions) Beginning asset retirement obligations $ 183 $ 271 New wells placed on production 5 1 Changes in estimates (a) 82 16 Dispositions (37) (89) Liabilities settled (52) (30) Accretion of discount 10 14 Ending asset retirement obligations 191 183 Less current portion of asset retirement obligations 73 25 Asset retirement obligations, long term $ 118 $ 158 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The 2019 change in estimate is primarily due to accelerating the forecasted timing of abandoning certain of the Company's vertical oil and |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Schedule of assets and liabilities | The Company recognized a finance lease upon commencement of the Hidden Ridge Building lease in October 2019, the balances of which are as follows: Consolidated Balance Sheet Location As of December 31, 2019 (in millions) Finance lease right-of-use asset Other property and equipment, net $ 556 Finance lease liability Other liabilities - current $ 16 Finance lease liability Other liabilities - noncurrent $ 556 |
Lease costs | The components of lease costs, including amounts recoverable from joint operating partners, are as follows: Year Ended December 31, 2019 (in millions) Finance lease cost: Amortization of right-of-use asset (a) $ 7 Interest on lease liability 4 Operating lease cost (b) 200 Short-term lease cost (c) 33 Variable lease cost (d) 73 Total lease cost $ 317 _____________________ (a) Represents straight-line rent cost associated with the Company's finance lease right-of-use asset. (b) Represents straight-line rent cost associated with the Company's operating lease right-of-use assets. (c) Represents costs associated with short-term leases (those with a contractual term of 12 months or less) that are not included in the consolidated balance sheets. (d) Variable lease costs are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and gas properties. |
Schedule of changes in operating lease liabilities | The changes in lease liabilities are as follows: Year Ended December 31, 2019 Operating Finance (in millions) Beginning lease liabilities (a) $ 325 $ — Liabilities assumed in exchange for new right-of-use assets (b) 142 573 Contract modifications (c) 4 — Dispositions (1) — Liabilities settled (177) (5) Accretion of discount (d) 13 4 Ending lease liabilities (e) $ 306 $ 572 ______________________ (a) Represents January 1, 2019 balance upon adoption of ASC 842. (b) Represents noncash leasing activity. The weighted-average discount rate used in 2019 to determine the present value of future operating and finance lease payments is 3.3 percent and 3.0 percent, respectively. (c) Represents changes in lease liabilities due to modifications of original contract terms. (d) Represents imputed interest on discounted future cash payments. three |
Payment schedule for operating lease obligations | Maturities of lease obligations are as follows: As of December 31, 2019 Operating Finance (in millions) 2020 $ 149 $ 33 2021 92 33 2022 47 34 2023 13 35 2024 8 35 Thereafter 18 603 Total lease payments 327 773 Less present value discount (21) (201) Present value of lease liabilities $ 306 $ 572 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Guarantor Obligations | The changes in contract obligations are as follows: Year Ended December 31, 2019 (in millions) Beginning contract obligations $111 Additions (a) 400 Liabilities settled (51) Accretion of discount 10 Changes in estimate (b) (2) Ending contract obligations $ 468 ______________________ (a) Additions include a $348 million deficiency fee obligation related to the South Texas Divestiture, $49 million of South Texas accrued deficiency fees from January 2019 through April 2019, $2 million of sand storage deficiencies associated with the sale of pressure pumping assets and $1 million related to sand mine decommissioning. (b) Represents the difference between estimated and actual liabilities settled. |
Schedule of future minimum drilling commitments | Minimum firm commitments are as follows: As of December 31, 2019 Firm Commitments (in millions) 2020 $ 532 2021 534 2022 471 2023 407 2024 412 Thereafter 1,784 Total minimum firm commitments $ 4,140 |
Delivery Commitments | Delivery commitments for gas are as follows: As of December 31, 2019 (MMBtu per day) 2020 196,557 2021 175,000 2022 175,000 2023 175,000 2024 150,137 Thereafter 156,164 Total gas delivery commitments 1,027,858 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions [Table Text Block] | Transactions and balances with ProPetro are as follows: Year Ended December 31, 2019 2018 (in millions) Pressure pumping related services charges (a) $ 461 $ 111 ____________________ (a) Represents pressure pumping and related services provided by ProPetro as part of a long-term agreement. The 2018 amount represents charges associated with the pressure pumping and related services performed by ProPetro in the normal course of business prior to the Company's sale of its pressure pumping assets to ProPetro. As of December 31, 2019 2018 (in millions) Accounts receivable - due from affiliate (a) $ 3 $ 119 Accounts payable - due to affiliate (b) $ 88 $ 37 |
Major Customers (Tables)
Major Customers (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Risks and Uncertainties [Abstract] | |
Schedule of revenue by major customer | Purchasers of the Company's oil, NGL and gas production that individually accounted for ten percent or more of the Company's oil and gas revenues in at least one of the three years ended December 31, 2019 are as follows: Year Ended December 31, 2019 2018 2017 Sunoco Logistics Partners L.P. 33 % 28 % 21 % Occidental Energy Marketing Inc. 20 % 17 % 16 % Plains Marketing L.P. 13 % 15 % 14 % Enterprise Products Partners L.P. 1 % 6 % 11 % |
Schedule of sales of purchased oil, NGL and gas revenues | Purchasers of the Company's purchased oil and gas that individually accounted for ten percent or more of the Company's sales of purchased oil and gas in at least one of the three years ended December 31, 2019 are as follows: Year Ended December 31, 2019 2018 2017 Occidental Energy Marketing Inc. 30 % 34 % 39 % BP Energy 5 % 9 % 11 % Exxon Mobil 4 % 5 % 11 % Valero Marketing and Supply Company 2 % 9 % 14 % |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue Recognition [Abstract] | |
Disaggregation of Revenue | Disaggregated revenue from contracts with purchasers by product type is as follows: Year Ended December 31, 2019 2018 (in millions) Oil sales $ 4,168 $ 3,991 NGL sales 510 695 Gas sales 238 305 Total oil and gas sales 4,916 4,991 Sales of purchased oil 4,726 4,339 Sales of purchased gas 29 49 Total sales of purchased oil and gas 4,755 4,388 Total revenue from contracts with purchasers $ 9,671 $ 9,379 |
Interest And Other Income (Tabl
Interest And Other Income (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
Interest And Other Income | The components of interest and other income are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Gain on sale of variable interest ( Note 10 ) $ 56 $ — $ — Interest income 17 29 32 Deferred compensation plan income (loss) 15 (2) 4 Investment in affiliate valuation adjustment ( Note 4 ) 15 — — Severance and sales tax refunds 6 1 13 Seismic data sales 5 5 — Contingent consideration valuation adjustment ( Note 4 ) (45) — — Other 7 5 4 Total interest and other income $ 76 $ 38 $ 53 |
Other Expense (Tables)
Other Expense (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
Schedule of components of other expense | The components of other expense are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Restructuring charges (a) $ 159 $ — $ — Transportation commitment charges (b) 74 161 167 Corporate headquarters move-related costs (c) 41 — — Asset impairment (d) 38 11 2 Asset divestiture-related charges (e) 25 170 — Idle drilling and well service equipment charges (f) 25 — — Sand mine decommissioning-related charges (g) 23 443 — Legal and environmental charges 19 21 20 Vertical integration services loss (h) 15 2 17 Other 29 41 38 Total other expense $ 448 $ 849 $ 244 ____________________ (a) Represents employee-related charges associated with the Corporate Restructuring Program. See Note 3 and Note 8 for additional information. (b) Primarily represents firm transportation charges on excess pipeline capacity commitments. (c) Represents costs associated with relocating to the Hidden Ridge Building, including $28 million of accelerated amortization of the operating lease right-of-use asset associated with the Company's former corporate headquarters and$13 million of exit and move-related costs. (d) Primarily represents inventory and other asset impairment charges associated with the decommissioning of the Company's Brady, Texas sand mine and the divestiture of the Company's pumping services assets. See Note 3 and Note 4 for additional information. (e) Primarily represents employee-related charges and contract termination charges associated with the Company's divestitures. See Note 3 for additional information. (f) Primarily represents expenses attributable to idle frac fleet and drilling rig fees that are not chargeable to joint operations. (g) Represents accelerated depreciation related to the decommission of the Company's Brady, Texas sand mine. See Note 3 for additional information. (h) Primarily represents net margins (attributable to third party working interest owners) that result from Company-provided vertically integrated services, 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 years ended December 31, 2019, 2018 and 2017, these vertical integration net margins included $51 million, $128 million and $140 million of gross vertical integration revenues, respectively, and $66 million, $130 million and $157 million of total vertical integration costs and expenses, respectively. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Schedule of unrecognized tax benefits | Unrecognized tax benefit activity is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Beginning unrecognized tax benefits $ 141 $ 124 $ 112 Current year additions — 17 12 Effectively settled tax positions (102) — — Ending unrecognized tax benefits $ 39 $ 141 $ 124 |
Summary of open tax years | The earliest open years in the Company's key jurisdictions are as follows: U.S. federal 2012 Various U.S. states 2013 |
Income tax (provision) benefit attributable to continuing operations | Income tax (provision) benefit is as follows: Year Ended December 31, 2019 2018 2017 (in millions) Current: U.S. federal $ 8 $ — $ 5 U.S. state (3) (2) — Current income tax (provision) benefit 5 (2) 5 Deferred: U.S. federal (224) (258) 526 U.S. state (12) (16) (7) Deferred income tax (provision) benefit (236) (274) 519 Income tax (provision) benefit $ (231) $ (276) $ 524 |
Reconciliation of federal statutory tax rate | The effective tax rate for income (loss) is reconciled to the United States federal statutory rate as follows: Year Ended December 31, 2019 2018 2017 (in millions, except percentages) Income before income taxes $ 987 $ 1,251 $ 309 Net loss attributable to noncontrolling interests — 3 — Income attributable to common stockholders before income taxes $ 987 $ 1,254 $ 309 Federal statutory income tax rate 21 % 21 % 35 % Provision for federal income taxes at the statutory rate (207) (263) (108) State income tax provision (net of federal tax) (12) (12) (4) Change in federal income tax rate (a) — — 625 Other (12) (1) 11 Income tax (provision) benefit $ (231) $ (276) $ 524 Effective income tax rate, excluding net loss attributable to noncontrolling interests 23 % 22 % (170 %) ____________________ (a) During 2017, the Company recorded a benefit of $625 million as a result of the Tax Reform Legislation that reduced the federal income tax rate beginning in 2018. |
Schedule of deferred tax assets and liabilities | Significant components of deferred tax assets and deferred tax liabilities are as follows: As of December 31, 2019 2018 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 996 $ 882 Credit carryforwards (b) 101 111 Deferred interest carryforward (c) 43 — Asset retirement obligations 41 40 Incentive plans 40 48 Net deferred hedge losses — 11 South Texas Divestiture 75 — Lease deferred tax assets 191 — Other 47 51 Deferred tax assets 1,534 1,143 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (2,628) (2,248) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes and differences in lease right of use assets (189) (47) Net deferred hedge gains (4) — South Texas Divestiture (35) — Lease deferred tax liabilities (61) — Other (6) — Deferred tax liabilities (2,923) (2,295) Net deferred tax liability $ (1,389) $ (1,152) ____________________ (a) Net operating loss carryforwards as of December 31, 2019, consist of $5.0 billion of U.S. federal NOLs, which expire between 2032 and 2039 and $177 million of Colorado NOLs that begin to expire in 2027. The Colorado NOL has a fully offsetting valuation allowance. (b) Credit carryforwards as of December 31, 2019, consist of $12 million of U.S. federal minimum tax credits and U.S. federal and Texas credits for research activities of $88 million and $1 million, respectively. The U.S. federal and state research credits as of December 31, 2019 exclude $39 million of unrecognized tax benefits. (c) The deferred interest carryforward represents disallowed interest deductions under IRC Section 163(j) (Limitation on Deduction for Interest on Certain Indebtedness) for the current and prior years. The disallowed interest can be carried forward indefinitely and utilized in future years. |
Net Income Per Share Attribut_2
Net Income Per Share Attributable To Common Stockholders (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Reconciliation of net income (loss) attributable to common stockholders, basic and diluted | The components of basic and diluted net income per share attributable to common stockholders are as follows: Year Ended December 31, 2019 2018 2017 (in millions) Net income attributable to common stockholders $ 756 $ 978 $ 833 Participating share based earnings (a) (3) (5) (6) Basic and diluted net income attributable to common stockholders $ 753 $ 973 $ 827 Basic and diluted weighted average shares outstanding 167 171 170 ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so. |
Shares Repurchased | Shares repurchased are as follows: Year Ended December 31, 2019 2018 (a) 2017 (in millions) Shares repurchased $ 622 $ 149 $ — ______________________ (a) During 2018, the Company repurchased $22 million of common stock pursuant to a previously authorized common stock repurchase program and $127 million of common stock pursuant to the current authorized common stock repurchase program. |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Narrative) (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019USD ($)segmentgas_processing_plant | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 01, 2019USD ($) | |
Other Ownership Interests [Line Items] | ||||
Present value of lease liabilities | $ 306 | $ 325 | ||
Build-to-suit lease liability | 327 | |||
Operating lease right-of-use assets | $ 280 | |||
Number of Gas Processing Plants | gas_processing_plant | 11 | |||
Reportable operating segments | segment | 1 | |||
Stock-based compensation awards general vesting period | 3 years | |||
Revenue | $ 9,671 | $ 9,379 | ||
Allowances for doubtful accounts | $ 2 | |||
Pressure Pumping Assets | ||||
Other Ownership Interests [Line Items] | ||||
Board Designation Threshold Percent | 5.00% | |||
Pressure Pumping Assets | Pressure Pumping Assets | ||||
Other Ownership Interests [Line Items] | ||||
Shares acquired | 16.00% | |||
Minimum | Buildings | ||||
Other Ownership Interests [Line Items] | ||||
Estimated useful life | 20 years | |||
Minimum | Equipment, vehicles, furniture and fixtures and information technology | ||||
Other Ownership Interests [Line Items] | ||||
Estimated useful life | 3 years | |||
Minimum | Water infrastructure | ||||
Other Ownership Interests [Line Items] | ||||
Estimated useful life | 3 years | |||
Maximum | Buildings | ||||
Other Ownership Interests [Line Items] | ||||
Estimated useful life | 39 years | |||
Maximum | Equipment, vehicles, furniture and fixtures and information technology | ||||
Other Ownership Interests [Line Items] | ||||
Estimated useful life | 10 years | |||
Maximum | Water infrastructure | ||||
Other Ownership Interests [Line Items] | ||||
Estimated useful life | 50 years | |||
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | ||||
Other Ownership Interests [Line Items] | ||||
Third party expenses, processing plants and treating facilities | $ 43 | 36 | $ 26 | |
Revenue | $ 90 | $ 78 | $ 60 | |
ASU 2016-02 | ||||
Other Ownership Interests [Line Items] | ||||
Build-to-suit lease liability | $ (219) |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Schedule of Inventory) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Accounting Policies [Abstract] | ||
Materials and supplies inventories | $ 75 | $ 128 |
Commodities | 130 | 114 |
Inventories | 205 | 242 |
Net materials and supplies inventories reserves | $ 2 | $ 5 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies (Schedule of Other Property Plant and Equipment) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | $ 1,632 | $ 1,291 |
Accumulated depreciation property, plant and equipment, other assets | 382 | 854 |
Land and buildings (a) | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 877 | 380 |
Proved and unproved sand properties (e) | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 16 | 36 |
Water infrastructure | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 404 | 343 |
Transportation Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 35 | 50 |
Computer Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 120 | 143 |
Leasehold Improvements [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 0 | 13 |
Furniture and Fixtures [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 28 | 15 |
Construction in Progress and Capitalized Interest [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | $ 152 | $ 311 |
Summary Of Significant Accoun_7
Summary Of Significant Accounting Policies (Schedule of Adoption of ASC 606) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Revenue | $ 9,671 | $ 9,379 | |
Oil and gas | |||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Revenue | 4,916 | 4,991 | $ 3,518 |
Cost of revenue | $ 874 | $ 855 | $ 591 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures Acquisitions and Divestitures (Narrative) (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | 42 Months Ended | |||||||||
Dec. 31, 2019USD ($)a | Jul. 31, 2019USD ($)a | May 31, 2019USD ($) | Dec. 31, 2018USD ($) | Nov. 30, 2018USD ($) | Aug. 31, 2018USD ($) | Dec. 31, 2019USD ($)a | Sep. 30, 2019USD ($)a | Dec. 31, 2019USD ($)a | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jul. 01, 2022 | Jan. 01, 2021USD ($) | |
Business Acquisition [Line Items] | |||||||||||||
Payments for undeveloped acreage | $ 28 | $ 65 | $ 136 | ||||||||||
Proceeds from disposition of assets, net of cash sold | 149 | 469 | 352 | ||||||||||
Total consideration | $ 56 | $ 56 | 56 | ||||||||||
Gain (loss) on disposition of assets, net | (477) | 290 | 208 | ||||||||||
Loss (income) from vertical integration services | 15 | 2 | 17 | ||||||||||
Asset divestiture-related charges | $ 25 | 170 | $ 0 | ||||||||||
Percent of employees impacted | 25.00% | ||||||||||||
Restricted stock awards | Corporate Restructuring Program [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Share-based Payment Arrangement, Accelerated Cost | $ 26 | ||||||||||||
Vertical and horizontal wells in Glasscock County | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from disposition of assets, net of cash sold | $ 64 | ||||||||||||
Area of Land | a | 4,500 | 4,500 | 4,500 | ||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 10 | ||||||||||||
Certain vertical wells in Martin County of the Permian Basin | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from disposition of assets, net of cash sold | $ 27 | ||||||||||||
Area of Land | a | 1,400 | ||||||||||||
South Texas divestiture | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from disposition of assets, net of cash sold | $ 2 | ||||||||||||
Total consideration | 210 | ||||||||||||
Gain (loss) on disposition of assets, net | $ (525) | ||||||||||||
Disposal Group, Including Discontinued Operation, Contingent Consideration | 136 | ||||||||||||
Guarantor Obligations, Reimbursement | 69 | 69 | $ 69 | ||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | 208 | ||||||||||||
Escrow Deposit | $ 75 | 75 | $ 75 | ||||||||||
South Texas divestiture | Employee Severance [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Asset divestiture-related charges | 19 | ||||||||||||
South Texas divestiture | Forecast [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Loss Contingency, Obligation, Percentage | 10000.00% | ||||||||||||
Loss Contingency, Buyer Recovery, Percentage | 18.00% | ||||||||||||
Escrow Deposit | $ 50 | ||||||||||||
South Texas divestiture | Divestitures Obligations, South Texas [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Guarantor Obligations, Reimbursement | 72 | ||||||||||||
South Texas divestiture | Maximum | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Disposal Group, Including Discontinued Operation, Contingent Consideration | $ 450 | ||||||||||||
Loss Contingency, Obligation, Percentage | 10000.00% | ||||||||||||
South Texas divestiture | Maximum | Forecast [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Loss Contingency, Obligation, Percentage | 10000.00% | ||||||||||||
Loss Contingency, Buyer Recovery, Percentage | 2000.00% | ||||||||||||
Pressure Pumping Assets | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Investment in affiliate | $ 172 | 172 | |||||||||||
Sand mine | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Employee-related charges | $ 7 | ||||||||||||
Loss (income) from vertical integration services | $ 12 | ||||||||||||
Impairment of Long-Lived Assets to be Disposed of | 13 | ||||||||||||
Permian Basin | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from disposition of assets, net of cash sold | 77 | ||||||||||||
West Panhandle | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from disposition of assets, net of cash sold | $ 170 | ||||||||||||
Employee-related charges | 7 | ||||||||||||
Gain (loss) on disposition of assets, net | $ 127 | ||||||||||||
Certain Vertical Wells in Martin County of the Permian Basin [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Total consideration | $ 38 | ||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 26 | $ 31 | |||||||||||
Oil and Gas, Undeveloped Acreage, Gross | a | 1,900 | ||||||||||||
Pressure pumping assets | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Impairment of Long-Lived Assets to be Disposed of | 16 | ||||||||||||
Pressure pumping assets | Pressure Pumping Assets | Sale assets | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Employee-related charges | 19 | 1 | |||||||||||
Total consideration | 282 | $ 282 | |||||||||||
Gain (loss) on disposition of assets, net | 30 | ||||||||||||
Other divestiture-related charges | 6 | ||||||||||||
Loss on Contract Termination | $ 13 | ||||||||||||
Discontinued Operation, Amount of Adjustment to Prior Period Gain (Loss) on Disposal, before Income Tax | $ (10) |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Divestitures and Decommissioning Activities) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2018USD ($) | Nov. 30, 2018USD ($) | Aug. 31, 2018USD ($) | Jul. 31, 2018USD ($) | Jun. 30, 2018USD ($) | Apr. 30, 2018USD ($)a | Apr. 30, 2017USD ($)a | Dec. 31, 2019USD ($)a | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Total consideration | $ 56 | |||||||||
Gain (loss) on disposition of assets, net | (477) | $ 290 | $ 208 | |||||||
Proceeds from disposition of assets, net of cash sold | 149 | 469 | 352 | |||||||
Accelerated depreciation | 23 | 443 | 0 | |||||||
Impairment of Oil and Gas Properties | $ 0 | (77) | (285) | |||||||
Sinor Nest | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of assets, net | $ 54 | |||||||||
Area of Land | a | 2,900 | |||||||||
Proceeds from disposition of assets, net of cash sold | $ 105 | |||||||||
Sand mine | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Employee-related charges | $ 7 | |||||||||
Accelerated depreciation | $ 23 | |||||||||
West Panhandle | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of assets, net | $ 127 | |||||||||
Employee-related charges | 7 | |||||||||
Proceeds from disposition of assets, net of cash sold | $ 170 | |||||||||
Raton Basin | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of assets, net | $ 2 | |||||||||
Employee-related charges | 6 | |||||||||
Other divestiture-related charges | 117 | |||||||||
Proceeds from disposition of assets, net of cash sold | 54 | |||||||||
Impairment of Oil and Gas Properties | $ (77) | |||||||||
Contract deficiency | $ 111 | |||||||||
West Eagle Ford Shale | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of assets, net | $ 75 | |||||||||
Area of Land | a | 10,200 | |||||||||
Proceeds from disposition of assets, net of cash sold | $ 100 | |||||||||
Martin County | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of assets, net | $ 194 | |||||||||
Proceeds from disposition of assets, net of cash sold | $ 264 | |||||||||
Acres sold | a | 20,500 | |||||||||
Other proved and unproved properties, inventory and other property and equipment | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of assets, net | $ (9) | 1 | $ 14 | |||||||
Permian Basin | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Proceeds from disposition of assets, net of cash sold | $ 77 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures (Schedule of Divestiture-related Charges) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | $ 159 | $ 0 | $ 0 | |
Asset divestiture-related charges | 25 | 170 | 0 | |
Employee Severance [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Beginning employee-related obligations | 27 | 0 | ||
Restructuring Charges | 155 | 39 | ||
Cash payments | (176) | (12) | ||
Ending employee-related obligations | $ 6 | 6 | 27 | 0 |
Restructuring Reserve | 6 | 27 | $ 27 | $ 0 |
Employee Severance [Member] | South Texas divestiture | ||||
Restructuring Reserve [Roll Forward] | ||||
Asset divestiture-related charges | $ 19 | |||
Employee Severance [Member] | Corporate Restructuring Program [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | $ 133 |
Disclosures About Fair Value _3
Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | $ 85 | $ 82 |
Investment in affiliate | 187 | 172 |
Contingent consideration | 91 | |
Total assets | 395 | 306 |
Total recurring fair value measurements | 375 | 279 |
Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 32 | 52 |
Commodity derivatives | 20 | 27 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | 85 | 82 |
Investment in affiliate | 187 | 0 |
Contingent consideration | 0 | |
Total assets | 272 | 82 |
Total recurring fair value measurements | 272 | 82 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 0 | 0 |
Commodity derivatives | 0 | 0 |
Significant Other Observable Inputs (Level 2) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | 0 | 0 |
Investment in affiliate | 0 | 172 |
Contingent consideration | 91 | |
Total assets | 123 | 224 |
Total recurring fair value measurements | 103 | 197 |
Significant Other Observable Inputs (Level 2) | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 32 | 52 |
Commodity derivatives | 20 | 27 |
Significant Unobservable Inputs (Level 3) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | 0 | 0 |
Investment in affiliate | 0 | 0 |
Contingent consideration | 0 | |
Total assets | 0 | 0 |
Total recurring fair value measurements | 0 | 0 |
Significant Unobservable Inputs (Level 3) | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 0 | 0 |
Commodity derivatives | $ 0 | $ 0 |
Disclosures About Fair Value _4
Disclosures About Fair Value Measurements (Narrative) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Jul. 31, 2018USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | May 31, 2019USD ($) | |
Impairment of oil and gas properties | $ 0 | $ 77 | $ 285 | |||
Raton Basin | ||||||
Impairment of oil and gas properties | $ 77 | |||||
Contract deficiency | $ 111 | |||||
Pressure pumping assets | ||||||
Impairment of Long-Lived Assets to be Disposed of | 16 | |||||
Sand mine | ||||||
Impairment of Long-Lived Assets to be Disposed of | $ 13 | |||||
South Texas Divestiture [Member] | ||||||
Disposal Group, Including Discontinued Operation, Contingent Consideration | $ 450 | |||||
Proved properties | Raton Basin | ||||||
Impairment of oil and gas properties | 65 | |||||
Other property and equipment | Raton Basin | ||||||
Impairment of oil and gas properties | $ 12 | |||||
Discount rate | ||||||
Oil and gas contracts | 0.044 | |||||
Contingent Consideration, Cash Receipt, Measurement Input | 0.032 | |||||
Contingent Consideration, Cash Payment, Measurement Input | 0.029 | |||||
Discount rate | Valuation Technique, Discounted Cash Flow [Member] | Significant Unobservable Inputs (Level 3) | ||||||
Discounted using an annual rate | 0.10 |
Disclosures About Fair Value _5
Disclosures About Fair Value Measurements (Measured On A Nonrecurring Basis) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2017USD ($)$ / MMBTU$ / bbl | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value Adjustment | $ 0 | $ (77) | $ (285) | |
Raton Basin | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value | $ 186 | |||
Fair Value Adjustment | $ (285) | |||
Management oil price outlook | $ / bbl | 53.65 | |||
Management gas price outlook | $ / MMBTU | 3 |
Disclosures About Fair Value _6
Disclosures About Fair Value Measurements (Financial Assets and Liabilities Not Carried At Fair Value) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value, Disclosure Item Amounts [Domain] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | $ 0 | $ 441 |
Current portion of long-term debt | 450 | 0 |
Long-term debt | 1,839 | 2,284 |
Cash and cash equivalents | 631 | 825 |
Cash and Cash Equivalents, Fair Value Disclosure | 631 | 825 |
Short-term investments | 0 | 443 |
Long-term investments | 0 | 125 |
Reported Value Measurement [Member] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | 0 | 443 |
Estimate of Fair Value Measurement [Member] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Current portion of long-term debt | 451 | 0 |
Long-term debt | 1,995 | 2,374 |
Cash | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Cash and cash equivalents | 631 | 775 |
Cash and Cash Equivalents, Fair Value Disclosure | 631 | 775 |
Bank Time Deposits [Member] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Cash and cash equivalents | 0 | 50 |
Cash and Cash Equivalents, Fair Value Disclosure | 0 | 50 |
Commercial Paper [Member] | Fair Value, Disclosure Item Amounts [Domain] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | 0 | 53 |
Commercial Paper [Member] | Reported Value Measurement [Member] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | 0 | 53 |
Corporate Bond Securities [Member] | Fair Value, Disclosure Item Amounts [Domain] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | 0 | 288 |
Long-term investments | 0 | 125 |
Corporate Bond Securities [Member] | Reported Value Measurement [Member] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | 0 | 290 |
Long-term investments | 0 | 125 |
Bank Time Deposits [Member] | Fair Value, Disclosure Item Amounts [Domain] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | 0 | 100 |
Bank Time Deposits [Member] | Reported Value Measurement [Member] | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Short-term investments | $ 0 | $ 100 |
Disclosures About Fair Value _7
Disclosures About Fair Value Measurements Schedule of Fair Value Measurements (Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Schedule of Held-to-maturity Securities [Line Items] | ||
Cash and cash equivalents | $ 631 | $ 825 |
Short-term investments | 0 | 443 |
Long-term investments | $ 0 | $ 125 |
Derivative Financial Instrume_3
Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details) | 12 Months Ended |
Dec. 31, 2019bbl / d$ / bbl$ / MMBTU | |
Brent swap contracts, First Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 3,407 |
Brent swap contracts, First Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 60.86 |
Brent swap contracts, Second Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent swap contracts, Second Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent swap contracts, Third Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent swap contracts, Third Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent swap contracts, Fourth Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent swap contracts, Fourth Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent swap contracts, Next Year | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent swap contracts, Next Year | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent collar contracts with short puts, First Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 145,500 |
Brent collar contracts with short puts, First Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Ceiling, price per barrel | $ / bbl | 68.46 |
Floor, price per barrel | $ / bbl | 61.64 |
Short put, price per barrel | $ / bbl | 53.45 |
Brent collar contracts with short puts, Second Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 135,500 |
Brent collar contracts with short puts, Second Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Ceiling, price per barrel | $ / bbl | 68.84 |
Floor, price per barrel | $ / bbl | 61.76 |
Short put, price per barrel | $ / bbl | 53.48 |
Brent collar contracts with short puts, Third Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 115,500 |
Brent collar contracts with short puts, Third Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Ceiling, price per barrel | $ / bbl | 69.78 |
Floor, price per barrel | $ / bbl | 62.06 |
Short put, price per barrel | $ / bbl | 53.56 |
Brent collar contracts with short puts, Fourth Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 115,500 |
Brent collar contracts with short puts, Fourth Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Ceiling, price per barrel | $ / bbl | 69.78 |
Floor, price per barrel | $ / bbl | 62.06 |
Short put, price per barrel | $ / bbl | 53.56 |
Brent collar contracts with short puts, Next Year | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 7,000 |
Brent collar contracts with short puts, Next Year | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Ceiling, price per barrel | $ / bbl | 65.37 |
Floor, price per barrel | $ / bbl | 60 |
Short put, price per barrel | $ / bbl | 52 |
Brent call contracts sold, First Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent call contracts sold, First Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent call contracts sold, Second Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent call contracts sold, Second Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent call contracts sold, Third Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent call contracts sold, Third Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent call contracts sold, Fourth Quarter | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 0 |
Brent call contracts sold, Fourth Quarter | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 0 |
Brent call contracts sold, Next Year | Oil contracts | |
Derivative [Line Items] | |
Volume per day (Bbl) | bbl / d | 13,000 |
Brent call contracts sold, Next Year | Oil contracts, price per bbl | |
Derivative [Line Items] | |
Price per MMBtu in usd | $ / MMBTU | 72.10 |
Derivative Financial Instrume_4
Derivative Financial Instruments (Gas Derivative Contracts Volume And Weighted Average Price) (Details) | 2 Months Ended | 12 Months Ended |
Feb. 18, 2020MMBTU / d$ / MMBTU | Dec. 31, 2019MMBTU / d$ / MMBTU | |
Swap Contracts For First Quarter of Year One [Member] | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 0 | |
Swap Contracts For First Quarter of Year One [Member] | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | $ / MMBTU | 0 | |
Swap Contracts For Second Quarter of Year One [Member] | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 30,000 | |
Swap Contracts For Second Quarter of Year One [Member] | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | $ / MMBTU | 2.41 | |
Swap Contracts For Third Quarter of Year One [Member] | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 30,000 | |
Swap Contracts For Third Quarter of Year One [Member] | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | $ / MMBTU | 2.41 | |
Swap contracts for next year Q4 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 10,109 | |
Swap contracts for next year Q4 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | $ / MMBTU | 2.41 | |
Basis swap contracts for next year Q1 | Gas contracts, in MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 0 | |
Basis swap contracts for next year Q1 | Gas contracts, price per MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | $ / MMBTU | 0 | |
Basis swap contracts for next year Q2 | Gas contracts, in MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 30,000 | |
Basis swap contracts for next year Q2 | Gas contracts, price per MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | $ / MMBTU | (1.68) | |
Basis swap contracts for next year Q3 | Gas contracts, in MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 30,000 | |
Basis swap contracts for next year Q3 | Gas contracts, price per MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | $ / MMBTU | (1.68) | |
Basis swap contracts for next year Q4 | Gas contracts, in MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 10,109 | |
Basis swap contracts for next year Q4 | Gas contracts, price per MMBTU | Permian Basin | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | $ / MMBTU | (1.68) | |
Swap Contracts For November 2020 Through March 2021 [Member] | Gas contracts, in MMBTU | Subsequent event | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 10,000 | |
Price per MMBtu in usd | $ / MMBTU | 2.46 | |
Swap Contracts For November 2020 Through March 2021 [Member] | Gas contracts, in MMBTU | Permian Basin | Subsequent event | ||
Derivative [Line Items] | ||
Volume per day (Bbl) | MMBTU / d | 10,000 | |
Price differential, dollars per barrel | $ / MMBTU | 1.46 |
Derivative Financial Instrume_5
Derivative Financial Instruments (Narrative) (Details) - Subsequent event $ in Millions | Feb. 18, 2020USD ($) |
Interest Rate Contract, Fixed Five Year [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 100 |
Derivative, Fixed Interest Rate | 1.39% |
Interest Rate Contract, Fixed Ten Year [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 300 |
Derivative, Fixed Interest Rate | 1.57% |
Derivative Financial Instrume_6
Derivative Financial Instruments (Offsetting Assets and Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Assets: | ||
Net Fair Value Presented in the Consolidated Balance Sheet, current | $ 32 | $ 52 |
Derivative Liability [Abstract] | ||
Net Fair Value Presented in the Consolidated Balance Sheet, current | 12 | 27 |
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent | 8 | 0 |
Contingent consideration | 91 | |
Significant Other Observable Inputs (Level 2) | ||
Derivative Liability [Abstract] | ||
Contingent consideration | 91 | |
Derivatives - current | Derivatives not designated as hedging instruments | Commodity price derivatives | ||
Assets: | ||
Fair Value | 32 | 59 |
Gross Amounts Offset in the Consolidated Balance Sheet | 0 | (7) |
Net Fair Value Presented in the Consolidated Balance Sheet, current | 32 | 52 |
Derivative Liability [Abstract] | ||
Fair Value | 12 | 34 |
Gross Amounts Offset in the Consolidated Balance Sheet | 0 | (7) |
Net Fair Value Presented in the Consolidated Balance Sheet, current | 12 | $ 27 |
Other assets - noncurrent | Derivatives not designated as hedging instruments | Commodity price derivatives | ||
Assets: | ||
Fair Value | 91 | |
Net Fair Value Presented in the Consolidated Balance Sheet, current | 91 | |
Other assets - noncurrent | Derivatives not designated as hedging instruments | Contingent consideration | ||
Assets: | ||
Gross Amounts Offset in the Consolidated Balance Sheet | 0 | |
Derivatives - noncurrent | Derivatives not designated as hedging instruments | Commodity price derivatives | ||
Derivative Liability [Abstract] | ||
Fair Value | 8 | |
Gross Amounts Offset in the Consolidated Balance Sheet | 0 | |
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent | $ 8 |
Derivative Financial Instrume_7
Derivative Financial Instruments (Derivative Gains and Losses) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative [Line Items] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax | $ 34 | $ (292) | $ (100) |
Commodity price derivatives | Derivative gain (loss), net | |||
Derivative [Line Items] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax | 34 | (292) | (99) |
Interest rate derivatives | Derivative gain (loss), net | |||
Derivative [Line Items] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax | 0 | 0 | (1) |
Contingent consideration | Interest and other income | |||
Derivative [Line Items] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax | $ (45) | $ 0 | $ 0 |
Schedule of Derivative Assets a
Schedule of Derivative Assets and Liabilities by Counterparty (Details) $ in Millions | Dec. 31, 2019USD ($) |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | $ 12 |
Wells Fargo Bank | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | 15 |
JP Morgan Chase | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | 5 |
Scotia Bank | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | 3 |
Royal Bank of Canada | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | 1 |
Bank of Montreal | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | (1) |
J Aron & Company | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | (1) |
Merrill Lynch | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | (1) |
Nextera Energy Power Marketing | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | (2) |
Citibank | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Derivative Assets (Liabilities), at Fair Value, Net | $ (7) |
Long-term Debt and Interest E_3
Long-term Debt and Interest Expense (Components Of Long-Term Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||
Outstanding debt principal balances, gross | $ 2,300 | $ 2,300 |
Issuance costs and discounts | (11) | (16) |
Total debt | 2,289 | 2,284 |
Less current portion of long-term debt | 450 | 0 |
Long-term debt | 1,839 | $ 2,284 |
7.50% senior notes due 2020 | ||
Debt Instrument [Line Items] | ||
Senior notes, interest rate | 7.50% | |
Outstanding debt principal balances, gross | 450 | $ 450 |
3.45% senior notes due 2021 | ||
Debt Instrument [Line Items] | ||
Senior notes, interest rate | 3.45% | |
Outstanding debt principal balances, gross | 500 | $ 500 |
3.95% senior notes due 2022 | ||
Debt Instrument [Line Items] | ||
Senior notes, interest rate | 3.95% | |
Outstanding debt principal balances, gross | 600 | $ 600 |
4.45% senior notes due 2026 | ||
Debt Instrument [Line Items] | ||
Senior notes, interest rate | 4.45% | |
Outstanding debt principal balances, gross | 500 | $ 500 |
7.20% senior notes due 2028 | ||
Debt Instrument [Line Items] | ||
Senior notes, interest rate | 7.20% | |
Outstanding debt principal balances, gross | $ 250 | $ 250 |
Long-term Debt and Interest E_4
Long-term Debt and Interest Expense (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2019USD ($)Rate | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Debt Instrument [Line Items] | |||
Line of credit facility, maximum borrowing capacity | $ | $ 1,500,000,000 | ||
Outstanding borrowings under the Credit Facility | $ | 0 | ||
Repayments of debt | $ | $ 0 | $ 450,000,000 | $ 485,000,000 |
Credit Facility | |||
Debt Instrument [Line Items] | |||
Federal fund rate | 0.50% | ||
Alternate base rate spread | 0.25% | ||
Applicable margin | 1.25% | ||
Letters of credit outstanding under the Credit Facility, interest percentage | 0.125% | ||
Unused portion, fee percentage | 0.15% | ||
Debt instrument covenant description | 0.65 | ||
Swing Line Loans | Credit Facility | |||
Debt Instrument [Line Items] | |||
Maximum outstanding borrowings under the Credit Facility | $ | $ 150,000,000 |
Long-term Debt and Interest E_5
Long-term Debt and Interest Expense (Principal Maturities Of Long-Term Debt) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Debt Disclosure [Abstract] | |
2020 | $ 450 |
2023 | 0 |
2024 | 0 |
Thereafter | $ 750 |
Long-term Debt and Interest E_6
Long-term Debt and Interest Expense (Interest Expenses) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest | $ 117 | $ 133 | $ 164 |
Amortization of issuance discounts | 1 | 1 | 1 |
Amortization of capitalized loan fees | 4 | 4 | 4 |
Net changes in accruals | 0 | (6) | (9) |
Interest incurred | 126 | 132 | 160 |
Less capitalized interest | (5) | (6) | (7) |
Total interest expense | $ 121 | $ 126 | $ 153 |
Incentive Plans (Narrative) (De
Incentive Plans (Narrative) (Details) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($)$ / sharesRateshares | Dec. 31, 2018USD ($)$ / sharesRate | Dec. 31, 2017USD ($)$ / shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
ESPP offering period | 8 months | ||
Unrecognized stock-based compensation expense | $ | $ 95 | ||
Remaining vesting period | 3 years | ||
Pioneer Long Term Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Approved and authorized awards | shares | 12,600,000 | ||
Employee stock purchase plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Employee stock purchase plan contribution limit | 15.00% | ||
Employee stock purchase plan participants purchase price percent | 15.00% | ||
Approved and authorized awards | shares | 1,250,000 | ||
Restricted stock - Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized stock-based compensation expense | $ | $ 25 | ||
Awards granted | shares | 221,497 | ||
Grant date fair value | $ | $ 20 | $ 24 | $ 20 |
Amount of liabilities attributable to liability awards included in accounts payable | $ | $ 11 | $ 14 | |
Restricted stock units, including liability awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Awards granted | shares | 934,735 | ||
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares granted (usd per share) | $ / shares | $ 137.23 | $ 180.66 | $ 180.50 |
Grant date fair value | $ | $ 99 | $ 67 | $ 70 |
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining vesting period | 34 months | ||
Awards granted | shares | 86,483 | ||
Shares granted (usd per share) | $ / shares | $ 165.84 | $ 246.18 | $ 258.27 |
Grant date fair value | $ | $ 22 | $ 21 | $ 18 |
Expected volatility period | 3 years | ||
401(k) plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Participants annual salary contributions, percentage | 80.00% | ||
Matching contributions percent | 200.00% | ||
Limit of employee's contribution of base salary, percent | 5.00% | ||
Matching contributions vesting period in years | 4 | ||
Recognized compensation matching contribution expense | $ | $ 27 | 36 | 25 |
Deferred compensation retirement plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Matching contributions percent | 100.00% | ||
Matching contributions | $ | $ 2 | $ 3 | $ 3 |
Deferred compensation retirement plan | Base salary | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Participants annual salary contributions, percentage | 50.00% | 2500.00% | |
Deferred compensation retirement plan | Annual bonus | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Participants annual salary contributions, percentage | 100.00% | ||
Deferred compensation retirement plan | Officer | Base salary | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Limit of employee's contribution of base salary, percent | 10.00% | ||
Deferred compensation retirement plan | Key employee | Annual bonus | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Limit of employee's contribution of base salary, percent | 8.00% |
Incentive Plans (Number Of Shar
Incentive Plans (Number Of Shares Available Under The Company's Long Term Incentive Plan) (Details) - Pioneer Long Term Incentive Plan [Member] | 164 Months Ended |
Dec. 31, 2019shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Approved and authorized awards | 12,600,000 |
Awards granted under plan | (8,371,882) |
Awards available for future grant | 4,228,118 |
Incentive Plans (Schedule Of Em
Incentive Plans (Schedule Of Employee Stock Purchase Plan) (Details) - Employee stock purchase plan | 276 Months Ended |
Dec. 31, 2019shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Approved and authorized shares | 1,250,000 |
Awards granted under plan | (1,056,938) |
Shares available for future issuance | 193,062 |
Incentive Plans (Schedule of Co
Incentive Plans (Schedule of Compensation Expense for Each Type of Incentive Award) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 119 | $ 102 | $ 103 |
Income tax (provision) benefit | $ (231) | $ (276) | $ 524 |
Restricted stock - Equity Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares granted (usd per share) | $ 137.23 | $ 180.66 | $ 180.50 |
Stock-based compensation expense | $ 79 | $ 65 | $ 60 |
Grant date fair value | 99 | 67 | 70 |
Restricted stock - Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 19 | 17 | 24 |
Grant date fair value | 20 | 24 | $ 20 |
Amount of liabilities attributable to liability awards included in accounts payable | $ 11 | $ 14 | |
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares granted (usd per share) | $ 165.84 | $ 246.18 | $ 258.27 |
Stock-based compensation expense | $ 19 | $ 18 | $ 17 |
Grant date fair value | 22 | 21 | 18 |
Employee stock purchase plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 2 | 2 | 2 |
Compensation Expense For Incentive Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Income tax (provision) benefit | $ 18 | $ 17 | $ 19 |
Incentive Plans (Schedule Of Re
Incentive Plans (Schedule Of Restricted Stock Award Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at beginning of year, shares | 799,672 | ||
Awards granted | 713,238 | ||
Awards forfeited | (49,873) | ||
Awards vested | (638,844) | ||
Outstanding at end of year, shares | 799,672 | ||
Restricted stock - Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at beginning of year, shares | 201,501 | ||
Awards granted | 221,497 | ||
Awards forfeited | (32,316) | ||
Awards vested | (143,831) | ||
Outstanding at end of year, shares | 201,501 | ||
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at end of year, shares | 824,193 | ||
Weighted Average Grant- Date Fair Value | |||
Outstanding (usd per share) | $ 149.99 | $ 165.10 | |
Shares granted (usd per share) | 137.23 | $ 180.66 | $ 180.50 |
Shares forfeited (usd per share) | 147.06 | ||
Shares vested (usd per share) | $ 154.89 | ||
Restricted stock - Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Awards granted | 221,497 | ||
Outstanding at end of year, shares | 246,851 |
Incentive Plans (Schedule Of As
Incentive Plans (Schedule Of Assumptions To Estimate The Fair Value) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized stock-based compensation expense | $ 95 | ||
Remaining vesting period awards (less than) | 3 years | ||
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Risk-free interest rate | 2.49% | 2.41% | 1.42% |
Performance unit awards | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Range of volatilities | 27.70% | 30.40% | 33.60% |
Performance unit awards | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Range of volatilities | 43.40% | 53.30% | 58.20% |
Incentive Plans (Schedule Of Pe
Incentive Plans (Schedule Of Performance Unit Activity) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Weighted Average Grant- Date Fair Value | |||
Common stock, shares issued | 175,057,889 | 174,321,171 | |
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at beginning of year, shares | 119,169 | ||
Units granted | 86,483 | ||
Units vested | (89,437) | ||
Outstanding at end of year, shares | 116,215 | 119,169 | |
Weighted Average Grant- Date Fair Value | |||
Outstanding (usd per share) | $ 191.58 | $ 251.92 | |
Units granted (usd per share) | 165.84 | $ 246.18 | $ 258.27 |
Units vested (usd per share) | $ 247.10 | ||
Grant date fair value | $ 22 | $ 21 | $ 18 |
Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Units vested | (1,911) | ||
Weighted Average Grant- Date Fair Value | |||
Performance percentage of actual payout minimum | 0.00% | ||
Performance percentage to reach maximum | 250.00% | ||
Performance Units Service Period Lapsed [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Units vested | (58,539) | ||
Officer | Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Units vested | (32,809) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning asset retirement obligations | $ 183 | $ 271 | |
New wells placed on production | 5 | 1 | |
Changes in estimates (a) | 82 | 16 | |
Dispositions | (37) | (89) | |
Liabilities settled | (52) | (30) | |
Accretion of discount | 10 | 14 | $ 19 |
Ending asset retirement obligations | 191 | 183 | $ 271 |
Asset retirement obligations, current portion | 73 | 25 | |
Asset retirement obligations, long term | $ 118 | $ 158 |
Leases (Narrative) (Details)
Leases (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Nov. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 01, 2019 | |
Property, Plant and Equipment [Line Items] | |||||
Build-to-suit lease liability | $ (327) | ||||
Total consideration | 56 | ||||
Gain (Loss) on Disposition of Assets | 56 | $ 0 | $ 0 | ||
Accelerated amortization | $ 28 | 28 | |||
Present value of lease liabilities | 306 | $ 325 | |||
Operating Lease, Operating, Short-term and Variable Leases, Cost | 103 | ||||
Interest on lease liability | 4 | ||||
Finance Lease, Principal Payments | 1 | ||||
Operating and Variable Lease Costs | $ 180 | ||||
Operating lease, weighted average discount rate | 3.30% | ||||
Finance lease, weighted average discount rate | 3.00% | ||||
Operating Lease, Weighted Average Remaining Lease Term | 3 years | ||||
Finance Lease, Weighted Average Remaining Lease Term | 20 years | ||||
Operating Lease, Lease Not yet Commenced, Amount | $ 38 | ||||
Lessee, Operating Lease, Lease Not yet Commenced, Term of Contract | 4 years | ||||
ASU 2016-02 | |||||
Property, Plant and Equipment [Line Items] | |||||
Capitalized construction costs | 217 | ||||
Build-to-suit lease liability | $ 219 | ||||
Former Corporate Headquarters [Member] | |||||
Property, Plant and Equipment [Line Items] | |||||
Present value of lease liabilities | $ 27 |
Leases (Schedule of Assets and
Leases (Schedule of Assets and Liabilities) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Leases [Abstract] | |
Finance lease right-of-use asset | $ 556 |
Finance lease liability - current | 16 |
Finance lease liability - noncurrent | $ 556 |
Leases (Lease Costs) (Details)
Leases (Lease Costs) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Lease, Cost [Abstract] | |
Amortization of right-of-use asset | $ 7 |
Interest on lease liability | 4 |
Operating lease cost | 200 |
Short-term lease cost | 33 |
Variable lease cost | 73 |
Total lease cost | $ 317 |
Leases (Schedule of Changes in
Leases (Schedule of Changes in Operating Lease Liabilities) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Operating | |
Operating Lease, Liability | $ 306 |
Operating Lease Liability Assumed in Exchange for Right-of-Use Asset | 142 |
Operating Lease, Contract Modifications Increase (Decrease) | 4 |
Gain (Loss) on Disposition of Operating Lease Liabilities | (1) |
Operating Lease, Liabilities Settled | (177) |
Finance Lease, Liability Assumed in Exchange for Right-of-Use Asset | 573 |
Finance Lease, Contract Modifications Increase (Decrease) | 0 |
Dispositions | 0 |
Liabilities settled | (5) |
Accretion of discount | 4 |
Ending lease liabilities (e) | 572 |
Accretion Expense, Operating Leases | $ 13 |
Leases (Payment Schedule for Op
Leases (Payment Schedule for Operating Lease Obligations) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Jan. 01, 2019 |
Leases [Abstract] | ||
2020 | $ 149 | |
2021 | 92 | |
2022 | 47 | |
2023 | 13 | |
2024 | 8 | |
Thereafter | 18 | |
Total lease payments | 327 | |
Less present value discount | (21) | |
Present value of lease liabilities | 306 | $ 325 |
2020 | 33 | |
2021 | 33 | |
2022 | 34 | |
2023 | 35 | |
2024 | 35 | |
Thereafter | 603 | |
Total lease payments | 773 | |
Less present value discount | (201) | |
Present value of lease liabilities | $ 572 | $ 0 |
Commitments And Contingencies_2
Commitments And Contingencies (Narrative) (Details) - USD ($) | 12 Months Ended | 42 Months Ended | 57 Months Ended | 180 Months Ended | ||
Dec. 31, 2019 | Jul. 01, 2022 | Dec. 31, 2022 | Dec. 31, 2032 | May 31, 2019 | Apr. 30, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | ||||||
Current annual salaries of officers and key employees | $ 15,000,000 | |||||
South Texas divestiture | ||||||
Loss Contingencies [Line Items] | ||||||
Deficiency Fee Liability | (394,000,000) | |||||
Guarantor Obligations, Reimbursement | 69,000,000 | |||||
Guarantor Obligations, Liquidation Proceeds, Monetary Amount | 325,000,000 | |||||
South Texas divestiture | Forecast [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Obligation, Percentage | 10000.00% | |||||
Loss Contingency, Buyer Recovery, Percentage | 18.00% | |||||
Divestitures Obligations, Raton Transportation [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Guarantor Obligations, Liquidation Proceeds, Monetary Amount | 50,000,000 | |||||
Deficiency fees paid and reimbursed | 12,000,000 | |||||
West Eagle Ford Shale | ||||||
Loss Contingencies [Line Items] | ||||||
Guarantor Obligations, Liquidation Proceeds, Monetary Amount | $ 19,000,000 | |||||
Maximum | South Texas divestiture | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Obligation, Percentage | 10000.00% | |||||
Deficiency Fee Liability | $ 620,000,000 | |||||
Maximum | South Texas divestiture | Forecast [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Obligation, Percentage | 10000.00% | |||||
Loss Contingency, Buyer Recovery, Percentage | 2000.00% | |||||
Maximum | Divestitures Obligations, Raton Transportation [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Deficiency Fee Liability | 90,000,000 | |||||
Maximum | Divestitures Obligations, Raton Transportation [Member] | Forecast [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Obligation, Percentage | 10000.00% | |||||
Maximum | West Eagle Ford Shale | ||||||
Loss Contingencies [Line Items] | ||||||
Deficiency Fee Liability | 20,000,000 | |||||
Maximum | West Eagle Ford Shale | Forecast [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Obligation, Percentage | 10000.00% | |||||
Unfavorable Regulatory Action [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Monetary sanctions | (188,400) | |||||
Divestitures Obligations, South Texas [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Deficiency Fee Liability | 348,000,000 | $ (49,000,000) | ||||
Divestitures Obligations, South Texas [Member] | South Texas divestiture | ||||||
Loss Contingencies [Line Items] | ||||||
Guarantor Obligations, Reimbursement | $ 72,000,000 | |||||
Divestitures Obligations, South Texas [Member] | South Texas divestiture | Other Current Liabilities [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Monetary sanctions | $ (153,000,000) |
Commitments and Contingencies_3
Commitments and Contingencies (Schedule of Changes in Contract Obligations) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2019 | Apr. 30, 2019 | Dec. 31, 2018 | |
Loss Contingency Accrual [Roll Forward] | ||||
Contractual Obligation | $ 468 | $ 468 | $ 111 | |
Contract Obligation Accrual, Provision | 400 | |||
Contractual Obligation, Settled | (51) | |||
Contractual Obligation, Accretion of Discount | 10 | |||
Contractual Obligation, Revision of Estimate | (2) | |||
Divestitures Obligations, South Texas [Member] | ||||
Loss Contingency Accrual [Roll Forward] | ||||
Deficiency Fee Liability | (348) | (348) | $ 49 | |
Sand Storage Deficiencies [Member] | ||||
Loss Contingency Accrual [Roll Forward] | ||||
Deficiency Fee Liability | (2) | (2) | ||
Sand mine | ||||
Loss Contingency Accrual [Roll Forward] | ||||
Deficiency Fee Liability | $ (1) | $ (1) |
Commitments and Contingencies_4
Commitments and Contingencies (Schedule of Minimum Commitments) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Firm Commitments | |
2020 | $ 532 |
2021 | 534 |
2022 | 471 |
2023 | 407 |
2024 | 412 |
Thereafter | 1,784 |
Total minimum firm commitments | $ 4,140 |
Commitments And Contingencies_5
Commitments And Contingencies (Schedule of Delivery Commitments) (Details) | Dec. 31, 2019mMBtus_per_day |
Commitments and Contingencies Disclosure [Abstract] | |
2020 | 196,557 |
2021 | 175,000 |
2022 | 175,000 |
2023 | 175,000 |
2024 | 150,137 |
Thereafter | 156,164 |
Total gas delivery commitments | 1,027,858 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | |
Related Party Transaction [Line Items] | |||
Accounts receivable - due from affiliate | $ 119 | $ 3 | $ 119 |
Pressure pumping related services charges (a) | 461 | 111 | |
Accounts payable - due to affiliate | $ 37 | $ 88 | $ 37 |
Pressure Pumping Assets | |||
Related Party Transaction [Line Items] | |||
Board Designation Threshold Percent | 5.00% | ||
Pressure Pumping Assets | Pressure Pumping Assets | |||
Related Party Transaction [Line Items] | |||
Shares acquired | 16.00% | ||
Pressure pumping assets | Pressure Pumping Assets | Sale assets | |||
Related Party Transaction [Line Items] | |||
Shares received | 16.6 | ||
Short-term receivables | $ 110 |
Major Customers (Consolidated O
Major Customers (Consolidated Oil, NGL And Gas Revenues) (Details) - Customer concentration | 12 Months Ended | ||
Dec. 31, 2019Rate | Dec. 31, 2018Rate | Dec. 31, 2017Rate | |
Sunoco Logistics Partners L.P. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 33.00% | 28.00% | 21.00% |
Occidental Energy Marketing Inc. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 20.00% | 17.00% | 16.00% |
Plains Marketing L.P. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 13.00% | 15.00% | 14.00% |
Enterprise Products Partners L.P. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 1.00% | 6.00% | 11.00% |
Major Customers Major Customers
Major Customers Major Customers (Sales of Purchased Oil and Gas (Details) - Sales of Purchased Oil and Gas [Member] | 12 Months Ended | ||
Dec. 31, 2019Rate | Dec. 31, 2018Rate | Dec. 31, 2017Rate | |
Occidental Energy Marketing Inc. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 30.00% | 34.00% | 39.00% |
Valero Marketing and Supply Company | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 2.00% | 9.00% | 14.00% |
BP Corporation North America [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 5.00% | 9.00% | 11.00% |
Exxon Mobil [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 4.00% | 5.00% | 11.00% |
Revenue Recognition (Details)
Revenue Recognition (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Revenue [Line Items] | ||
Revenue | $ 9,671 | $ 9,379 |
Description of 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, NGL and gas and sales of purchased oil and gas may not be received for 30 to 60 days after the date the volumes are delivered, and as a result, the Company is required to estimate the amount of volumes delivered to the purchaser and the price that will be received for the sale of the product. | |
Accounts receivable, due or billable | $ 968 | 646 |
Oil sales | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | 4,168 | 3,991 |
NGL Sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | 510 | 695 |
Gas Sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | 238 | 305 |
Total Oil and Gas Sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | 4,916 | 4,991 |
Sale of Oil Purchased [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | 4,726 | 4,339 |
Sale of Gas Purchased [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | 29 | 49 |
Sales of Purchased Oil and Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue | $ 4,755 | $ 4,388 |
Interest And Other Income (Inte
Interest And Other Income (Interest And Other Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |||
Gain (Loss) on Disposition of Assets | $ 56 | $ 0 | $ 0 |
Interest income | 17 | 29 | 32 |
Deferred Compensation Plan Income | 15 | (2) | 4 |
Investment in affiliate valuation adjustment | 15 | 0 | 0 |
Tax refunds | 6 | 1 | 13 |
Seismic Data Sales | 5 | 5 | 0 |
Contingent Consideration, Valuation Adjustment | (45) | 0 | 0 |
Other Income | 7 | 5 | 4 |
Interest and other | $ 76 | $ 38 | $ 53 |
Other Expense (Details)
Other Expense (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Nov. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | ||||
Restructuring Charges | $ 159 | $ 0 | $ 0 | |
Transportation commitment charges | 74 | 161 | 167 | |
Relocation Costs | 41 | 0 | 0 | |
Asset Impairment Charges | 38 | 11 | 2 | |
Asset divestiture-related charges | 25 | 170 | 0 | |
Idle drilling and well service equipment charges | 25 | 0 | 0 | |
Accelerated depreciation | 23 | 443 | 0 | |
Legal and environmental charges | 19 | 21 | 20 | |
Loss (income) from vertical integration services | 15 | 2 | 17 | |
Other | 29 | 41 | 38 | |
Total other expense | 448 | 849 | 244 | |
Accelerated amortization | $ 28 | 28 | ||
Exit and Relocation Costs | 13 | |||
Gross vertical integration revenues | 51 | 128 | 140 | |
Total vertical integration costs and expenses | $ 66 | $ 130 | $ 157 |
Income Taxes (Schedule of Unrec
Income Taxes (Schedule of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Beginning unrecognized tax benefits | $ 141 | $ 124 | $ 112 |
Current year additions | 0 | 12 | 17 |
Effectively settled tax positions | (102) | 0 | 0 |
Ending unrecognized tax benefits | $ 39 | $ 141 | $ 124 |
Income Taxes (Income Taxes Paid
Income Taxes (Income Taxes Paid) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Taxes Paid [Abstract] | |||
Payments for income taxes, net of tax refunds received | $ (5) | $ 0 | $ 0 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||||
Payments for income taxes, net of tax refunds received | $ (5) | $ 0 | $ 0 | |
Income tax benefit from rate change | 625 | |||
AMT credit carryovers | 12 | |||
Unrecognized tax benefits | $ 39 | $ 141 | $ 124 | $ 112 |
Income Taxes (Summary Of Open T
Income Taxes (Summary Of Open Tax Years, By Jurisdiction) (Details) | 12 Months Ended |
Dec. 31, 2019 | |
U.S. federal | |
Income Tax Contingency [Line Items] | |
Open tax years, by jurisdiction | 2012 |
Various U.S. states | |
Income Tax Contingency [Line Items] | |
Open tax years, by jurisdiction | 2013 |
Income Taxes (Schedule Of Incom
Income Taxes (Schedule Of Income Tax (Provision) Benefit Allocation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Income tax (provision) benefit | $ (231) | $ (276) | $ 524 |
Income Taxes (Income Tax (Provi
Income Taxes (Income Tax (Provision) Benefit Attributable To Income From Continuing Operations) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Current: | |||
U.S. federal | $ 8 | $ 0 | $ 5 |
U.S. state | (3) | (2) | 0 |
Current income tax (provision) benefit | 5 | (2) | 5 |
Deferred: | |||
U.S. federal | (224) | (258) | 526 |
U.S. state | (12) | (16) | (7) |
Deferred income tax benefit | (236) | (274) | 519 |
Income tax (provision) benefit | $ (231) | $ (276) | $ 524 |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Income before income taxes | $ 987 | $ 1,251 | $ 309 |
Net loss attributable to noncontrolling interests | 0 | 3 | 0 |
Income attributable to common stockholders before income taxes | $ 987 | $ 1,254 | $ 309 |
Federal statutory income tax rate | 21.00% | 21.00% | 35.00% |
Provision for federal income taxes at the statutory rate | $ (207) | $ (263) | $ (108) |
State income tax provision (net of federal tax) | (12) | (12) | (4) |
Change in federal income tax rate | 0 | 0 | 625 |
Other | (12) | (1) | 11 |
Income tax (provision) benefit | $ (231) | $ (276) | $ 524 |
Effective income tax rate, excluding net loss attributable to noncontrolling interests | 23.00% | 22.00% | (170.00%) |
Income tax benefit from rate change | $ 625 |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Deferred Tax Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Valuation Allowance [Line Items] | ||||
Net operating loss carryforward | $ 996 | $ 882 | ||
Credit carryforwards | 101 | 111 | ||
Deferred interest carryforward | 43 | 0 | ||
Asset retirement obligations | 41 | 40 | ||
Incentive plans | 40 | 48 | ||
Net deferred hedge losses | 0 | 11 | ||
South Texas Divestiture | 75 | 0 | ||
Lease deferred tax assets | 191 | 0 | ||
Other | 47 | 51 | ||
Total deferred tax assets | 1,534 | 1,143 | ||
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes | (2,628) | (2,248) | ||
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes | (189) | (47) | ||
Net deferred hedge gains | (4) | 0 | ||
South Texas Divestiture | (35) | 0 | ||
Lease deferred tax liabilities | (61) | 0 | ||
Other | (6) | 0 | ||
Deferred tax liabilities | (2,923) | (2,295) | ||
Net deferred tax liability | (1,389) | (1,152) | ||
Unrecognized tax benefits | 39 | $ 141 | $ 124 | $ 112 |
U.S. Federal Tax Credit Carryforward [Member] | U.S. | ||||
Valuation Allowance [Line Items] | ||||
Credit carryforwards | 12 | |||
Research Tax Credit Carryforward [Member] | U.S. | ||||
Valuation Allowance [Line Items] | ||||
Credit carryforwards | 88 | |||
Research Tax Credit Carryforward [Member] | Texas | ||||
Valuation Allowance [Line Items] | ||||
Credit carryforwards | 1 | |||
Domestic Tax Authority [Member] | ||||
Valuation Allowance [Line Items] | ||||
Net operating loss carryforward | 5,000 | |||
COLORADO | ||||
Valuation Allowance [Line Items] | ||||
Net operating loss carryforward | $ 177 |
Net Income Per Share Attribut_3
Net Income Per Share Attributable To Common Stockholders (Schedule of Net Income (Loss) Reconciliation) (Details) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |||
Net income attributable to common stockholders | $ 756 | $ 978 | $ 833 |
Participating basic earnings | (3) | (5) | (6) |
Net income (loss) attributable to common stockholders | $ 753 | $ 973 | $ 827 |
Basic and diluted weighted average common shares outstanding | 167 | 171 | 170 |
Net Income Per Share Attribut_4
Net Income Per Share Attributable To Common Stockholders (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Equity, Class of Treasury Stock [Line Items] | |||
Repurchase of common stock | $ 653,000,000 | $ 179,000,000 | $ 36,000,000 |
Stock repurchase program | |||
Equity, Class of Treasury Stock [Line Items] | |||
Authorized repurchase amount | 2,000,000,000 | ||
Repurchase of common stock | 127,000,000 | ||
Stock Repurchase Program, Remaining Authorized Repurchase Amount | 1,300,000,000 | ||
Shares repurchased | |||
Equity, Class of Treasury Stock [Line Items] | |||
Repurchase of common stock | $ 622,000,000 | 149,000,000 | $ 0 |
Previously Authorized Common Stock Repurchase Program [Member] | |||
Equity, Class of Treasury Stock [Line Items] | |||
Repurchase of common stock | $ 22,000,000 |
Subsequent Events (Details)
Subsequent Events (Details) - $ / shares | Feb. 19, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 15, 2020 |
Subsequent Event [Line Items] | |||||
Dividends declared (usd per share) | $ 1.20 | $ 0.32 | $ 0.08 | ||
7.50% senior notes due 2020 | |||||
Subsequent Event [Line Items] | |||||
Senior Notes, interest rate, percentage | 7.50% | ||||
Subsequent event | |||||
Subsequent Event [Line Items] | |||||
Dividends declared (usd per share) | $ 0.55 | ||||
Subsequent event | 7.50% senior notes due 2020 | |||||
Subsequent Event [Line Items] | |||||
Senior Notes, interest rate, percentage | 7.50% |