Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 16, 2018 | Jun. 30, 2017 | |
Document Documentand Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | CXO | ||
Entity Registrant Name | CONCHO RESOURCES INC | ||
Entity Central Index Key | 1,358,071 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Common Stock, Shares Outstanding | 149,067,852 | ||
Entity Public Float | $ 17,883,517,337 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 0 | $ 53 |
Accounts receivable, net of allowance for doubtful accounts: | ||
Oil and natural gas | 331 | 220 |
Joint operations and other | 212 | 238 |
Inventory | 14 | 16 |
Derivative instruments | 0 | 4 |
Prepaid costs and other | 35 | 31 |
Total current assets | 592 | 562 |
Property and equipment: | ||
Oil and natural gas properties, successful efforts method | 21,267 | 18,476 |
Accumulated depletion and depreciation | (8,460) | (7,390) |
Total oil and natural gas properties, net | 12,807 | 11,086 |
Other property and equipment, net | 234 | 216 |
Total property and equipment, net | 13,041 | 11,302 |
Funds held in escrow | 0 | 43 |
Deferred loan costs, net | 13 | 11 |
Intangible assets, net | 26 | 24 |
Other assets | 60 | 177 |
Total assets | 13,732 | 12,119 |
Current liabilities: | ||
Accounts payable - trade | 43 | 28 |
Bank overdrafts | 116 | 0 |
Revenue payable | 183 | 132 |
Accrued drilling costs | 330 | 359 |
Derivative instruments | 277 | 82 |
Other current liabilities | 216 | 152 |
Total current liabilities | 1,165 | 753 |
Long-term debt | 2,691 | 2,741 |
Deferred income taxes | 687 | 766 |
Noncurrent derivative instruments | 102 | 96 |
Asset retirement obligations and other long-term liabilities | 172 | 140 |
Commitments and contingencies (Note 10) | ||
Stockholders' equity: | ||
Common stock, $0.001 par value; 300,000,000 authorized; 149,324,849 and 146,488,685 shares issued at December 31, 2017 and 2016, respectively | 0 | 0 |
Additional paid-in capital | 7,142 | 6,783 |
Retained earnings | 1,840 | 884 |
Treasury stock, at cost; 598,049 and 429,708 shares at December 31, 2017 and 2016, respectively | (67) | (44) |
Total stockholders' equity | 8,915 | 7,623 |
Total liabilities and stockholders' equity | $ 13,732 | $ 12,119 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 300,000,000 | 300,000,000 |
Common stock, shares issued | 149,324,849 | 146,488,685 |
Treasury shares | 598,049 | 429,708 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating revenues: | |||
Oil sales | $ 2,092 | $ 1,350 | $ 1,540 |
Natural gas sales | 494 | 285 | 264 |
Total operating revenues | 2,586 | 1,635 | 1,804 |
Operating costs and expenses: | |||
Oil and natural gas production | 408 | 320 | 390 |
Production and ad valorem taxes | 199 | 131 | 151 |
Exploration and abandonments | 59 | 77 | 59 |
Depreciation, depletion and amortization | 1,146 | 1,167 | 1,223 |
Accretion of discount on asset retirement obligations | 8 | 7 | 8 |
Impairments of long-lived assets | 0 | 1,525 | 61 |
General and administrative (including non-cash stock-based compensation of $60, $59 and $63 for the years ended December 31, 2017, 2016 and 2015, respectively) | 244 | 226 | 231 |
(Gain) loss on derivatives | 126 | 369 | (700) |
(Gain) loss on disposition of assets, net | (678) | (118) | 54 |
Total operating costs and expenses | 1,512 | 3,704 | 1,477 |
Income (loss) from operations | 1,074 | (2,069) | 327 |
Other income (expense): | |||
Interest expense | (146) | (204) | (215) |
Loss on extinguishment of debt | (66) | (56) | 0 |
Other, net | 19 | (9) | (15) |
Total other expense | (193) | (269) | (230) |
Income (loss) before income taxes | 881 | (2,338) | 97 |
Income tax (expense) benefit | 75 | 876 | (31) |
Net income (loss) | $ 956 | $ (1,462) | $ 66 |
Earnings per share: | |||
Basic net income (loss) | $ 6.44 | $ (10.85) | $ 0.54 |
Diluted net income (loss) | $ 6.41 | $ (10.85) | $ 0.54 |
Consolidated Statements of Ope5
Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Non-cash stock-based compensation | $ 60 | $ 59 | $ 63 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders Equity - USD ($) shares in Thousands, $ in Millions | Total | Common Stock [Member] | Additional Paid In Capital [Member] | Retained Earnings [Member] | Treasury Stock [Member] |
BALANCE, Shares at Dec. 31, 2014 | 113,265 | 260 | |||
BALANCE at Dec. 31, 2014 | $ 5,281 | $ 0 | $ 3,028 | $ 2,280 | $ (27) |
Net income (loss) | 66 | $ 0 | 0 | 66 | $ 0 |
Issuance of common stock (Shares) | 15,755 | 0 | |||
Issuance of common stock | 1,536 | $ 0 | 1,536 | 0 | $ 0 |
Common stock issued in business combinations | 0 | ||||
Stock options exercised | 0 | $ 0 | 0 | 0 | $ 0 |
Stock options exercised, shares | 5 | 0 | |||
Grants of restricted stock, shares | 452 | 0 | |||
Cancellation of restricted stock, shares | (33) | 0 | |||
Stock-based compensation | 63 | $ 0 | 63 | 0 | $ 0 |
Excess tax benefit (deficiency) related to stock-based compensation | 2 | 0 | 2 | 0 | 0 |
Purchase of treasury stock | (5) | $ 0 | 0 | 0 | $ (5) |
Purchase of treasury stock, shares | 0 | 46 | |||
BALANCE, Shares at Dec. 31, 2015 | 129,444 | 306 | |||
BALANCE at Dec. 31, 2015 | 6,943 | $ 0 | 4,629 | 2,346 | $ (32) |
Net income (loss) | (1,462) | $ 0 | 0 | (1,462) | $ 0 |
Issuance of common stock (Shares) | 10,350 | 0 | |||
Issuance of common stock | 1,327 | $ 0 | 1,327 | 0 | $ 0 |
Common stock issued in business combinations (Shares) | 6,134 | 0 | |||
Common stock issued in business combinations | 768 | $ 0 | 768 | 0 | $ 0 |
Stock options exercised | 1 | $ 0 | 1 | 0 | $ 0 |
Stock options exercised, shares | 23 | 0 | |||
Grants of restricted stock, shares | 451 | 0 | |||
Performance unit share conversion, shares | 180 | 0 | |||
Cancellation of restricted stock, shares | (93) | 0 | |||
Stock-based compensation | 59 | $ 0 | 59 | 0 | $ 0 |
Excess tax benefit (deficiency) related to stock-based compensation | (1) | 0 | (1) | 0 | 0 |
Purchase of treasury stock | (12) | $ 0 | 0 | 0 | $ (12) |
Purchase of treasury stock, shares | 0 | 124 | |||
BALANCE, Shares at Dec. 31, 2016 | 146,489 | 430 | |||
BALANCE at Dec. 31, 2016 | 7,623 | $ 0 | 6,783 | 884 | $ (44) |
Adoption of ASU No. 2016-09 (Note 2) | Accounting Standards Update 2016-09 [Member] | 8 | 0 | 8 | 0 | 0 |
BALANCE at Jan. 1, 2017 | 7,631 | 0 | 6,791 | 884 | (44) |
Net income (loss) | 956 | $ 0 | 0 | 956 | $ 0 |
Common stock issued in business combinations (Shares) | 2,177 | 0 | |||
Common stock issued in business combinations | 291 | $ 0 | 291 | 0 | $ 0 |
Stock options exercised | 0 | $ 0 | 0 | 0 | $ 0 |
Stock options exercised, shares | 20 | 0 | |||
Grants of restricted stock, shares | 490 | 0 | |||
Performance unit share conversion, shares | 249 | 0 | |||
Cancellation of restricted stock, shares | (100) | 0 | |||
Stock-based compensation | 60 | $ 0 | 60 | 0 | $ 0 |
Purchase of treasury stock | (23) | $ 0 | 0 | 0 | $ (23) |
Purchase of treasury stock, shares | 0 | 168 | |||
BALANCE, Shares at Dec. 31, 2017 | 149,325 | 598 | |||
BALANCE at Dec. 31, 2017 | $ 8,915 | $ 0 | $ 7,142 | $ 1,840 | $ (67) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ 956 | $ (1,462) | $ 66 |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||
Depreciation, depletion and amortization | 1,146 | 1,167 | 1,223 |
Accretion of discount on asset retirement obligations | 8 | 7 | 8 |
Impairments of long-lived assets | 0 | 1,525 | 61 |
Exploration and abandonments, including dry holes | 27 | 57 | 34 |
Non-cash stock-based compensation expense | 60 | 59 | 63 |
Deferred income taxes | (71) | (864) | 30 |
(Gain) loss on disposition of assets, net | (678) | (118) | 54 |
(Gain) loss on derivatives | 126 | 369 | (700) |
Net settlements received from (paid on) derivatives | 79 | 625 | 633 |
Loss on extinguishment of debt | 66 | 56 | 0 |
Other non-cash items | (1) | 14 | 14 |
Changes in operating assets and liabilities, net of acquisitions and dispositions: | |||
Accounts receivable | (126) | 32 | 128 |
Prepaid costs and other | (9) | 6 | (4) |
Inventory | 0 | 2 | (5) |
Accounts payable | 14 | 15 | (18) |
Revenue payable | 52 | (38) | (68) |
Other current liabilities | 46 | (68) | 11 |
Net cash provided by (used in) operating activities | 1,695 | 1,384 | 1,530 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Additions to oil and natural gas properties | (1,581) | (1,046) | (2,185) |
Acquisitions of oil and natural gas properties | (908) | (1,351) | (259) |
Additions to property, equipment and other assets | (44) | (61) | (67) |
Proceeds from the disposition of assets | 803 | 332 | 0 |
Deposits on dispositions of oil and natural gas properties | 29 | 0 | 0 |
Direct transaction costs for disposition of assets | (18) | 0 | 0 |
Funds held in escrow | 0 | (43) | 0 |
Contributions to equity method investments | 0 | (56) | (91) |
Net cash provided by (used in) investing activities | (1,719) | (2,225) | (2,602) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from issuance of debt | 2,795 | 600 | 1,491 |
Payments of debt | (2,829) | (1,200) | (1,630) |
Debt extinguishment costs | (63) | (42) | 0 |
Excess tax benefit (deficiency) from stock-based compensation | 0 | (1) | 2 |
Net proceeds from issuance of common stock | 0 | 1,327 | 1,536 |
Payments for loan costs | (25) | (7) | 0 |
Purchase of treasury stock | (23) | (12) | (5) |
Increase (decrease) in bank overdrafts | 116 | 0 | (93) |
Net cash provided by (used in) financing activities | (29) | 665 | 1,301 |
Net increase (decrease) in cash and cash equivalents | (53) | (176) | 229 |
Cash and cash equivalents at beginning of period | 53 | 229 | 0 |
Cash and cash equivalents at end of period | 0 | 53 | 229 |
SUPPLEMENTAL CASH FLOWS: | |||
Cash paid for interest | 139 | 232 | 211 |
Cash paid for income taxes | 13 | 0 | 4 |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of common stock for business combinations | $ 291 | $ 768 | $ 0 |
Organization and nature of oper
Organization and nature of operations | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and nature of operations | Note 1 . Organization and nature of operations Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is t he acquisition, development, exploration and production of oil and natural gas properties primarily l ocated in the Permian Basin of s outheast New Mexico and w est Texas. |
Summary of significant accounti
Summary of significant accounting policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of significant accounting policies | Note 2 . Summary of significant accounting policies Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also include the accounts of a variable interest en tity (“VIE”) where the Company wa s the primary beneficiary of the arrangements during the year ended December 31, 2017 . See Note 4 for additional information regarding the circumstances surrounding the VIE. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated. R eclassifications. Certain prior period amounts have been reclassified to conform to the 2017 presentation. These reclassifications had no im pact on net income (loss), total stockholders’ equity or total cash flows. Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America 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. Actual results could differ from the se estimates. Depletion of oi l and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rat es of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves , commodity price outlooks and prevailing market rates of other sources of income and costs . Other significant estimates inclu de, but are not limited to, asset retirement obligations, fair value of stock-based compensation , fair value of business combinati ons, fair value of nonmonetary transactions, fair value of de rivative financial instruments and income taxes . Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an origin al maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believe s that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, 2016, the majority of the Company’s cash was invested in stable value government money market funds. Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Oil and natural gas sales receivables related to these operations are generally unsecured. Jo int interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due dat e. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $ 1 million for each of the year s ended December 31, 2017 and 2016 . Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost o r net realizable value, on a weighted average cost basis . Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integra ted assets is based on the unit-of-production method using proved dev eloped reserves . During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized depletion expense from operations of $ 1,122 million, $ 1,145 mi llion and $ 1,203 million, respectively. The Company generally 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 ar e met: the well has found a sufficient quantity of reserves to justify its completion as a producing well; and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the Company’s l arge multi-well project development program, capital intensive nature and geographical location of certain projects, it may take longer than one year to evaluate the future potential of the exploration well and economics associated with making a determinat ion on its commercial viability. In these instances, the project ’ s feasibility is not contingent upon price improvements or advances in technology, but rather the C ompany’ s ongoing efforts and expenditures related to accurately predicting the hydrocarbon r ecoverability based on well information, ga ining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued consta ntly. Consequently, the Company’ s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves and is transferred to proved oil and natural gas properties or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional in formation regarding the Company’ s suspended exploratory well costs. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or a bandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disp osition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred. Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects ar e ready for their intended use. During the y ears ended December 31, 2017 and 2015 , the Company had capitalized interest of approximately $ 3 million and $ 1 million, respectively. The Company did not have capitalized interes t related to significant oil and natural gas development projects for the year ended December 31, 2016 . The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances ind icate 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 is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment lo ss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base . For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized a t that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital e xpenditures and production costs and cash flows from integrated assets . The Compan y recognized impairment expense of approximately $ 1.5 b illion and $ 61 million duri ng the years ended December 31, 2016 and 2015 , respectively, related to its proved oil and natural gas properties. The Company did not recognize impairment expense during the year ended December 31, 2017 . See Note 7 for additional in formation regarding the Company’ s impairment expense . Unpro ved oil and natural gas properties are periodically assessed for impairment by consid ering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the pr ojects. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized expense of approximately $ 29 million, $ 60 million and $ 35 million, respectively, related to abandoned and expiring acreage , which is included in exploration and abandonments expense in the accompanying consolidated statements of operations. Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of a ssets ranging from two to 39 years. The Company had other capital assets of $ 234 million and $ 216 million, net of accumulated depreciation of $ 90 million and $ 74 million, at December 31, 2017 a nd December 31, 2016 , respectively. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized depreciation expense of $ 21 million, $ 21 million and $ 19 million, respectively. Dur ing the y ear ended December 31, 2015 , the Company had capitalized interest of approximately $ 1 million. The Company did not have capitalized interest related to other property and equipment during the years ended December 31, 2017 or 2016 . Funds held in escrow. At December 31, 2016 , the Company’s funds held in escrow totaled $43 million, which consisted of a deposit paid by the Company that was held in escrow for its Northern Delaware Basin acquisition. See Note 4 for additional information regarding the acquisition . Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is computed using the straight-line method. The Company had deferred loan costs related to its credit facility o f $ 13 million and $ 11 million, net of accumulated amortization of $ 51 million and $ 56 million, in noncurrent assets at December 31, 2017 and 2016 , respectively. Intangible assets. The Company has capitalized certain rights acquired through acquisition s . The gross intangible assets , which have no residual value, are amortized over the estimated economic life of three to 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life . The following table reflects the gross and net intangible assets at December 31, 2017 and 2016 , respectively : December 31, (in millions) 2017 2016 Gross intangibles $ 42 $ 37 Accumulated amortization (16) (13) Net intangibles $ 26 $ 24 The Company recognized amortization expense of approximately $3 million for the year ended December 31, 2017 and approximately $1 million for each of the years ended December 31, 2016 and 2015 . The Company will record amortization expense of approximately $3 million for the year ended December 31, 2018 and approximately $1 million for each of the remaining years under the term. Equity method investments. Equity method investments are included in other assets in the Company’s consolidated balance sheets . Income and losses incurred from the Company’s equity investments are recorded in other income (expense) in its consolidated statements of operations. At December 31, 2016, the Company owned a 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the N orthern Delaware Basin. The Company’s net investment in ACC was approximately $ 129 million at December 31, 2016 . During th e years ended December 31, 2016 and 2015 , the Company recorded a loss of approximately $ 2 million and $ 4 million, respectively. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. See Note 4 for additional information regarding the disposition of ACC. The Company owns a membership interest in Oryx Southern Delawar e Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering an d transportation system in the S outhern Delaware Basin. During 2017, the Company’s membership interest was reduced from 25 percent to 23.75 percent after the addition of a new partne r. The Company’s net investment was approximately $ 49 million and $ 42 million at December 31, 2017 and 2016 , respectively . During the years ended December 31, 2017 and 2016 , the Company recorded income of appro ximately $ 7 million and a loss of approximately $ 2 million, respectively . Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing , regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probab le and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash paymen ts is fixed and readily determinable. At December 31, 2017 and 2016 , the Company has accrued approximately $ 3 million and $ 1 million, respectively, related to environmental liabilities. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized environmental charges of approximately $ 9 million, $ 7 million and $ 3 million, respectively. Senior note deferred loan costs. Senior note de ferred loan costs are stated at cost, net of amortization, which is computed using the effective interest method. The Company had senior n ote deferred loan costs of $ 25 million and $ 31 million, net of accumulated amortization of $ 1 million and $ 12 million, as a reduction of long-term debt at December 31, 2017 a nd 2016 , respectively. See Note 9 for additional information regarding activity related to the Company’s senior notes. Income taxes. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributabl e to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years i n which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is establis hed to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company evaluates uncertain tax positions for recognition and measurement in the cons olidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the te chnical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consol idated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of b enefit that is greater than 50 percent likely of b eing realized upon settlement. The Company had no material uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2017 or 2016 . Any interest or pena lties would be recognized as a component of income tax expense. On December 22, 2017, the President of the United States (“the President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” ( “TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”) to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allows companies to report provisional amounts when based on reason able estimates and to adjust these amounts during a measurement period of up to one year. The Company has elected to apply SAB 118 and, as such, has recorded provisional amounts for the income tax balances reported in its consolidated financial statements. The Company will continue to monitor any new administrative guidance or tax law interpretation. See Note 11 for additional information regarding the Company’s deferred tax balances and its accounting for the impacts of the TCJA. Derivative instruments. The Company recognizes its derivative instruments , other than any commodity derivative contracts that are designated as normal purchase and normal sale, as either assets or liabilities measured at fair value. The Company netted the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical del ivery contracts to effectively provide commodity price hedges. Because these contracts are not expec ted to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company ’s consolidated financial statements. Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the relat ed long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increas e in the carrying amount of the liability and as corresponding accretion expense. Based on certain factors including commodity prices and costs, the Company may revise its previous estimates related to the liability, which would also increase or decrease t he associated oil and natural gas property asset. Treasury stock. Treasury stock purchases are recorded at cost. Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser , which for the Company is primarily at the wellhead . The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas i mbalances. Oil and n atural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. I mbalances are tracked by well ; ho wever, the Company does not record any receivable from or payable to the other owners unless the imbalance has reached a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the C ompany is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance. The Company had no significant imbalances at December 31, 2017 or 2016 . General and administrative expense . The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $ 16 million, $ 17 million and $ 19 million for the years e nded December 31, 2017 , 2016 and 2015 , respectively. Stock-based compensation. S tock-based compensation expense is recognized in the Company’ s financial statements on a n accelerated basis over the awards’ vesting periods based on their grant date fair values. S tock-based compensation awards generally vest over a period ranging from one to eight years. The Company utilizes the average of the grant date’s hi gh and low stock price s for the fair value of restricted stock and the Monte Carlo simulation method for the fair value of performance unit awards. Recent ly adopted accounting pronouncements. The Company adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” on January 1, 2017. The adoption did not have an impact on prior period consolidated financial statements. The Company elected to account for forfeitures of share-based payments as they occur. At December 31, 2016, the Company had not recorded compensation expense of approximately $8 million based on forecasted forfeitures nor the associated deferred tax benefit of approximately $3 million. Addi tionally, t he Company recognized all excess tax benefits not previously recorded, which totaled approximately $5 million at December 31, 2016. Upon adoption, the Company recorded a cumulative-effect adjustment, which decreased retained earnings by less tha n $1 million, increased additional paid-in capital by approximately $8 million, and de creased net deferred income tax liabilities by approximately $8 million. The Company elected to prospectively classify excess tax benefits and deficiencies as operating a ctivities on the consolidated statements of cash flows and will prospectively record those excess tax benefits and deficiencies as discrete items in the income tax provision in the consolidated statements of operations. Under the new standard, for the year ended December 31, 2017 , the Company recorded excess tax benefits of approximately $ 6 million in the Company’s income tax provision. Also under the new standard, for the year ended December 31 , 2017, the Company recorded actual forfeitures of share- bas ed payments of approximately $ 8 million. New accounting pronouncements issued but not yet adopted . In May 2014, the Financial Accounting Standards Board (the “ FASB ”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlin es a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model prov ides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU No. 2014-09 by one year. That ne w standard is now effective for annual reporting periods beginning after December 15, 2017. The Company has completed its evaluation and implementation of ASU No. 2014-09 and will adopt the new revenue recognition guidance during the first quarter of 2018. The Company has elected to use the modified retrospective method for adoption. Upon adoption, the Company will not record a material cumulative effect adjustment and prior period financial statements will not be restated. The adoption of this guidanc e is not expected to have an ongoing material impact on the Company’s financial statements. More specifically, the adoption of this guidance will result in changes to sales of oil and natural gas and operating expenses due to the conclusion that some third -parties meet the definition of an agent under the control model in ASC 606, thus the fees paid to these service providers will be classified as operating expenses under ASC 606. With the adoption, the Company has updated its revenue recognition policy and its related internal control documentation, processes and controls to conform to the new standard. The Company will also expand its revenue recognition related disclosures. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which su persedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense re cognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company does not plan to early adopt the standard . The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. The Company is substantially complete with the process of revi ewing and determining the contracts to which this new guidance applies. The Company is currently enhancing its accounting system in order to track and calculate additional information necessary for adoption of this standard. The Company believes this new g uidance will have a moderate impact to its consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under currently applicable guidance. In June 2016, the FASB issued ASU No. 2016-1 3, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requ ires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This gui dance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” with the objective of adding guidance to assist in evaluating whether transactions should be accounted fo r as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. The Company does not believe this new guidance will have a material impact on its consolidated financial statements. |
Exploratory well costs
Exploratory well costs | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract] | |
Exploratory well costs | Note 3 . Exploratory well costs The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized explo ratory well costs are carried in unproved oil and natural gas properties. See Unaudited Supplementary Data for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are ch arged to exploration and abandonments expense in the consolidated statements of operations. The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Beginning capitalized exploratory well costs $ 151 $ 116 $ 242 Additions to exploratory well costs pending the determination of proved reserves 180 144 103 Reclassifications due to determination of proved reserves (147) (86) (228) Exploratory well costs charged to expense - (6) (1) Disposition of wells (2) (17) - Ending capitalized exploratory well costs $ 182 $ 151 $ 116 The following table provides an aging at December 31, 2017 and 2016 of capitalized exploratory well costs based on the date drilling was completed: December 31, (in millions, except number of projects) 2017 2016 Capitalized exploratory well costs that have been capitalized for a period of one year or less $ 180 $ 141 Capitalized exploratory well costs that have been capitalized for a period greater than one year 2 10 Total capitalized exploratory well costs $ 182 $ 151 Number of projects with exploratory well costs that have been capitalized for a period greater than one year 2 8 |
Acquisitions, divestitures and
Acquisitions, divestitures and nonmonetary transactions | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions, divestitures and nonmonetary transactions [Abstract] | |
Acquisitions, divestitures and nonmonetary transactions | Note 4 . Acquisitions, divestitures and nonmonetary transactions D uring the year ended December 31, 2017 , the Company entered into the following transactions : Northern Delaware Basin acquisition. In January and April 2017, the Company closed on the two-part acquisition in the Northern Delaware Basin. As consideration for the entire acquisition , the Company paid approximately $160 million in cash , of which $43 million was held in escrow at December 31, 2016, and issued to the seller appr oximately 2.2 million shares of its common stock w ith an approximate value of $291 million. ACC divestiture. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. The Company and its joint venture partner entered into s eparate agreements to sell 100 percent of their respective ownership interests in ACC. After adjustments for debt and working capital, the Company received cash proceeds from the sale of approximately $801 million. After direct transaction costs, the Compa ny recorded a pre-tax gain on disposition of assets of approximately $655 million which is included in other income in the consolidated financial statements. The Company’s net investment in ACC at the time of closing was approximately $129 million. Midla nd Basin acquisition. In July 2017, the Company completed an acquisition in the Midland Basin. As consideration for the acquisition, the Company paid approximately $595 million in cash. Concurrent with the acquisition, the Company entered into a transacti on structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended (the “Code”) . In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the o il and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operates the properties pursuant to a management agreement with the VIE. At December 31 , 2017, the Company was determined to be the primary benefic iary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. The assets currently held by the VIE attributable to the acquisition will be conveyed to the Company or one of its subs idiaries, and the VIE structure will terminate, upon the earlier of (i) the completion of the Reverse 1031 Exchange or (ii) the expiration of the time allowed by the treasury regulations and published Internal Revenue Service guidance to complete the Rever se 1031 Exchange , which is 180 days from commencement . At Decem ber 3 1, 2017, the VIE’s total assets and liabilities included i n the Company’s consolidated balance sheet were approximately $608 million and $604 million , respectively. See Note 17 for further discussion of the subsequent event that completed the Reverse 1031 Exchange . Non monetary transactions. During 2017 , the Company completed multiple nonmonetary transactions. The transactions include the exchange of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and as a result the Company recorded pre-tax gains of approximately $26 million. D uring t he year ended December 31, 2016 , the Company entered into the following transactions : Asset divestiture. In February 2016, the Company sold certain assets in the northern Delaware Basin for proceeds of approximately $292 million and recognized a pre-tax gain of approximately $110 million. Southern Delaware Basin acquisition. In March 2016, the Company completed an acquisition of 80 perc ent of a third-party seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, the Company issued to the seller approximately 2.2 million shares of common stock with an approximate value of $231 million, $146 million in cash and $40 million to carry a portion of the seller’s future development costs in these properties that was expended in 2016 and 2017 and included in costs incurred. Reliance acquisition. In October 2016, the Company completed an acquisition of approxi mately 40,000 net acres in the n orthern Midland Basin and other assets from Reliance Energy, Inc. (collectively, the “Reliance Acquisition”) for approximately $1.7 billion. As consideration for the acqu isition, the Company paid approximately $1.2 billion in cash and issued to the seller approximately 3.9 million shares of common stock with an approximate value of $0.5 billion. Approximately $29 million of operating revenues and approximately $10 million of income from operations attributed to the Reliance Acquisition are included in the Company’s results of operations from the closing date in October 2016 through the year ended December 31, 2016. The following table reflects the fair value of the acquired assets and liabilities at the October 2016 closing date associated with the Reliance Acquisition: (in millions) Fair value of net assets: Proved oil and natural gas properties $ 730 Unproved oil and natural gas properties 972 Other assets 34 Total assets acquired 1,736 Current liabilities, including current portion of asset retirement obligations (8) Asset retirement obligations assumed (12) Fair value of net assets acquired $ 1,716 Fair value of consideration paid for net assets: Cash consideration $ 1,176 Non-cash consideration, including equity 540 Total consideration paid for net assets $ 1,716 Pro forma data. The following unaudited pro forma combined condensed financial data for the year ended December 31, 2016 was derived from the historical financial statements of the Company giving effect to the Reliance Acquisition, as if it had occurred on January 1, 2016 . The results of operations for the Reliance Acquisition are included in the Company’s results of operations since the closing date in October 2016 through December 31, 2017 . The pro forma financial data does not include the results of operations for a ny other acquisitions made during the periods presented , as they were primarily acreage acquisitions and their results were not deemed material. The unaudited pro forma combined condensed financial data has been included for comparat ive purposes only and is not necessarily indicative of the results that might have occurred had the Reliance Acquisition taken place as of the date indicated and is not intended to be a projection of future results . Year Ended (in millions, except per share amounts) December 31, 2016 (unaudited) Operating revenues $ 1,717 Net loss $ (1,396) Earnings per common share: Basic net loss $ (10.36) Diluted net loss $ (10.36) During t he year ended December 31, 2015 , the Company entered into the following transaction : Clayton Williams Acreage Exchange. In December 2015, the Company completed a nonmonetary acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. The Company recognized a loss on disposition of assets of approximately $50 million related to the acreage exchange based on the fair value of the assets surrendered. |
Asset retirement obligations
Asset retirement obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations | Note 5 . Asset retirement obligations The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws . Market risk premiums associated with asset retirement obligations are estimated to repre sent a component of the Company’ s credit-adjusted risk-free rate that is utilized in the calculations o f ass et retirement obligations. The Company’s asset retirement obligation transactions during the years ended December 31, 2017 , 2016 and 2015 are summarized in the table below: Years Ended December 31, (in millions) 2017 2016 2015 Asset retirement obligations, beginning of period $ 130 $ 120 $ 120 Liabilities incurred from new wells 2 2 4 Liabilities assumed in acquisitions 10 13 2 Accretion expense 8 7 8 Disposition of wells (1) (11) - Liabilities settled upon plugging and abandoning wells (5) (1) (3) Revision of estimates (a) (3) - (11) Asset retirement obligations, end of period $ 141 $ 130 $ 120 (a) The revisions to the Companyʼs asset retirement obligation estimates for the years ended December 31, 2017 and 2015 are primarily due to a reduction in the future estimated abandonment costs. |
Incentive plans
Incentive plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Incentive plans | Note 6 . Incentive plans Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of its employees. During the years ended December 31, 2017 , 2016 and 2015 , the Company matched 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual eligible compensation, subject to federal limit s . The Company’s contributions to the plan for the years ended December 31, 2017 , 2016 and 2015 were approximately $ 10 million , $ 9 m illion and $ 10 million, respectively, of which a portion was recoverable from other working interest owners. Stock incentive plan. The Company’s 2015 Stock Incentiv e Plan (the “Plan”) provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company. A total of 10.5 million shares of common stock have been authorized for issuance under the Plan. At December 31, 2017 , the Company had 2.1 million shares of common stock available for future grants. Shares issued as a result of awards granted under the Plan are generally n ew common shares. Restricted stock awards. All restricted shares are legally issued and outstanding . If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the year ended D ecember 31, 2017 is presented below: Weighted Average Number of Grant Date Restricted Fair Value Shares Per Share Restricted stock: Outstanding at December 31, 2016 1,157,270 $ 115.29 Shares granted 490,300 $ 123.16 Shares cancelled / forfeited (100,199) $ 113.56 Lapse of restrictions (398,125) $ 117.91 Outstanding at December 31, 2017 1,149,246 $ 118.02 For restricted stock awards granted, stock-based compensation expense is being recognized in the Company’ s consolidated financial statements on a n accelerated basis over the awards’ vesting periods based on their grant date fair values . The restricted stock-based compensation awards generally vest over a period ranging from one to eight years . The Company utilizes the average of the grant date’s high and low stock price s for the fair value of restricted stock. The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Fair value for awards granted during the period (a) $ 60 $ 51 $ 50 Fair value for awards vested during the period $ 49 $ 45 $ 36 Stock-based compensation expense from restricted stock $ 43 $ 41 $ 43 Income tax benefit related to restricted stock $ 11 $ 15 $ 16 (a) The weighted average grant date fair value per share amounts were $123.16, $112.78 and $109.76 for the years ended December 31, 2017, 2016 and 2015, respectively. During the year ended December 31, 2017 , the Company recorded actual forfeitures of $8 million which reduced total stock-based compensation expense. During the year ended December 31, 2016 , the Company recorded $5 million of estimated forfeitures. Stock option awards. A summary of the Company’s stock option award activity under the Plan for the year ended December 31, 2017 is presented below: Weighted Average Number of Exercise Options Price Stock options: Outstanding at December 31, 2016 20,000 $ 15.33 Options exercised (20,000) $ 15.33 Outstanding at December 31, 2017 - Vested and exercisable at December 31, 2017 - The intrinsic value of options exercised was approximately $ 2 million for each of the years ended December 31, 2017 and 2016 based on the difference between the market price at the exercise date and the option exercise price. The Company did not have any material options exercised during the year ended December 31, 2015 . Performance unit awards. During the years ended December 31, 2017 , 2016 and 2015 , the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The grant date fair value was determined using the Monte Carlo simulation method and is being expensed ratably over the performance period. Expected volatilities utilized in the model were es timated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the U . S. Treasury rate for a term commensurate with the expected life of the grant. The Com pany used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, 2017 2016 2015 Risk-free interest rate 1.47% 1.31% 1.07% Range of volatilities 24.8% - 60.2% 31.6% - 59.0% 26.1% - 43.0% The following table summarizes the performance unit activity for the year ended December 31, 2017 : Number of Grant Date Units Fair Value Performance units: Outstanding at December 31, 2016 331,526 $ 136.68 Units granted (a) 108,398 $ 183.48 Units forfeited (43,333) $ 140.00 Units vested (b) (148,944) $ 156.86 Outstanding at December 31, 2017 247,647 $ 146.10 (a) Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period. (b) On December 31, 2017, the performance period ended for these performance units. Each unit converted into three shares representing 446,832 shares of common stock issued on January 2, 2018. The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Fair value for awards granted during the period (a) $ 20 $ 19 $ 28 Fair value for awards vested during the period $ 68 $ 33 $ 16 Stock-based compensation expense from performance units $ 17 $ 18 $ 20 Income tax benefit related to performance units $ 2 $ 7 $ 7 (a) The weighted average grant date fair value per unit amounts were $183.48, $114.81 and $156.86 for the years ended December 31, 2017, 2016 and 2015, respectively. Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-bas ed compensation awards that we re outstanding at December 31, 2017 : (in millions) 2018 $ 49 2019 26 2020 8 Thereafter 2 Total $ 85 |
Disclosures about fair value me
Disclosures about fair value measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Disclosures about fair value measurements | Note 7 . Disclosures about fair value measurements The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. 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. These two types of inputs are further prioritized into the following fair value input hierarchy: Level 1 : Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 : Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-ex change traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i ) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures. Level 3 : P rices or valuation m odels that require inputs that are both significant to the fair value measurement and less observable from objective sources ( i.e. , supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consi der various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Financial Assets and Liabilities Measured at Fair Value The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 Carrying Fair Carrying Fair (in millions) Value Value Value Value Assets: Derivative instruments $ - $ - $ 4 $ 4 Liabilities: Derivative instruments $ 379 $ 379 $ 178 $ 178 Credit facility $ 322 $ 322 $ - $ - $600 million 5.5% senior notes due 2022 (a) $ - $ - $ 594 $ 620 $1,550 million 5.5% senior notes due 2023 (a) $ - $ - $ 1,555 $ 1,621 $600 million 4.375% senior notes due 2025 (a) $ 593 $ 624 $ 592 $ 599 $1,000 million 3.75% senior notes due 2027 (a) $ 987 $ 1,012 $ - $ - $800 million 4.875% senior notes due 2047 (a) $ 789 $ 874 $ - $ - (a) The carrying value includes associated deferred loan costs and any premium (discount). Credit facility. The carrying amount of the Company’s credit facility approximates its fair value, as the applicable interest rates are variable and reflective of market rates. Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy. Other financial assets and liabilities . The Company has other financial instruments consisting primarily of receivable s, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments. Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect th e valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize ( i ) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, 2017 and 2016 . The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets. December 31, 2017 Fair Value Measurements Using Net Quoted Prices Gross Fair Value in Active Significant Amounts Presented Markets for Other Significant Offset in the in the Identical Observable Unobservable Total Consolidated Consolidated Assets Inputs Inputs Fair Balance Balance (in millions) (Level 1) (Level 2) (Level 3) Value Sheet Sheet Assets Current: Commodity derivatives $ - $ 13 $ - $ 13 $ (13) $ - Noncurrent: Commodity derivatives - 1 - 1 (1) - Liabilities Current: Commodity derivatives - (290) - (290) 13 (277) Noncurrent: Commodity derivatives - (103) - (103) 1 (102) Net derivative instruments $ - $ (379) $ - $ (379) $ - $ (379) December 31, 2016 Fair Value Measurements Using Net Quoted Prices Gross Fair Value in Active Significant Amounts Presented Markets for Other Significant Offset in the in the Identical Observable Unobservable Total Consolidated Consolidated Assets Inputs Inputs Fair Balance Balance (in millions) (Level 1) (Level 2) (Level 3) Value Sheet Sheet Assets Current: Commodity derivatives $ - $ 59 $ - $ 59 $ (55) $ 4 Noncurrent: Commodity derivatives - - - - - - Liabilities Current: Commodity derivatives - (137) - (137) 55 (82) Noncurrent: Commodity derivatives - (96) - (96) - (96) Net derivative instruments $ - $ (174) $ - $ (174) $ - $ (174) Concentrations of credit risk. At December 31, 2017 , the Company ’ s primary concentration s of credit risk are the risk of collec ting accounts receivable and the risk of counterparties ’ failure to perform under de rivative obligations. See Note 12 for in formation regarding the Company’ s major customers and derivative counterparties . The Company has entered into International Swap Dealers Association Master Agreements ( “ ISDA Agreements ” ) with each of its derivative counterparties. The te rms of the ISDA Agreements provide the Company and the co unterparties 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 8 for additional information regarding the Company ’ s derivative activities. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Impairments of long-lived assets – The Company periodical ly reviews its long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when t here are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amo unt of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the New York Mercantile Exc hange (“NYMEX”) strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At December 31, 2017 , the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2018 price of $59.55 per barrel of oil decreasing to a 2024 price of $51.82 per barrel of oil marginally recovering to a 2025 price of $51.83 per barrel of oil. Similarly, natural gas prices ranged from a 2018 price of $2.84 per Mcf of natural gas decreasing to a 2019 price of $2.81 per Mcf then rising to a 2025 price of $2.99 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after 2025. The Company did not recognize any impairment loss during the year ended December 31, 2017 . The Company calculates the es timated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses fr om integrated assets and (viii) discount rate. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. These are classified as Level 3 fair value assumptions. During the three months ended March 31, 2016, NYMEX strip prices declined as compared to December 31, 2015, and as a result the carrying amount of the Company’s Yeso field of approximately $3.4 billion exceeded the expected undiscounted future net cash flo ws resulting in a non-cash charge against earnings of approximately $ 1.5 billion. The non-cash charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets. The following table reports the carryi ng amount, estimated fair value and impairment expense of long-lived assets for the indicated period s : Estimated Carrying Fair Value Impairment (in millions) Amount (Level 3) Expense March 2016 $ 3,438 $ 1,913 $ 1,525 December 2015 $ 105 $ 52 $ 53 September 2015 $ 18 $ 10 $ 8 It is reasonably possible that the estimate of undiscounted future net cash flows of the Company’s long-lived assets may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity prices including differentials, (ii) increases or decreases in production and capital costs, (iii) future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets. |
Derivative financial instrument
Derivative financial instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative financial instruments | Note 8 . Derivative financial instruments The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i ) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also enters into fixed-price forward physical power purchase contracts to manage the volatility of the price of power needed for ongoing operations. The Compa ny may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical contracts are not expected to be net cash settled, the Company has elected normal purchase or normal sale treatment and are thus record ed at cost. The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its consolidated statements of operations as they occur. The followin g table summarizes the amounts r eported in earnings related to the commodity derivative instruments for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Gain (loss) on derivatives: Oil derivatives $ (172) $ (337) $ 675 Natural gas derivatives 46 (32) 25 Total $ (126) $ (369) $ 700 The following table represents the Company’s net cash receipts from derivatives for the years ended December 31, 2017, 2016 and 2015: Years Ended December 31, (in millions) 2017 2016 2015 Net cash receipts from derivatives: Oil derivatives $ 79 $ 609 $ 597 Natural gas derivatives - 16 36 Total $ 79 $ 625 $ 633 Commodity derivative contracts at December 31, 2017 . The following table sets forth the Company’s outstanding derivative contracts at December 31, 2017 . When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at December 31, 2017 are expected to settle by December 31, 2019 . First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Price Swaps: (a) 2018: Volume (Bbl) 10,123,629 8,965,170 7,931,318 7,432,007 34,452,124 Price per Bbl $ 52.05 $ 51.92 $ 51.65 $ 51.57 $ 51.82 2019: Volume (Bbl) 6,613,000 6,254,500 5,946,000 5,681,000 24,494,500 Price per Bbl $ 52.36 $ 52.33 $ 52.37 $ 52.36 $ 52.35 Oil Basis Swaps: (b) 2018: Volume (Bbl) 10,059,000 8,855,000 8,066,000 7,451,000 34,431,000 Price per Bbl $ (0.80) $ (0.88) $ (0.89) $ (0.93) $ (0.87) 2019: Volume (Bbl) 6,870,000 6,505,500 6,210,000 5,933,000 25,518,500 Price per Bbl $ (0.96) $ (0.98) $ (0.99) $ (1.01) $ (0.98) Natural Gas Price Swaps: (c) 2018: Volume (MMBtu) 16,556,000 16,101,000 14,819,000 14,504,000 61,980,000 Price per MMBtu $ 3.05 $ 3.04 $ 3.04 $ 3.03 $ 3.04 2019: Volume (MMBtu) 4,591,533 4,501,387 4,418,537 4,329,535 17,840,992 Price per MMBtu $ 2.86 $ 2.86 $ 2.86 $ 2.86 $ 2.86 (a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. (c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. The Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company. In September 2017, the Company elected to enter into an “Investment Grade Period” under the Credit Facility, as defined below, which had the effect of releasing all collateral formerly securing the Credit Facility . Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See Note 9 for additional informatio n regarding the Credit Facility . |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Note 9 . Debt The Company’s debt consisted of the following at December 31, 2017 and 2016 : December 31, (in millions) 2017 2016 Credit facility $ 322 $ - 5.5% unsecured senior notes due 2022 - 600 5.5% unsecured senior notes due 2023 - 1,550 4.375% unsecured senior notes due 2025 (a) 600 600 3.75% unsecured senior notes due 2027 1,000 - 4.875% unsecured senior notes due 2047 800 - Unamortized original issue premium (discount), net (6) 22 Senior notes issuance costs, net (25) (31) Less: current portion - - Total long-term debt $ 2,691 $ 2,741 (a) For each of the twelve month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are callable at 103.281%, 102.188%, 101.094% and 100%, respectively. Credit facility. The Company’s credit facility, as amended and restated (the “Credit Facility”), has a maturity date of May 9, 2022. At December 31, 2017 , the Company’s commitments from its bank group were $ 2.0 billion. In April 2017, the Company amended the Credit Facility to extend the maturity date, increase the borrowing base and decrease unused lender commitments. The amendment also lowered the corporate ratings floor sufficient to automatically terminate an Investment Grade Period under the Credit Facility from (i) “Ba1” to “Ba2” for Moody’s Investors Service, Inc. (“Moody’s”) and (ii) “BB+” to “BB” for S&P Global Ratings (“S&P”). The Company recorded a loss on extinguishment of debt of approximately $1 million for th e proportional amount of unamortized deferred loan costs associated with banks that are no longer in the Credit Facility syndicate as a result of the April 2017 amendment. In September 2017, the Company elected to enter into an Investment Grade Period und er the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of the Company’s credit ratings be low certain thresholds or by the Company’s election), the Credit Facility will once again be secured by a first lien on substantially all of the Company’s oil and natural gas properties and by a pledge of the equity interests in its subsidiaries. At December 31, 2017 , certain of the Company’s 100 percent owned subsidiaries are guarantors under the Credit Facility. During an Investment Grade Period, advances on the Credit Facility bear interest, at the Company’s option, based on (i) an alternative base rate , which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank (4.50 percent at December 31, 2017 ), (b) the federal funds effective rate plus 0.5 percent and (c) the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent or (ii) LIBOR. The Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on the Company’s credit ratings from Moody’s and S&P. At the Company’s current credit ratings, LIBOR Rate Loans and Alternate Base Rate Lo ans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum. During the years ended December 31, 2017 , 2016 and 2015 , the Company incurred commitment fees on the unused portion of the available commitments of $ 6 million, $ 8 million and $ 7 million, respectively. The Company had $ 1.7 billion of unused commitmen ts under the Credit F acility at December 31, 2017 . The Credit Facility contains various restrictive covenants and compliance requirements, which include: maintenance of certain financial ratios, including maintenance of a quarterly ratio of consolidat ed total debt to consolidated earnings, as defined, before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other non-cash income and expenses to be no greater than 4.25 to 1.0, and during an Investment Gra de Period, if the Company does not have both a rating of “Baa3” or better from Moody’s and a rating of “BBB-” or better from S&P, maintenance of a quarterly ratio of PV-9 of the Company’s oil and natural gas properties reflected in its most recently delive red reserve report to consolidated total debt to be no less than 1.50 to 1.0; limits on the incurrence of additional indebtedness and certain types of liens; restrictions as to mergers, combinations and dispositions of assets; and restrictions on the pa yment of cash dividends. Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note 16 . In September 2017, the Company issued $1,800 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “2017 Notes”). The 3.75% Notes were issued at a price equal to 99.636 percent of par, and the 4.875% Notes were issued at a price equal to 99.749 percent of par. Th e Company received net proceeds of approximately $1,777 million. Additionally, in September 2017, the Company completed a cash tender offer (the “Tender Offer”) to purchase any and all of the outstanding $600 million aggregate principal amount of its 5.5% unsecured senior notes due 2022 and the outstanding $1,550 million aggregate principal amount of its 5.5% unsecured senior notes due 2023 (collectively, the “5.5% Notes”). The Company received tenders from the holders of approximately $1,232 million in ag gregate principal amount, or approximately 57.3 percent, of its outstanding 5.5% Notes in connection with the Tender Offer at a price of 102.934 percent of the unpaid principal amount plus accrued and unpaid interest to the settlement date. In connection with the Tender Offer, the Company redeemed the remaining outstanding 5.5% Notes not purchased in the Tender Offer at a price, including the make-whole premium as determined in accordance with the indentures, of 102.75 percent of the unpaid principal amou nt plus accrued and unpaid interest. Additionally in September 2017, the Company completed a satisfaction and discharge of the redeemed notes, where the Company prepaid interest to October 13, 2017. The Company used the net proceeds from the offering of th e 2017 Notes, together with cash on hand and borrowings under its Credit Facility, to fund the Tender Offer and the satisfaction and discharge of its obligations under the indentures of the 5.5% Notes. In December 2016, the Company issued $600 million in aggregate principal amount of 4.375% senior notes due 2025 at par, for which it received net proceeds of approximately $592 million. The Company used the net proceeds from the offering to fund the satisfaction and discharge of its obligations under the ind enture of the $600 million outstanding principal amount of its 6.5% unsecured senior notes due 2022 (the “6.5% Notes”) at a price equal to 103.25 percent of par. The early extinguishment price included the make-whole premium as determined in accordance wit h the indenture governing the 6.5% Notes. In December 2016, the Company also paid interest of approximately $20 million on the 6.5% Notes through January 16, 2017. The Company recorded a loss on extinguishment of debt related to the 6.5% Notes of approxi mately $28 million for the year ended December 31, 2016. This amount includes $20 million associated with the make-whole premium paid for the early extinguishment of the notes, approximately $7 million of unamortized deferred loan costs and approximately $ 1 million of additional interest on the 6.5% Notes through January 16, 2017, which was paid in December 2016. In September 2016, the Company redeemed the $600 million outstanding principal amount of its 7.0% unsecured senior notes due 2021 (the “7.0% Note s”) at a price equal to 103.5 percent of par. The redemption price included the make-whole premium for the early redemption, as determined in accordance with the indenture governing the 7.0% Notes. The Company also paid accrued and unpaid interest on the 7 .0% Notes through September 19, 2016, the redemption date. The Company recorded a loss on extinguishment of debt related to the redemption of the 7.0% Notes of approximately $28 million for the year ended December 31, 2016. This amount includes $21 millio n associated with the make-whole premium paid for the early redemption of the notes and approximately $7 million of unamortized deferred loan costs. As a result of the transactions discussed above, the Company recorded a loss on extinguishment of debt for the year ended December 31, 2017 as follows: Credit Facility Senior Notes April 2017 September 2017 (in millions) Amendment Tender Offer Extinguishment Total Cash: Tender premium $ - $ 36 $ - $ 36 Make-whole premium - - 25 25 Prepaid interest - - 2 2 Total cash - 36 27 63 Non-cash: Unamortized original issue premium - (11) (8) (19) Unamortized deferred loan costs 1 12 9 22 Total non-cash 1 1 1 3 Total loss on extinguishment of debt $ 1 $ 37 $ 28 $ 66 At December 31, 2017, the Company was in compliance with the covenants under all of its debt instruments. Principal maturities of long-term debt. Principal maturities of long -term debt outstanding at December 31, 2017 were as follows: (in millions) 2018 $ - 2019 - 2020 - 2021 - 2022 322 Thereafter 2,400 Total $ 2,722 Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Cash payments for interest $ 139 $ 232 $ 211 Non-cash interest 6 9 9 Net changes in accruals 4 (37) - Interest costs incurred 149 204 220 Less: capitalized interest (3) - (5) Total interest expense $ 146 $ 204 $ 215 |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and contingencies | Note 10 . Commitments and contingencies Severance agreements. The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $ 8 million. Indemnifications . The Company has agreed to indemnify its directors and officers with respect to claims and damages arising from certain acts or omi ssions taken in such capacity. Legal actions . The Company is a party to 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 any such proceedings or cl aims 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 results of operations. The Company will continue to evaluate proceedings and claims involving the Comp any on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters. Severance tax, royalty and joint interest audits . The Company is subject to routine severance, royalty a nd joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from in terpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At December 31, 2016 , the Company h ad $ 7 million accrued for estimated exposur e that has since been satisfied . Although the Company bel ieves that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. C ommitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including drilling commitments, water commitment agreements, throughput volume delivery commitments, power commitments , fixed asset commitments and maintenance commitments. The following table summariz es the Company’s commitments at December 31, 2017 : (in millions) 2018 $ 33 2019 51 2020 33 2021 29 2022 26 Thereafter 84 Total $ 256 Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the year ended December 31, 2017 was approximately $ 10 million and approximately $ 8 million for each of the years ended December 31 , 2016 and 2015 , respectively . Future minimum lease commitments under non-cancellable operating leases at December 31, 2017 were as follows: (in millions) 2018 $ 10 2019 8 2020 7 2021 5 2022 - Thereafter 1 Total $ 31 |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income taxes | Note 11 . Income taxes T he Company uses an asset and liability approach for financial accounting and reporting for income taxes. T he Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income ta x return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to federal income tax laws , including a decrease in the federal corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018 . In accordance with the guidance stated in ASC 740, “Income Taxes,” the Company is required to account for t he effects of an enacted tax law or rate change in t he period of enactment, which is the date it is signed by the President . Set forth below is a discussion of certain provisions enacted by the TCJA and the Company’s assessment of the impact of such provis ions on its consolidated results. In accordance with SAB 118 , the Company has calculated its best estimate of the impact of the TCJA, including the federal statutory tax rate change noted ab ove, in accordance with its understanding of the TCJA and guidance available as of the date of this filing and as a result has recorded $ 398 million as a decrease to its income tax provision at December 31, 2017 . The provisional amount related to the re-measurement of certain deferred tax assets and liabilities, based on the rates at which they are expected to reverse in the future, was $ 398 million. The TCJA also repealed the corporate alternative minimum tax (“AMT”) for tax years beginning after December 31, 2017, and provides that existing AMT credit carryovers are refundable beginning with the 2018 tax year. The Company has approximately $ 10 million of AMT credit carryovers that are expected to be fully refu nded by 2022. At December 31, 2017 , the Company had current income tax receivable s of approximately $ 5 million . At December 31, 2017 , the Company did not have any significant uncertain tax positions requiring recognition in the fi nancial statements. The tax years 2013 through 2017 remain subject to examination by the major tax jurisdictions. The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Current: U.S. federal $ (6) $ (12) $ - U.S. state and local 2 - 1 Total current income tax expense (benefit) (4) (12) 1 Deferred: U.S. federal (94) (771) 40 U.S. state and local 23 (93) (10) Total deferred income tax expense (benefit) (71) (864) 30 Total income tax expense (benefit) attributable to income from operations $ (75) $ (876) $ 31 The reconciliation between the income tax expense (benefit) computed by multiplying pre-tax income (loss) from operations by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) from operations is as follows: Years Ended December 31, (in millions) 2017 2016 2015 Income (loss) at U.S. federal statutory rate $ 308 $ (818) $ 34 Provisional change in deferred tax assets and liabilities (398) - - State income taxes, net of federal tax effect 17 (41) 3 Revisions of previous estimates - 1 (1) Change in estimated effective statutory state income tax - (21) (9) Excess tax benefit related to stock-based compensation (6) - - Nondeductible expense and other 4 3 4 Income tax expense (benefit) $ (75) $ (876) $ 31 Effective tax rate (9)% 38% 32% The Company monitors changes in enacted tax rates for the jurisdictions in which it operates. The Company monitors its state tax apportionment footprint and makes updates for changes in its projected activity, including changes in budgets and drilling plans. During 2013, the S tate of New Mexico passed legislation to phase in a tax rate reduction over the next five years . In June of 2015, the State of Texas enacted legislation to reduce its rate. B ased upon the Company’s projected future activity for the states in which it conducts business, the timing for when it anticipates its deferred tax items to become taxable and enacted tax rates at such time deferred items become taxable, the Company did not revise its estimated state rate and , as such, did not r ecord an additional deferred state tax benefit during 2017 . The Company did revise its estimated state rate and recorded an additional deferred state tax benefit of approximately $ 21 million and $ 9 million during 2016 and 2015 , respectively. Th e Company recorded a discrete income tax benefit of approximately $6 million for the year ended December 31 , 2017 related to excess tax benefits on stock-based awards, which is recorded in the income tax provision pursuant to ASU No. 2016-09 adopted on January 1, 2017 . The Company’s 2017 effective tax rate de crease d as compared to 2016 primarily due to the provisional $ 398 million income tax benefit recognized as a result of the re-measurement of the Company’s net deferred tax liability based on changes enacted by the TCJA. This benefit more than offset the $ 308 million income tax expense on income before income taxes during 2017 at the federal statutor y rate. The Company’s effective tax rate increased in 2016 as compared to 2015 primarily due to a shi ft from pre-tax earnings of $97 million in 2015 to a pre-tax loss of $2.3 billion in 2016, resulting in a less pronounced effect on the effective tax rat e for each reconciling item. In particular, the reduction in the Company’s effective statutory state rate caused a 1 percent increase in 2016 as compared to a 9 percent reduction in 2015, partially offset by other reconciling and non-deductible items for a n et rate increase of 5 percent over 2015. At December 31, 2016, the Company had approximately $539 million of federal net operating losses (“NOLs”), of which $6 million was carried back to the 2014 tax year. During 2017, the Company projects it will util ize approximately $411 million of the remaining NOLs available of $533 million. At December 31, 2017, the Company had approximately $122 million of NOLs that will expire in 2036 but are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of limitations imposed by the TCJA. Additionally, the Company has estimated an apportioned New Mexico NOL of approximately $111 million expiring in 2036. The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows: December 31, (in millions) 2017 2016 Deferred tax assets: Stock-based compensation $ 18 $ 39 Derivative instruments 87 64 Asset retirement obligation 33 48 Net operating losses and credits 31 177 Other 13 24 Total deferred tax assets 182 352 Deferred tax liabilities: Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes (852) (1,095) Intangible assets (5) (9) Other (12) (14) Total deferred tax liability (869) (1,118) Net deferred tax liability $ (687) $ (766) The Company ha d net deferred tax liabilities of approximately $ 687 m illion and $ 766 m illion as of December 31, 2017 and 2016 , respectively. Pursuant to management’s assessment, the Company do es not believe a cumulative ownership change has o ccurred as of December 31, 2017 . As such, Section 382 of the Internal Revenue Code of 1986, as amended , is not expected to limit the Company’s ability to utilize its NOL carryfo rward as of December 31, 2017 . Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the lik elihood that the Company’s NOLs and other deferred tax attributes will be utilized prior to their expiration. At December 31, 2017 , management considered all factors including the expected reversal of deferred tax liabilities (includi ng the impact of available carry back and carryforward periods), historical operating income ta x planning strategies and pr ojected future taxable inc ome. Based on the results of the assessment, management determined that it is more likely than not that the Company will reali ze its deferred tax assets. |
Major customers and derivative
Major customers and derivative counterparties | 12 Months Ended |
Dec. 31, 2017 | |
Major Customer Disclosure [Abstract] | |
Major Customers and Derivative Counterparties [Text Block] | Note 12 . Major customers and derivative counterparties Sales to major customers. The Company’s share of oil and natural gas production is sold to various purchasers. The Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production. The following purchasers individually accounted for 10 percent or more of the consolidated oil and natural gas revenues during the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, 2017 2016 2015 Plains Marketing and Transportation, Inc. 21% 29% 11% Holly Frontier Refining and Marketing, LLC 10% 16% 25% Enterprise Crude Oil LLC 8% 7% 12% At December 31, 2017 , the Company had receivables from Plains Marketing & Transportation Inc., Holly Frontier Refining and Marketing, LLC and Enterprise Crude Oil LLC of $ 72 million, $ 36 million and $ 30 million , respectively, which are reflected in a ccounts receivable — oil and natural gas in the accompanying consolidated balance sheets. Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterpa rties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. The Company is not required to provide credit support or collateral to any counterparties under its derivative contra cts, nor are they required to provide credit support to the Company. In September 2017, the Company elected to enter into an “Investment Grade Period” under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives a re no longer secured. See Note 9 for ad ditional information regarding the Credit Facility. |
Related party transactions
Related party transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related party transactions | Note 13 . Related party transactions The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest. These payments were reported in the Company’s consolidated statements of operations and totaled approximately $ 7 million, $ 4 million and $ 6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively . |
Earnings per share
Earnings per share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract] | |
Net income per share | Note 14 . Earnings per share T he Company uses the two-class method of calculating earnings per share because certain of the Company’s unvested share-based awards qualify as participating secu rities. The Company’s basic earnings per share attributable to common stockholders is computed as ( i ) net income (loss) as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as ( i ) basic earnings attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding. The following table reconcile s the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per shar e amounts for the years ended December 31, 2017 , 2016 and 2015 , respectively, under the t wo-class method : Years Ended December 31, (in millions, except per share amounts) 2017 2016 2015 Net income (loss) as reported $ 956 $ (1,462) $ 66 Participating basic earnings (a) (7) - (1) Basic earnings attributable to common stockholders 949 (1,462) 65 Reallocation of participating earnings - - - Diluted earnings attributable to common stockholders $ 949 $ (1,462) $ 65 (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed 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. The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in thousands) 2017 2016 2015 Weighted average common shares outstanding: Basic 147,320 134,755 119,926 Dilutive common stock options 3 - 25 Dilutive performance units 633 - 422 Diluted 147,956 134,755 120,373 The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive: Years Ended December 31, (in thousands) 2017 2016 2015 Number of antidilutive common shares: Antidilutive performance units 81 - - |
Other current liabilities
Other current liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Other Liabilities Disclosure [Abstract] | |
Other current liabilities | Note 15 . Other current liabilities The following table provides the components of the Company’s other current liabilities at December 31, 2017 and 2016 : December 31, (in millions) 2017 2016 Other current liabilities: Accrued production costs $ 72 $ 63 Payroll related matters 40 35 Accrued interest 36 32 Settlements due on derivatives 25 - Asset retirement obligations 12 10 Other 31 12 Other current liabilities $ 216 $ 152 |
Subsidiary guarantors
Subsidiary guarantors | 12 Months Ended |
Dec. 31, 2017 | |
Guarantees [Abstract] | |
Subsidiary guarantors | Note 16 . Subsidiary guarantors At December 31, 2017 , certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Co mpany, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Compa ny to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee. See Note 9 for a summary of the Company’s senior notes. In accordance with practices accepted by the SEC, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiar ies as subsidiary guarantors. In addition, two of the Company’s subsidiaries do not guarantee the Company’s senior notes and are included in the Company’s consolidated financial statements . One of such entities is a VIE that was formed to effectuate a tax- free exchange of assets, and the other entity is a 100 percent owned subsidiary that was recently acquired. These entities are referred to as “Subsidiary Non-Guarantors” in the tables below. The following condensed consolidating balance s heets at December 31, 2017 and 2016 , condensed c o nsolidating statements of o perations and condensed consolidating statements of cash flows for the years ended December 31, 2017 , 2016 and 2015 , present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity meth od), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are reco rded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company. Condensed Consolidating Balance Sheet December 31, 2017 Parent Subsidiary Subsidiary Consolidating (in millions) Issuer Guarantors Non-Guarantors Entries Total ASSETS Accounts receivable - related parties $ 8,836 $ (669) $ - $ (8,167) $ - Other current assets 6 576 10 - 592 Oil and natural gas properties, net - 12,192 615 - 12,807 Property and equipment, net - 234 - - 234 Investment in subsidiaries 3,202 - - (3,202) - Other long-term assets 23 76 - - 99 Total assets $ 12,067 $ 12,409 $ 625 $ (11,369) $ 13,732 LIABILITIES AND EQUITY Accounts payable - related parties $ (669) $ 8,223 $ 613 $ (8,167) $ - Other current liabilities 341 821 3 - 1,165 Long-term debt 2,691 - - - 2,691 Other long-term liabilities 789 166 6 - 961 Equity 8,915 3,199 3 (3,202) 8,915 Total liabilities and equity $ 12,067 $ 12,409 $ 625 $ (11,369) $ 13,732 Condensed Consolidating Balance Sheet December 31, 2016 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total ASSETS Accounts receivable - related parties $ 8,991 $ (336) $ (8,655) $ - Other current assets 12 550 - 562 Oil and natural gas properties, net - 11,086 - 11,086 Property and equipment, net - 216 - 216 Investment in subsidiaries 1,989 - (1,989) - Other long-term assets 11 244 - 255 Total assets $ 11,003 $ 11,760 $ (10,644) $ 12,119 LIABILITIES AND EQUITY Accounts payable - related parties $ (336) $ 8,991 $ (8,655) $ - Other current liabilities 113 640 - 753 Long-term debt 2,741 - - 2,741 Other long-term liabilities 862 140 - 1,002 Equity 7,623 1,989 (1,989) 7,623 Total liabilities and equity $ 11,003 $ 11,760 $ (10,644) $ 12,119 Condensed Consolidating Statement of Operations For the Year Ended December 31, 2017 Parent Subsidiary Subsidiary Consolidating (in millions) Issuer Guarantors Non-Guarantors Entries Total Total operating revenues $ - $ 2,566 $ 20 $ - $ 2,586 Total operating costs and expenses (129) (1,366) (17) - (1,512) Income (loss) from operations (129) 1,200 3 - 1,074 Interest expense (145) (1) - - (146) Loss on extinguishment of debt (66) - - - (66) Other, net 1,221 19 - (1,221) 19 Income before income taxes 881 1,218 3 (1,221) 881 Income tax benefit 75 - - - 75 Net income $ 956 $ 1,218 $ 3 $ (1,221) $ 956 Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Total operating revenues $ - $ 1,635 $ - $ 1,635 Total operating costs and expenses (370) (3,334) - (3,704) Loss from operations (370) (1,699) - (2,069) Interest expense (202) (2) - (204) Loss on extinguishment of debt (56) - - (56) Other, net (1,710) (9) 1,710 (9) Loss before income taxes (2,338) (1,710) 1,710 (2,338) Income tax benefit 876 - - 876 Net loss $ (1,462) $ (1,710) $ 1,710 $ (1,462) Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Total operating revenues $ - $ 1,804 $ - $ 1,804 Total operating costs and expenses 697 (2,174) - (1,477) Income (loss) from operations 697 (370) - 327 Interest expense (213) (2) - (215) Other, net (387) (15) 387 (15) Income (loss) before income taxes 97 (387) 387 97 Income tax expense (31) - - (31) Net income (loss) $ 66 $ (387) $ 387 $ 66 Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2017 Parent Subsidiary Subsidiary Consolidating (in millions) Issuer Guarantors Non-Guarantors Entries Total Net cash flows provided by operating activities $ 145 $ 1,549 $ 1 $ - $ 1,695 Net cash flows used in investing activities - (1,105) (614) - (1,719) Net cash flows provided by (used in) financing activities (145) (497) 613 - (29) Net decrease in cash and cash equivalents - (53) - - (53) Cash and cash equivalents at beginning of period - 53 - - 53 Cash and cash equivalents at end of period $ - $ - $ - $ - $ - Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Net cash flows provided by (used in) operating activities $ (665) $ 2,049 $ - $ 1,384 Net cash flows used in investing activities - (2,225) - (2,225) Net cash flows provided by financing activities 665 - - 665 Net decrease in cash and cash equivalents - (176) - (176) Cash and cash equivalents at beginning of period - 229 - 229 Cash and cash equivalents at end of period $ - $ 53 $ - $ 53 Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Net cash flows provided by (used in) operating activities $ (1,394) $ 2,924 $ - $ 1,530 Net cash flows used in investing activities - (2,602) - (2,602) Net cash flows provided by (used in) financing activities 1,394 (93) - 1,301 Net increase in cash and cash equivalents - 229 - 229 Cash and cash equivalents at beginning of period - - - - Cash and cash equivalents at end of period $ - $ 229 $ - $ 229 |
Subsequent events
Subsequent events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent events | Note 17 . Subsequent events Southern Delaware Basin divestitures. In January 2018, the Company closed on two asset sales transactions of certain non-core asse ts in Reeves and Ward Counties with combined preliminary proceeds of approximately $280 million, subject to customary post-closing adjustment s . As of December 31, 2017, the Company received cash deposits totaling approximately $29 million for the asset sales, which was included in the total cash flows from investing act ivities in its consolidated statement of cash flows. The assets divested included proved and unproved oil and natural gas pr operties on approximately 20 ,000 net acres. This completed the Reverse 1031 Exchange discussed in Note 4 . February 2018 non monetary transaction. In February 2018, the Company closed on a trade where it received approximately 21,000 net acres , primarily located in the Midland Basin, with current production of 5 MBoepd in exchange for approximately 34,000 net acres, primarily comprised of approximately 32,000 net acres in the northern Delaware Basin, with current production of 3 MBoepd. New commodity derivative contracts. After December 31, 2017 , the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Price Swaps: (a) 2018: Volume (Bbl) 915,000 1,213,000 1,013,000 674,000 3,815,000 Price per Bbl $ 63.64 $ 63.48 $ 63.34 $ 63.11 $ 63.42 2019: Volume (Bbl) 876,000 748,000 636,000 552,000 2,812,000 Price per Bbl $ 58.14 $ 58.12 $ 58.10 $ 58.08 $ 58.11 2020: Volume (Bbl) 1,001,000 1,001,000 1,012,000 1,012,000 4,026,000 Price per Bbl $ 54.80 $ 54.80 $ 54.80 $ 54.80 $ 54.80 Oil Basis Swaps: (b) 2018: Volume (Bbl) 615,000 637,000 399,000 306,000 1,957,000 Price per Bbl $ 0.13 $ 0.06 $ (0.07) $ (0.10) $ 0.03 2019: Volume (Bbl) 180,000 182,000 184,000 - 546,000 Price per Bbl $ (0.27) $ (0.27) $ (0.27) $ - $ (0.27) 2020: Volume (Bbl) 2,184,000 2,184,000 2,208,000 2,208,000 8,784,000 Price per Bbl $ (0.09) $ (0.09) $ (0.09) $ (0.09) $ (0.09) Natural Gas Price Swaps: (c) 2018: Volume (MMBtu) 1,277,000 878,000 921,000 274,000 3,350,000 Price per MMBtu $ 3.08 $ 3.08 $ 3.08 $ 3.08 $ 3.08 (a) The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. (c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. |
Summary of significant accoun25
Summary of significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Principles of consolidation | Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also include the accounts of a variable interest en tity (“VIE”) where the Company wa s the primary beneficiary of the arrangements during the year ended December 31, 2017 . See Note 4 for additional information regarding the circumstances surrounding the VIE. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated. |
Reclassifications | R eclassifications. Certain prior period amounts have been reclassified to conform to the 2017 presentation. These reclassifications had no im pact on net income (loss), total stockholders’ equity or total cash flows. |
Use of estimates in the preparation of financial statements | Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America 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. Actual results could differ from the se estimates. Depletion of oi l and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rat es of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves , commodity price outlooks and prevailing market rates of other sources of income and costs . Other significant estimates inclu de, but are not limited to, asset retirement obligations, fair value of stock-based compensation , fair value of business combinati ons, fair value of nonmonetary transactions, fair value of de rivative financial instruments and income taxes . |
Cash equivalents | Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an origin al maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believe s that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, 2016, the majority of the Company’s cash was invested in stable value government money market funds. |
Accounts receivable | Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Oil and natural gas sales receivables related to these operations are generally unsecured. Jo int interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due dat e. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $ 1 million for each of the year s ended December 31, 2017 and 2016 . |
Inventory | Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost o r net realizable value, on a weighted average cost basis . |
Oil and natural gas properties | Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integra ted assets is based on the unit-of-production method using proved dev eloped reserves . During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized depletion expense from operations of $ 1,122 million, $ 1,145 mi llion and $ 1,203 million, respectively. The Company generally 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 ar e met: the well has found a sufficient quantity of reserves to justify its completion as a producing well; and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the Company’s l arge multi-well project development program, capital intensive nature and geographical location of certain projects, it may take longer than one year to evaluate the future potential of the exploration well and economics associated with making a determinat ion on its commercial viability. In these instances, the project ’ s feasibility is not contingent upon price improvements or advances in technology, but rather the C ompany’ s ongoing efforts and expenditures related to accurately predicting the hydrocarbon r ecoverability based on well information, ga ining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued consta ntly. Consequently, the Company’ s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves and is transferred to proved oil and natural gas properties or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional in formation regarding the Company’ s suspended exploratory well costs. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or a bandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disp osition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred. Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects ar e ready for their intended use. During the y ears ended December 31, 2017 and 2015 , the Company had capitalized interest of approximately $ 3 million and $ 1 million, respectively. The Company did not have capitalized interes t related to significant oil and natural gas development projects for the year ended December 31, 2016 . The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances ind icate 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 is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment lo ss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base . For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized a t that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital e xpenditures and production costs and cash flows from integrated assets . The Compan y recognized impairment expense of approximately $ 1.5 b illion and $ 61 million duri ng the years ended December 31, 2016 and 2015 , respectively, related to its proved oil and natural gas properties. The Company did not recognize impairment expense during the year ended December 31, 2017 . See Note 7 for additional in formation regarding the Company’ s impairment expense . Unpro ved oil and natural gas properties are periodically assessed for impairment by consid ering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the pr ojects. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized expense of approximately $ 29 million, $ 60 million and $ 35 million, respectively, related to abandoned and expiring acreage , which is included in exploration and abandonments expense in the accompanying consolidated statements of operations. |
Other property and equipment | Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of a ssets ranging from two to 39 years. The Company had other capital assets of $ 234 million and $ 216 million, net of accumulated depreciation of $ 90 million and $ 74 million, at December 31, 2017 a nd December 31, 2016 , respectively. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized depreciation expense of $ 21 million, $ 21 million and $ 19 million, respectively. Dur ing the y ear ended December 31, 2015 , the Company had capitalized interest of approximately $ 1 million. The Company did not have capitalized interest related to other property and equipment during the years ended December 31, 2017 or 2016 . |
Funds held in escrow | Funds held in escrow. At December 31, 2016 , the Company’s funds held in escrow totaled $43 million, which consisted of a deposit paid by the Company that was held in escrow for its Northern Delaware Basin acquisition. See Note 4 for additional information regarding the acquisition . |
Deferred loan costs | Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is computed using the straight-line method. The Company had deferred loan costs related to its credit facility o f $ 13 million and $ 11 million, net of accumulated amortization of $ 51 million and $ 56 million, in noncurrent assets at December 31, 2017 and 2016 , respectively. |
Intangible assets | Intangible assets. The Company has capitalized certain rights acquired through acquisition s . The gross intangible assets , which have no residual value, are amortized over the estimated economic life of three to 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life . The following table reflects the gross and net intangible assets at December 31, 2017 and 2016 , respectively : December 31, (in millions) 2017 2016 Gross intangibles $ 42 $ 37 Accumulated amortization (16) (13) Net intangibles $ 26 $ 24 The Company recognized amortization expense of approximately $3 million for the year ended December 31, 2017 and approximately $1 million for each of the years ended December 31, 2016 and 2015 . The Company will record amortization expense of approximately $3 million for the year ended December 31, 2018 and approximately $1 million for each of the remaining years under the term. |
Equity method investments | Equity method investments. Equity method investments are included in other assets in the Company’s consolidated balance sheets . Income and losses incurred from the Company’s equity investments are recorded in other income (expense) in its consolidated statements of operations. At December 31, 2016, the Company owned a 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the N orthern Delaware Basin. The Company’s net investment in ACC was approximately $ 129 million at December 31, 2016 . During th e years ended December 31, 2016 and 2015 , the Company recorded a loss of approximately $ 2 million and $ 4 million, respectively. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. See Note 4 for additional information regarding the disposition of ACC. The Company owns a membership interest in Oryx Southern Delawar e Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering an d transportation system in the S outhern Delaware Basin. During 2017, the Company’s membership interest was reduced from 25 percent to 23.75 percent after the addition of a new partne r. The Company’s net investment was approximately $ 49 million and $ 42 million at December 31, 2017 and 2016 , respectively . During the years ended December 31, 2017 and 2016 , the Company recorded income of appro ximately $ 7 million and a loss of approximately $ 2 million, respectively . |
Environmental | Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing , regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probab le and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash paymen ts is fixed and readily determinable. At December 31, 2017 and 2016 , the Company has accrued approximately $ 3 million and $ 1 million, respectively, related to environmental liabilities. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized environmental charges of approximately $ 9 million, $ 7 million and $ 3 million, respectively. |
Senior note deferred loan costs | Senior note deferred loan costs. Senior note de ferred loan costs are stated at cost, net of amortization, which is computed using the effective interest method. The Company had senior n ote deferred loan costs of $ 25 million and $ 31 million, net of accumulated amortization of $ 1 million and $ 12 million, as a reduction of long-term debt at December 31, 2017 a nd 2016 , respectively. See Note 9 for additional information regarding activity related to the Company’s senior notes. |
Income taxes | Income taxes. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributabl e to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years i n which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is establis hed to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. On December 22, 2017, the President of the United States (“the President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” ( “TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”) to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allows companies to report provisional amounts when based on reason able estimates and to adjust these amounts during a measurement period of up to one year. The Company has elected to apply SAB 118 and, as such, has recorded provisional amounts for the income tax balances reported in its consolidated financial statements. The Company will continue to monitor any new administrative guidance or tax law interpretation. See Note 11 for additional information regarding the Company’s deferred tax balances and its accounting for the impacts of the TCJA. |
Income taxes uncertainties | The Company evaluates uncertain tax positions for recognition and measurement in the cons olidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the te chnical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consol idated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of b enefit that is greater than 50 percent likely of b eing realized upon settlement. The Company had no material uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2017 or 2016 . Any interest or pena lties would be recognized as a component of income tax expense. |
Derivative instruments | Derivative instruments. The Company recognizes its derivative instruments , other than any commodity derivative contracts that are designated as normal purchase and normal sale, as either assets or liabilities measured at fair value. The Company netted the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical del ivery contracts to effectively provide commodity price hedges. Because these contracts are not expec ted to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company ’s consolidated financial statements. |
Asset retirement obligations | Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the relat ed long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increas e in the carrying amount of the liability and as corresponding accretion expense. Based on certain factors including commodity prices and costs, the Company may revise its previous estimates related to the liability, which would also increase or decrease t he associated oil and natural gas property asset. |
Treasury stock | Treasury stock. Treasury stock purchases are recorded at cost. |
Revenue recognition | Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser , which for the Company is primarily at the wellhead . The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers. |
Oil and natural gas imbalances | Oil and natural gas i mbalances. Oil and n atural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. I mbalances are tracked by well ; ho wever, the Company does not record any receivable from or payable to the other owners unless the imbalance has reached a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the C ompany is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance. The Company had no significant imbalances at December 31, 2017 or 2016 . |
General and administrative expense | General and administrative expense . The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $ 16 million, $ 17 million and $ 19 million for the years e nded December 31, 2017 , 2016 and 2015 , respectively. |
Stock-based compensation | Stock-based compensation. S tock-based compensation expense is recognized in the Company’ s financial statements on a n accelerated basis over the awards’ vesting periods based on their grant date fair values. S tock-based compensation awards generally vest over a period ranging from one to eight years. The Company utilizes the average of the grant date’s hi gh and low stock price s for the fair value of restricted stock and the Monte Carlo simulation method for the fair value of performance unit awards. |
Recent accounting pronouncements | Recent ly adopted accounting pronouncements. The Company adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” on January 1, 2017. The adoption did not have an impact on prior period consolidated financial statements. The Company elected to account for forfeitures of share-based payments as they occur. At December 31, 2016, the Company had not recorded compensation expense of approximately $8 million based on forecasted forfeitures nor the associated deferred tax benefit of approximately $3 million. Addi tionally, t he Company recognized all excess tax benefits not previously recorded, which totaled approximately $5 million at December 31, 2016. Upon adoption, the Company recorded a cumulative-effect adjustment, which decreased retained earnings by less tha n $1 million, increased additional paid-in capital by approximately $8 million, and de creased net deferred income tax liabilities by approximately $8 million. The Company elected to prospectively classify excess tax benefits and deficiencies as operating a ctivities on the consolidated statements of cash flows and will prospectively record those excess tax benefits and deficiencies as discrete items in the income tax provision in the consolidated statements of operations. Under the new standard, for the year ended December 31, 2017 , the Company recorded excess tax benefits of approximately $ 6 million in the Company’s income tax provision. Also under the new standard, for the year ended December 31 , 2017, the Company recorded actual forfeitures of share- bas ed payments of approximately $ 8 million. New accounting pronouncements issued but not yet adopted . In May 2014, the Financial Accounting Standards Board (the “ FASB ”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlin es a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model prov ides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU No. 2014-09 by one year. That ne w standard is now effective for annual reporting periods beginning after December 15, 2017. The Company has completed its evaluation and implementation of ASU No. 2014-09 and will adopt the new revenue recognition guidance during the first quarter of 2018. The Company has elected to use the modified retrospective method for adoption. Upon adoption, the Company will not record a material cumulative effect adjustment and prior period financial statements will not be restated. The adoption of this guidanc e is not expected to have an ongoing material impact on the Company’s financial statements. More specifically, the adoption of this guidance will result in changes to sales of oil and natural gas and operating expenses due to the conclusion that some third -parties meet the definition of an agent under the control model in ASC 606, thus the fees paid to these service providers will be classified as operating expenses under ASC 606. With the adoption, the Company has updated its revenue recognition policy and its related internal control documentation, processes and controls to conform to the new standard. The Company will also expand its revenue recognition related disclosures. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which su persedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense re cognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company does not plan to early adopt the standard . The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. The Company is substantially complete with the process of revi ewing and determining the contracts to which this new guidance applies. The Company is currently enhancing its accounting system in order to track and calculate additional information necessary for adoption of this standard. The Company believes this new g uidance will have a moderate impact to its consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under currently applicable guidance. In June 2016, the FASB issued ASU No. 2016-1 3, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requ ires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This gui dance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” with the objective of adding guidance to assist in evaluating whether transactions should be accounted fo r as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. The Company does not believe this new guidance will have a material impact on its consolidated financial statements. |
Summary of significant accoun26
Summary of significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Finite-Lived Intangible Assets [Table Text Block] | The following table reflects the gross and net intangible assets at December 31, 2017 and 2016 , respectively : December 31, (in millions) 2017 2016 Gross intangibles $ 42 $ 37 Accumulated amortization (16) (13) Net intangibles $ 26 $ 24 |
Exploratory well costs (Tables)
Exploratory well costs (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract] | |
Company's capitalized exploratory well activity | The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Beginning capitalized exploratory well costs $ 151 $ 116 $ 242 Additions to exploratory well costs pending the determination of proved reserves 180 144 103 Reclassifications due to determination of proved reserves (147) (86) (228) Exploratory well costs charged to expense - (6) (1) Disposition of wells (2) (17) - Ending capitalized exploratory well costs $ 182 $ 151 $ 116 |
Aging of capitalized exploratory well costs based on the date drilling was completed | The following table provides an aging at December 31, 2017 and 2016 of capitalized exploratory well costs based on the date drilling was completed: December 31, (in millions, except number of projects) 2017 2016 Capitalized exploratory well costs that have been capitalized for a period of one year or less $ 180 $ 141 Capitalized exploratory well costs that have been capitalized for a period greater than one year 2 10 Total capitalized exploratory well costs $ 182 $ 151 Number of projects with exploratory well costs that have been capitalized for a period greater than one year 2 8 |
Acquisitions, divestitures an28
Acquisitions, divestitures and nonmonetary transactions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions, divestitures and nonmonetary transactions [Abstract] | |
Estimated fair value of the acquired assets and liabilities | The following table reflects the fair value of the acquired assets and liabilities at the October 2016 closing date associated with the Reliance Acquisition: (in millions) Fair value of net assets: Proved oil and natural gas properties $ 730 Unproved oil and natural gas properties 972 Other assets 34 Total assets acquired 1,736 Current liabilities, including current portion of asset retirement obligations (8) Asset retirement obligations assumed (12) Fair value of net assets acquired $ 1,716 Fair value of consideration paid for net assets: Cash consideration $ 1,176 Non-cash consideration, including equity 540 Total consideration paid for net assets $ 1,716 |
Business Acquisition, Pro Forma Information [Table Text Block] | The following unaudited pro forma combined condensed financial data for the year ended December 31, 2016 was derived from the historical financial statements of the Company giving effect to the Reliance Acquisition, as if it had occurred on January 1, 2016 . The results of operations for the Reliance Acquisition are included in the Company’s results of operations since the closing date in October 2016 through December 31, 2017 . The pro forma financial data does not include the results of operations for a ny other acquisitions made during the periods presented , as they were primarily acreage acquisitions and their results were not deemed material. The unaudited pro forma combined condensed financial data has been included for comparat ive purposes only and is not necessarily indicative of the results that might have occurred had the Reliance Acquisition taken place as of the date indicated and is not intended to be a projection of future results . Year Ended (in millions, except per share amounts) December 31, 2016 (unaudited) Operating revenues $ 1,717 Net loss $ (1,396) Earnings per common share: Basic net loss $ (10.36) Diluted net loss $ (10.36) |
Asset retirement obligations (T
Asset retirement obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations | The Company’s asset retirement obligation transactions during the years ended December 31, 2017 , 2016 and 2015 are summarized in the table below: Years Ended December 31, (in millions) 2017 2016 2015 Asset retirement obligations, beginning of period $ 130 $ 120 $ 120 Liabilities incurred from new wells 2 2 4 Liabilities assumed in acquisitions 10 13 2 Accretion expense 8 7 8 Disposition of wells (1) (11) - Liabilities settled upon plugging and abandoning wells (5) (1) (3) Revision of estimates (a) (3) - (11) Asset retirement obligations, end of period $ 141 $ 130 $ 120 (a) The revisions to the Companyʼs asset retirement obligation estimates for the years ended December 31, 2017 and 2015 are primarily due to a reduction in the future estimated abandonment costs. |
Incentive plans (Tables)
Incentive plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of the Company's restricted stock awards activity | A summary of the Company’s restricted stock award activity for the year ended D ecember 31, 2017 is presented below: Weighted Average Number of Grant Date Restricted Fair Value Shares Per Share Restricted stock: Outstanding at December 31, 2016 1,157,270 $ 115.29 Shares granted 490,300 $ 123.16 Shares cancelled / forfeited (100,199) $ 113.56 Lapse of restrictions (398,125) $ 117.91 Outstanding at December 31, 2017 1,149,246 $ 118.02 |
Summarizes information about stock-based compensation for the Company's restricted stock awards activity under the Plan | The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Fair value for awards granted during the period (a) $ 60 $ 51 $ 50 Fair value for awards vested during the period $ 49 $ 45 $ 36 Stock-based compensation expense from restricted stock $ 43 $ 41 $ 43 Income tax benefit related to restricted stock $ 11 $ 15 $ 16 (a) The weighted average grant date fair value per share amounts were $123.16, $112.78 and $109.76 for the years ended December 31, 2017, 2016 and 2015, respectively. |
Summary of the Company's stock option awards activity under the Plan | A summary of the Company’s stock option award activity under the Plan for the year ended December 31, 2017 is presented below: Weighted Average Number of Exercise Options Price Stock options: Outstanding at December 31, 2016 20,000 $ 15.33 Options exercised (20,000) $ 15.33 Outstanding at December 31, 2017 - Vested and exercisable at December 31, 2017 - |
Summarizes the assumptions to estimate the fair value of performance units granted | The Com pany used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, 2017 2016 2015 Risk-free interest rate 1.47% 1.31% 1.07% Range of volatilities 24.8% - 60.2% 31.6% - 59.0% 26.1% - 43.0% |
Summary of the Company's performance unit activity | The following table summarizes the performance unit activity for the year ended December 31, 2017 : Number of Grant Date Units Fair Value Performance units: Outstanding at December 31, 2016 331,526 $ 136.68 Units granted (a) 108,398 $ 183.48 Units forfeited (43,333) $ 140.00 Units vested (b) (148,944) $ 156.86 Outstanding at December 31, 2017 247,647 $ 146.10 (a) Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period. (b) On December 31, 2017, the performance period ended for these performance units. Each unit converted into three shares representing 446,832 shares of common stock issued on January 2, 2018. |
Summarizes information about stock-based compensation for the Company's performance unit awards activity under the Plan | The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Fair value for awards granted during the period (a) $ 20 $ 19 $ 28 Fair value for awards vested during the period $ 68 $ 33 $ 16 Stock-based compensation expense from performance units $ 17 $ 18 $ 20 Income tax benefit related to performance units $ 2 $ 7 $ 7 (a) The weighted average grant date fair value per unit amounts were $183.48, $114.81 and $156.86 for the years ended December 31, 2017, 2016 and 2015, respectively. |
Future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding | The following table reflects the future stock-based compensation expense to be recorded for all the stock-bas ed compensation awards that we re outstanding at December 31, 2017 : (in millions) 2018 $ 49 2019 26 2020 8 Thereafter 2 Total $ 85 |
Disclosures about fair value 31
Disclosures about fair value measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Carrying amounts and fair values of the Company's financial instruments | The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 Carrying Fair Carrying Fair (in millions) Value Value Value Value Assets: Derivative instruments $ - $ - $ 4 $ 4 Liabilities: Derivative instruments $ 379 $ 379 $ 178 $ 178 Credit facility $ 322 $ 322 $ - $ - $600 million 5.5% senior notes due 2022 (a) $ - $ - $ 594 $ 620 $1,550 million 5.5% senior notes due 2023 (a) $ - $ - $ 1,555 $ 1,621 $600 million 4.375% senior notes due 2025 (a) $ 593 $ 624 $ 592 $ 599 $1,000 million 3.75% senior notes due 2027 (a) $ 987 $ 1,012 $ - $ - $800 million 4.875% senior notes due 2047 (a) $ 789 $ 874 $ - $ - (a) The carrying value includes associated deferred loan costs and any premium (discount). |
Net basis derivative fair values as reported in the consolidated balance sheets | The following tables summarize ( i ) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, 2017 and 2016 . The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets. December 31, 2017 Fair Value Measurements Using Net Quoted Prices Gross Fair Value in Active Significant Amounts Presented Markets for Other Significant Offset in the in the Identical Observable Unobservable Total Consolidated Consolidated Assets Inputs Inputs Fair Balance Balance (in millions) (Level 1) (Level 2) (Level 3) Value Sheet Sheet Assets Current: Commodity derivatives $ - $ 13 $ - $ 13 $ (13) $ - Noncurrent: Commodity derivatives - 1 - 1 (1) - Liabilities Current: Commodity derivatives - (290) - (290) 13 (277) Noncurrent: Commodity derivatives - (103) - (103) 1 (102) Net derivative instruments $ - $ (379) $ - $ (379) $ - $ (379) December 31, 2016 Fair Value Measurements Using Net Quoted Prices Gross Fair Value in Active Significant Amounts Presented Markets for Other Significant Offset in the in the Identical Observable Unobservable Total Consolidated Consolidated Assets Inputs Inputs Fair Balance Balance (in millions) (Level 1) (Level 2) (Level 3) Value Sheet Sheet Assets Current: Commodity derivatives $ - $ 59 $ - $ 59 $ (55) $ 4 Noncurrent: Commodity derivatives - - - - - - Liabilities Current: Commodity derivatives - (137) - (137) 55 (82) Noncurrent: Commodity derivatives - (96) - (96) - (96) Net derivative instruments $ - $ (174) $ - $ (174) $ - $ (174) |
Carrying amounts, estimated fair values and impairment expense of long-lived assets | Estimated Carrying Fair Value Impairment (in millions) Amount (Level 3) Expense March 2016 $ 3,438 $ 1,913 $ 1,525 December 2015 $ 105 $ 52 $ 53 September 2015 $ 18 $ 10 $ 8 |
Derivative financial instrume32
Derivative financial instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments | The followin g table summarizes the amounts r eported in earnings related to the commodity derivative instruments for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Gain (loss) on derivatives: Oil derivatives $ (172) $ (337) $ 675 Natural gas derivatives 46 (32) 25 Total $ (126) $ (369) $ 700 The following table represents the Company’s net cash receipts from derivatives for the years ended December 31, 2017, 2016 and 2015: Years Ended December 31, (in millions) 2017 2016 2015 Net cash receipts from derivatives: Oil derivatives $ 79 $ 609 $ 597 Natural gas derivatives - 16 36 Total $ 79 $ 625 $ 633 |
Company's outstanding derivative contracts | Commodity derivative contracts at December 31, 2017 . The following table sets forth the Company’s outstanding derivative contracts at December 31, 2017 . When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at December 31, 2017 are expected to settle by December 31, 2019 . First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Price Swaps: (a) 2018: Volume (Bbl) 10,123,629 8,965,170 7,931,318 7,432,007 34,452,124 Price per Bbl $ 52.05 $ 51.92 $ 51.65 $ 51.57 $ 51.82 2019: Volume (Bbl) 6,613,000 6,254,500 5,946,000 5,681,000 24,494,500 Price per Bbl $ 52.36 $ 52.33 $ 52.37 $ 52.36 $ 52.35 Oil Basis Swaps: (b) 2018: Volume (Bbl) 10,059,000 8,855,000 8,066,000 7,451,000 34,431,000 Price per Bbl $ (0.80) $ (0.88) $ (0.89) $ (0.93) $ (0.87) 2019: Volume (Bbl) 6,870,000 6,505,500 6,210,000 5,933,000 25,518,500 Price per Bbl $ (0.96) $ (0.98) $ (0.99) $ (1.01) $ (0.98) Natural Gas Price Swaps: (c) 2018: Volume (MMBtu) 16,556,000 16,101,000 14,819,000 14,504,000 61,980,000 Price per MMBtu $ 3.05 $ 3.04 $ 3.04 $ 3.03 $ 3.04 2019: Volume (MMBtu) 4,591,533 4,501,387 4,418,537 4,329,535 17,840,992 Price per MMBtu $ 2.86 $ 2.86 $ 2.86 $ 2.86 $ 2.86 (a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. (c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Company's debt | Note 9 . Debt The Company’s debt consisted of the following at December 31, 2017 and 2016 : December 31, (in millions) 2017 2016 Credit facility $ 322 $ - 5.5% unsecured senior notes due 2022 - 600 5.5% unsecured senior notes due 2023 - 1,550 4.375% unsecured senior notes due 2025 (a) 600 600 3.75% unsecured senior notes due 2027 1,000 - 4.875% unsecured senior notes due 2047 800 - Unamortized original issue premium (discount), net (6) 22 Senior notes issuance costs, net (25) (31) Less: current portion - - Total long-term debt $ 2,691 $ 2,741 (a) For each of the twelve month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are callable at 103.281%, 102.188%, 101.094% and 100%, respectively. |
Loss on extinguishment of debt | As a result of the transactions discussed above, the Company recorded a loss on extinguishment of debt for the year ended December 31, 2017 as follows: Credit Facility Senior Notes April 2017 September 2017 (in millions) Amendment Tender Offer Extinguishment Total Cash: Tender premium $ - $ 36 $ - $ 36 Make-whole premium - - 25 25 Prepaid interest - - 2 2 Total cash - 36 27 63 Non-cash: Unamortized original issue premium - (11) (8) (19) Unamortized deferred loan costs 1 12 9 22 Total non-cash 1 1 1 3 Total loss on extinguishment of debt $ 1 $ 37 $ 28 $ 66 |
Principal maturities of debt | Principal maturities of long -term debt outstanding at December 31, 2017 were as follows: (in millions) 2018 $ - 2019 - 2020 - 2021 - 2022 322 Thereafter 2,400 Total $ 2,722 |
Interest expense | The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Cash payments for interest $ 139 $ 232 $ 211 Non-cash interest 6 9 9 Net changes in accruals 4 (37) - Interest costs incurred 149 204 220 Less: capitalized interest (3) - (5) Total interest expense $ 146 $ 204 $ 215 |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of the Company's future commitments | The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including drilling commitments, water commitment agreements, throughput volume delivery commitments, power commitments , fixed asset commitments and maintenance commitments. The following table summariz es the Company’s commitments at December 31, 2017 : (in millions) 2018 $ 33 2019 51 2020 33 2021 29 2022 26 Thereafter 84 Total $ 256 |
Future minimum lease commitments under non-cancellable operating leases | Future minimum lease commitments under non-cancellable operating leases at December 31, 2017 were as follows: (in millions) 2018 $ 10 2019 8 2020 7 2021 5 2022 - Thereafter 1 Total $ 31 |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Company's income tax expense (benefit) attributable to income from continuing operations | The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in millions) 2017 2016 2015 Current: U.S. federal $ (6) $ (12) $ - U.S. state and local 2 - 1 Total current income tax expense (benefit) (4) (12) 1 Deferred: U.S. federal (94) (771) 40 U.S. state and local 23 (93) (10) Total deferred income tax expense (benefit) (71) (864) 30 Total income tax expense (benefit) attributable to income from operations $ (75) $ (876) $ 31 |
reconciliation between the income tax expense (benefit) computed by multiplying pretax income (loss) from operations | The reconciliation between the income tax expense (benefit) computed by multiplying pre-tax income (loss) from operations by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) from operations is as follows: Years Ended December 31, (in millions) 2017 2016 2015 Income (loss) at U.S. federal statutory rate $ 308 $ (818) $ 34 Provisional change in deferred tax assets and liabilities (398) - - State income taxes, net of federal tax effect 17 (41) 3 Revisions of previous estimates - 1 (1) Change in estimated effective statutory state income tax - (21) (9) Excess tax benefit related to stock-based compensation (6) - - Nondeductible expense and other 4 3 4 Income tax expense (benefit) $ (75) $ (876) $ 31 Effective tax rate (9)% 38% 32% |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows: December 31, (in millions) 2017 2016 Deferred tax assets: Stock-based compensation $ 18 $ 39 Derivative instruments 87 64 Asset retirement obligation 33 48 Net operating losses and credits 31 177 Other 13 24 Total deferred tax assets 182 352 Deferred tax liabilities: Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes (852) (1,095) Intangible assets (5) (9) Other (12) (14) Total deferred tax liability (869) (1,118) Net deferred tax liability $ (687) $ (766) |
Major customers and derivativ36
Major customers and derivative counterparties (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Major Customer Disclosure [Abstract] | |
Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block] | The following purchasers individually accounted for 10 percent or more of the consolidated oil and natural gas revenues during the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, 2017 2016 2015 Plains Marketing and Transportation, Inc. 21% 29% 11% Holly Frontier Refining and Marketing, LLC 10% 16% 25% Enterprise Crude Oil LLC 8% 7% 12% |
Earnings per share (Tables)
Earnings per share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract] | |
Reconciliation of earnings attributable to common shares, basic and diluted | The following table reconcile s the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per shar e amounts for the years ended December 31, 2017 , 2016 and 2015 , respectively, under the t wo-class method : Years Ended December 31, (in millions, except per share amounts) 2017 2016 2015 Net income (loss) as reported $ 956 $ (1,462) $ 66 Participating basic earnings (a) (7) - (1) Basic earnings attributable to common stockholders 949 (1,462) 65 Reallocation of participating earnings - - - Diluted earnings attributable to common stockholders $ 949 $ (1,462) $ 65 (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed 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. |
Reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding | The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, (in thousands) 2017 2016 2015 Weighted average common shares outstanding: Basic 147,320 134,755 119,926 Dilutive common stock options 3 - 25 Dilutive performance units 633 - 422 Diluted 147,956 134,755 120,373 |
Summary of the performance units that were not included in the computation of diluted net income per share | The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive: Years Ended December 31, (in thousands) 2017 2016 2015 Number of antidilutive common shares: Antidilutive performance units 81 - - |
Other current liabilities (Tabl
Other current liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Liabilities Disclosure [Abstract] | |
components of the Company's other current liabilities | The following table provides the components of the Company’s other current liabilities at December 31, 2017 and 2016 : December 31, (in millions) 2017 2016 Other current liabilities: Accrued production costs $ 72 $ 63 Payroll related matters 40 35 Accrued interest 36 32 Settlements due on derivatives 25 - Asset retirement obligations 12 10 Other 31 12 Other current liabilities $ 216 $ 152 |
Subsidiary guarantors (Tables)
Subsidiary guarantors (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Guarantees [Abstract] | |
Condensed Consolidating Balance Sheet | The following condensed consolidating balance s heets at December 31, 2017 and 2016 , condensed c o nsolidating statements of o perations and condensed consolidating statements of cash flows for the years ended December 31, 2017 , 2016 and 2015 , present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity meth od), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are reco rded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company. Condensed Consolidating Balance Sheet December 31, 2017 Parent Subsidiary Subsidiary Consolidating (in millions) Issuer Guarantors Non-Guarantors Entries Total ASSETS Accounts receivable - related parties $ 8,836 $ (669) $ - $ (8,167) $ - Other current assets 6 576 10 - 592 Oil and natural gas properties, net - 12,192 615 - 12,807 Property and equipment, net - 234 - - 234 Investment in subsidiaries 3,202 - - (3,202) - Other long-term assets 23 76 - - 99 Total assets $ 12,067 $ 12,409 $ 625 $ (11,369) $ 13,732 LIABILITIES AND EQUITY Accounts payable - related parties $ (669) $ 8,223 $ 613 $ (8,167) $ - Other current liabilities 341 821 3 - 1,165 Long-term debt 2,691 - - - 2,691 Other long-term liabilities 789 166 6 - 961 Equity 8,915 3,199 3 (3,202) 8,915 Total liabilities and equity $ 12,067 $ 12,409 $ 625 $ (11,369) $ 13,732 Condensed Consolidating Balance Sheet December 31, 2016 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total ASSETS Accounts receivable - related parties $ 8,991 $ (336) $ (8,655) $ - Other current assets 12 550 - 562 Oil and natural gas properties, net - 11,086 - 11,086 Property and equipment, net - 216 - 216 Investment in subsidiaries 1,989 - (1,989) - Other long-term assets 11 244 - 255 Total assets $ 11,003 $ 11,760 $ (10,644) $ 12,119 LIABILITIES AND EQUITY Accounts payable - related parties $ (336) $ 8,991 $ (8,655) $ - Other current liabilities 113 640 - 753 Long-term debt 2,741 - - 2,741 Other long-term liabilities 862 140 - 1,002 Equity 7,623 1,989 (1,989) 7,623 Total liabilities and equity $ 11,003 $ 11,760 $ (10,644) $ 12,119 |
Condensed Consolidating Statement of Operations | The following condensed consolidating balance s heets at December 31, 2017 and 2016 , condensed c o nsolidating statements of o perations and condensed consolidating statements of cash flows for the years ended December 31, 2017 , 2016 and 2015 , present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity meth od), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are reco rded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2017 Parent Subsidiary Subsidiary Consolidating (in millions) Issuer Guarantors Non-Guarantors Entries Total Total operating revenues $ - $ 2,566 $ 20 $ - $ 2,586 Total operating costs and expenses (129) (1,366) (17) - (1,512) Income (loss) from operations (129) 1,200 3 - 1,074 Interest expense (145) (1) - - (146) Loss on extinguishment of debt (66) - - - (66) Other, net 1,221 19 - (1,221) 19 Income before income taxes 881 1,218 3 (1,221) 881 Income tax benefit 75 - - - 75 Net income $ 956 $ 1,218 $ 3 $ (1,221) $ 956 Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Total operating revenues $ - $ 1,635 $ - $ 1,635 Total operating costs and expenses (370) (3,334) - (3,704) Loss from operations (370) (1,699) - (2,069) Interest expense (202) (2) - (204) Loss on extinguishment of debt (56) - - (56) Other, net (1,710) (9) 1,710 (9) Loss before income taxes (2,338) (1,710) 1,710 (2,338) Income tax benefit 876 - - 876 Net loss $ (1,462) $ (1,710) $ 1,710 $ (1,462) Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Total operating revenues $ - $ 1,804 $ - $ 1,804 Total operating costs and expenses 697 (2,174) - (1,477) Income (loss) from operations 697 (370) - 327 Interest expense (213) (2) - (215) Other, net (387) (15) 387 (15) Income (loss) before income taxes 97 (387) 387 97 Income tax expense (31) - - (31) Net income (loss) $ 66 $ (387) $ 387 $ 66 |
Condensed Consolidating Statement of Cash Flows | The following condensed consolidating balance s heets at December 31, 2017 and 2016 , condensed c o nsolidating statements of o perations and condensed consolidating statements of cash flows for the years ended December 31, 2017 , 2016 and 2015 , present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity meth od), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are reco rded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2017 Parent Subsidiary Subsidiary Consolidating (in millions) Issuer Guarantors Non-Guarantors Entries Total Net cash flows provided by operating activities $ 145 $ 1,549 $ 1 $ - $ 1,695 Net cash flows used in investing activities - (1,105) (614) - (1,719) Net cash flows provided by (used in) financing activities (145) (497) 613 - (29) Net decrease in cash and cash equivalents - (53) - - (53) Cash and cash equivalents at beginning of period - 53 - - 53 Cash and cash equivalents at end of period $ - $ - $ - $ - $ - Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Net cash flows provided by (used in) operating activities $ (665) $ 2,049 $ - $ 1,384 Net cash flows used in investing activities - (2,225) - (2,225) Net cash flows provided by financing activities 665 - - 665 Net decrease in cash and cash equivalents - (176) - (176) Cash and cash equivalents at beginning of period - 229 - 229 Cash and cash equivalents at end of period $ - $ 53 $ - $ 53 Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015 Parent Subsidiary Consolidating (in millions) Issuer Guarantors Entries Total Net cash flows provided by (used in) operating activities $ (1,394) $ 2,924 $ - $ 1,530 Net cash flows used in investing activities - (2,602) - (2,602) Net cash flows provided by (used in) financing activities 1,394 (93) - 1,301 Net increase in cash and cash equivalents - 229 - 229 Cash and cash equivalents at beginning of period - - - - Cash and cash equivalents at end of period $ - $ 229 $ - $ 229 |
Subsequent events (Tables)
Subsequent events (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
New commodity derivative contracts | After December 31, 2017 , the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Price Swaps: (a) 2018: Volume (Bbl) 915,000 1,213,000 1,013,000 674,000 3,815,000 Price per Bbl $ 63.64 $ 63.48 $ 63.34 $ 63.11 $ 63.42 2019: Volume (Bbl) 876,000 748,000 636,000 552,000 2,812,000 Price per Bbl $ 58.14 $ 58.12 $ 58.10 $ 58.08 $ 58.11 2020: Volume (Bbl) 1,001,000 1,001,000 1,012,000 1,012,000 4,026,000 Price per Bbl $ 54.80 $ 54.80 $ 54.80 $ 54.80 $ 54.80 Oil Basis Swaps: (b) 2018: Volume (Bbl) 615,000 637,000 399,000 306,000 1,957,000 Price per Bbl $ 0.13 $ 0.06 $ (0.07) $ (0.10) $ 0.03 2019: Volume (Bbl) 180,000 182,000 184,000 - 546,000 Price per Bbl $ (0.27) $ (0.27) $ (0.27) $ - $ (0.27) 2020: Volume (Bbl) 2,184,000 2,184,000 2,208,000 2,208,000 8,784,000 Price per Bbl $ (0.09) $ (0.09) $ (0.09) $ (0.09) $ (0.09) Natural Gas Price Swaps: (c) 2018: Volume (MMBtu) 1,277,000 878,000 921,000 274,000 3,350,000 Price per MMBtu $ 3.08 $ 3.08 $ 3.08 $ 3.08 $ 3.08 (a) The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. (c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. |
Summary Of Significant Accoun41
Summary Of Significant Accounting Policies (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure Summary Of Significant Accounting Policies Narrative [Abstract] | |||
Allowance for Doubtful Accounts Receivable | $ 1 | $ 1 | |
Depletion expense from operations | 1,122 | 1,145 | $ 1,203 |
Interest costs capitalized on oil and gas properties | 3 | 0 | 1 |
Impairments of long-lived assets | 0 | 1,525 | 61 |
Impairment of abandoned and expiring acreage | 29 | 60 | 35 |
Other property and equipment, net | 234 | 216 | |
Other property and equipment, accumulated depreciation | 90 | 74 | |
Depreciation expense on other property and equipment | 21 | 21 | 19 |
Interest costs capitalized on other property and equipment | 0 | 0 | 1 |
Funds held in escrow | 0 | 43 | |
Credit Facility deferred loan costs, net | 13 | 11 | |
Accumulated amortization of Credit Facility deferred loan costs | $ 51 | 56 | |
Estimated economic life of gross operating rights in years, minimum | 3 years | ||
Estimated economic life of gross operating rights in years, maximum | 25 years | ||
Amortization Of Intangible Assets | $ 3 | 1 | 1 |
Future amortization expense of intangible assets, year one | 3 | ||
Future amortization expense of intangible assets, year two | 1 | ||
Future amortization expense of intangible assets, year three | 1 | ||
Future amortization expense of intangible assets, year four | 1 | ||
Future amortization expense of intangible assets, year five | 1 | ||
Future amortization expense thereafter | 19 | ||
Environmental liability accrued | 3 | 1 | |
Environmental libility expensed | 9 | 7 | 3 |
Senior notes issuance costs, net | 25 | 31 | |
Accumulated amortization of senior note deferred loan costs | 1 | 12 | |
Fees related to operation of jointly owned oil and natural gas properties | 16 | 17 | 19 |
ASU 2016-09 Cumulative Effect: Forfeiture estimate compensation expense / increase to APIC | 8 | ||
ASU 2016-09 Cumulative Effect: Deferred tax benefit | 3 | ||
ASU 2016-09 Cumulative Effect: Excess tax benefits | 5 | ||
ASU 2016-09 Cumulative Effect: Decrease to retained earnings | 0 | ||
ASU 2016-09 Cumulative Effect: Decrease to deferred income taxes | 8 | ||
Excess tax benefit (deficiency) [discrete item] | 6 | 0 | 0 |
Forfeitures expense | 8 | 5 | |
Alpha Crude Connector [Member] | |||
Equity Method Investments [Line Items] | |||
Income (loss) from equity method investments | (2) | $ (4) | |
Total equity method investment | 0 | $ 129 | |
Equity method investment ownership percentage | 50.00% | ||
Oryx Southern Delaware Holdings [Member] | |||
Equity Method Investments [Line Items] | |||
Income (loss) from equity method investments | 7 | $ (2) | |
Total equity method investment | $ 49 | $ 42 | |
Equity method investment ownership percentage | 23.75% | 25.00% |
Summary Of Significant Accoun42
Summary Of Significant Accounting Policies (Gross And Net Intangible Assets) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Disclosure Summary Of Significant Accounting Policies Gross And Net Intangible Assets [Abstract] | ||
Gross intangibles | $ 42 | $ 37 |
Accumulated amortization | (16) | (13) |
Net intangibles | $ 26 | $ 24 |
Exploratory Well Costs (Capital
Exploratory Well Costs (Capitalized Exploratory Well Activity) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract] | |||
Beginning capitalized exploratory well costs | $ 151 | $ 116 | $ 242 |
Additions to exploratory well costs pending the determination of proved reserves | 180 | 144 | 103 |
Reclassifications due to determination of proved reserves | (147) | (86) | (228) |
Exploratory well costs charged to expense | 0 | (6) | (1) |
Disposition of wells | (2) | (17) | 0 |
Ending capitalized exploratory well costs | $ 182 | $ 151 | $ 116 |
Exploratory Well Costs (Aging O
Exploratory Well Costs (Aging Of Capitalized Exploratory Well Costs Based On The Date Of Drilling) (Detail) $ in Millions | Dec. 31, 2017USD ($)Number | Dec. 31, 2016USD ($)Number | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Disclosure Exploratory Well Costs Aging Of Capitalized Exploratory Well Costs Based On The Date Of Drilling [Abstract] | ||||
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ 180 | $ 141 | ||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | 2 | 10 | ||
Total capitalized exploratory well costs | $ 182 | $ 151 | $ 116 | $ 242 |
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects | Number | 2 | 8 |
Acquisitions, divestitures an45
Acquisitions, divestitures and nonmonetary transactions (Narrative) (Detail) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition [Line Items] | ||||
Funds held in escrow | $ 0 | $ 43 | ||
Issuance of common stock for business combinations | 291 | 768 | $ 0 | |
Proceeds From Sale Of Oil And Gas Property And Equipment | $ 280 | 29 | 0 | 0 |
(Gain) loss on disposition of assets, net | (678) | (118) | 54 | |
Northern Delaware Basin [Member] | ||||
Business Acquisition [Line Items] | ||||
Total cash consideration paid for acquisition | $ 160 | |||
Funds held in escrow | 43 | |||
Common stock issued in business combinations (Shares) | 2.2 | |||
Issuance of common stock for business combinations | $ 291 | |||
Alpha Crude Connector [Member] | ||||
Business Acquisition [Line Items] | ||||
Proceeds From Sale Of Oil And Gas Property And Equipment | 801 | |||
(Gain) loss on disposition of assets, net | (655) | |||
Total equity method investment | 129 | |||
Midland Basin [Member] | ||||
Business Acquisition [Line Items] | ||||
Total cash consideration paid for acquisition | 595 | |||
VIE Assets | 608 | |||
VIE Liabilities | 604 | |||
Nonmonetary Transactions [Member] | ||||
Business Acquisition [Line Items] | ||||
Pre-tax gain on nonmonetary transactions | $ 26 | |||
Asset Divestiture [Member] | ||||
Business Acquisition [Line Items] | ||||
Net proceeds from divestiture | 292 | |||
Pre-tax gain on asset divestiture | 110 | |||
Southern Delaware Basin [Member] | ||||
Business Acquisition [Line Items] | ||||
Future Carry Amount | 40 | |||
Total cash consideration paid for acquisition | $ 146 | |||
Common stock issued in business combinations (Shares) | 2.2 | |||
Issuance of common stock for business combinations | $ 231 | |||
Reliance [Member] | ||||
Business Acquisition [Line Items] | ||||
Common stock issued in business combinations (Shares) | 3.9 | |||
Total consideration paid for net assets | $ 1,716 | |||
Cash consideration | 1,176 | |||
Equity consideration | 540 | |||
Revenues since acquisition date | 29 | |||
Income from operations since acquisition date | $ 10 | |||
Clayton Williams [Member] | ||||
Business Acquisition [Line Items] | ||||
Gain (loss) on disposition of assets | $ (50) |
Acquisitions And Business Combi
Acquisitions And Business Combinations (Fair Value of Net Assets) (Detail) - Reliance [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Business Acquisition [Line Items] | |
Proved oil and natural gas properties | $ 730 |
Unproved oil and natural gas properties | 972 |
Other assets | 34 |
Total assets acquired | 1,736 |
Current liabilities, including current portion of asset retirement obligations | (8) |
Asset retirement obligations assumed | (12) |
Fair value of net assets acquired | 1,716 |
Cash consideration | 1,176 |
Non-cash consideration, including equity | 540 |
Total consideration paid for net assets | $ 1,716 |
Acquisitions And Business Com47
Acquisitions And Business Combinations (Pro Forma Data) (Detail) $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)$ / shares | |
Business Acquisition, Pro Forma Information [Abstract] | |
Operating revenues | $ | $ 1,717 |
Net loss | $ | $ (1,396) |
Earnings per common share, basic | $ / shares | $ (10.36) |
Earnings per common share, diluted | $ / shares | $ (10.36) |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule Of Asset Retirement Obligation Transactions) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Disclosure Asset Retirement Obligations Schedule Of Asset Retirement Obligation Transactions [Abstract] | ||||
Asset retirement obligations, beginning of period | $ 130 | $ 120 | $ 120 | |
Liabilities incurred from new wells | 2 | 2 | 4 | |
Liabilities assumed in acquisitions | 10 | 13 | 2 | |
Accretion expense | 8 | 7 | 8 | |
Disposition of wells | (1) | (11) | 0 | |
Liabilities settled upon plugging and abandoning wells | (5) | (1) | (3) | |
Revision of estimates | [1] | (3) | 0 | (11) |
Asset retirement obligations, end of period | $ 141 | $ 130 | $ 120 | |
[1] | The revisions to the Companyʼs asset retirement obligation estimates for the years ended December 31, 2017 and 2015 are primarily due to a reduction in the future estimated abandonment costs. |
Incentive Plans (Narrative) (De
Incentive Plans (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Forfeitures expense | $ 8 | $ 5 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value | $ 2 | $ 2 | $ 0 |
Performance unit awards vesting period | 3 years | ||
Approved and authorized awards | 10,500,000 | ||
Awards available for future grant | 2,100,000 | ||
401 (k) defined contribution plan | |||
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined contribution plan employer's contribution match percentage | 100.00% | 100.00% | 100.00% |
Defined contribution plan, employee contribution | 10.00% | 10.00% | 10.00% |
Defined contribution plan, employers contribution | $ 10 | $ 9 | $ 10 |
Incentive Plans (Schedule Of Re
Incentive Plans (Schedule Of Restricted Stock Awards Activity) (Detail) - 2015 Stock Incentive Plan [Member] - Restricted Stock [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Outstanding at beginning of period | 1,157,270 | ||
Shares granted | 490,300 | ||
Shares cancelled / forfeited | (100,199) | ||
Lapse of restrictions | (398,125) | ||
Outstanding at end of period | 1,149,246 | 1,157,270 | |
Weighted Average Grant Date Fair Value, Outstanding at beginning of year | $ 115.29 | ||
Shares Granted - Weighted Average Grant Date Fair Value Per Share | 123.16 | $ 112.78 | $ 109.76 |
Shares cancelled / forfeited - Weighted Average Grant Date Fair Value per share | 113.56 | ||
Lapse of Restrictions - Weighted Average Grant Date Fair Value per share | 117.91 | ||
Weighted Average Grant Date Fair Value, Outstanding at end of year | $ 118.02 | $ 115.29 |
Incentive Plans (Summary Inform
Incentive Plans (Summary Information For Stock-Based Compensation For Restricted Stock Awards) (Detail) - Restricted Stock [Member] - 2015 Stock Incentive Plan [Member] - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value for awards granted during the period | [1] | $ 60 | $ 51 | $ 50 |
Fair value for awards vested during the period | 49 | 45 | 36 | |
Stock-based compensation expense from restricted stock | 43 | 41 | 43 | |
Income tax benefit related to restricted stock | $ 11 | $ 15 | $ 16 | |
Shares Granted - Weighted Average Grant Date Fair Value Per Share | $ 123.16 | $ 112.78 | $ 109.76 | |
[1] | The weighted average grant date fair value per share amounts were $123.16, $112.78 and $109.76 for the years ended December 31, 2017, 2016 and 2015, respectively. |
Incentive Plans (Schedule Of St
Incentive Plans (Schedule Of Stock Option Awards Activity) (Detail) - 2015 Stock Incentive Plan [Member] - Stock Options [Member] - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Outstanding at beginning of period (Shares) | 20,000 | |
Options exercised (Shares) | (20,000) | |
Outstanding at end of period (Shares) | 0 | 20,000 |
Vested and exercisable at end of period (Shares) | 0 | |
Outstanding at beginning of period | $ 15.33 | $ 15.33 |
Options exercised | $ 15.33 |
Incentive Plans (Summary Of Ass
Incentive Plans (Summary Of Assumptions To Estimate Fair Value of Performance Unit Awards) (Detail) - 2015 Stock Incentive Plan [Member] - Performance Units [Member] | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Risk-free interest rate | 1.47% | 1.31% | 1.07% |
Volatility assumption - minimum | 24.80% | 31.60% | 26.10% |
Volatility assumption - maximum | 60.20% | 59.00% | 43.00% |
Incentive Plans (Schedule Of Pe
Incentive Plans (Schedule Of Performance Unit Awards Activity) (Detail) - 2015 Stock Incentive Plan [Member] - Performance Units [Member] - $ / shares | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Performance units outstanding at beginning of period (Shares) | 331,526 | |||
Units granted | [1] | 108,398 | ||
Units forfeited | (43,333) | |||
Units vested | [2] | (148,944) | ||
Performance units outstanding at end of period (Shares) | 247,647 | 331,526 | ||
Weighted Average Grant Date Fair Value, Outstanding at beginning of year | $ 136.68 | |||
Shares Granted - Grant Date Fair Value - Performance Units | 183.48 | $ 114.81 | $ 156.86 | |
Shares Forfeited - Grant Date Fair Value - Performance Units | 140 | |||
Shares Vested - Grant Date Fair Value - Performance Units | 156.86 | |||
Weighted Average Grant Date Fair Value, Outstanding at end of year | $ 146.1 | $ 136.68 | ||
Performance Percentage Of Actual Payout Minimum | 0.00% | |||
Performance Percentage Of Actual Payout Maximum | 300.00% | |||
Number Of Shares Earned For Each Vested Award | 446,832 | |||
[1] | Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period. | |||
[2] | On December 31, 2017, the performance period ended for these performance units. Each unit converted into three shares representing 446,832 shares of common stock issued on January 2, 2018. |
Incentive Plans (Summary Info55
Incentive Plans (Summary Information For Stock-Based Compensation For Performance Units) (Detail) - Performance Units [Member] - 2015 Stock Incentive Plan [Member] - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value for awards granted during the period | [1] | $ 20 | $ 19 | $ 28 |
Fair value for awards vested during the period | 68 | 33 | 16 | |
Stock-based compensation expense from performance units | 17 | 18 | 20 | |
Income tax benefit related to performance units | $ 2 | $ 7 | $ 7 | |
Shares Granted - Grant Date Fair Value - Performance Units | $ 183.48 | $ 114.81 | $ 156.86 | |
[1] | The weighted average grant date fair value per unit amounts were $183.48, $114.81 and $156.86 for the years ended December 31, 2017, 2016 and 2015, respectively. |
Incentive Plans (Summary For Fu
Incentive Plans (Summary For Future Stock-Based Compensation Expense) (Detail) - 2015 Stock Incentive Plan [Member] $ in Millions | Dec. 31, 2017USD ($) |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
2,018 | $ 49 |
2,019 | 26 |
2,020 | 8 |
Thereafter | 2 |
Total | $ 85 |
Disclosures about Fair Value 57
Disclosures about Fair Value Measurements (Narrative) (Detail) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2025$ / bbl$ / Mcf | Dec. 31, 2024$ / bbl | Dec. 31, 2019$ / Mcf | Dec. 31, 2018$ / bbl$ / Mcf | Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | ||||||||
Management Estimate of Future Oil Price | $ / bbl | 51.83 | 51.82 | 59.55 | |||||
Management Estimate of Future Natural Gas Price | $ / Mcf | 2.99 | 2.81 | 2.84 | |||||
Annual discount rate | 10.00% | |||||||
Carrying Amount | $ 3,438 | $ 105 | $ 18 | |||||
Impairment Expense | $ 1,525 | $ 53 | $ 8 |
Disclosures About Fair Value 58
Disclosures About Fair Value Measurements (Carrying Amounts And Fair Values Of The Company's Financial Instruments) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Derivative instruments, Assets | $ 0 | $ 4 | |
Derivative instruments, Liabilities | 379 | 178 | |
Credit facility | 322 | 0 | |
Five Point Five Percent Unsecured Senior Notes Due 2022 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | 0 | 620 | |
Five Point Five Percent Unsecured Senior Notes Due 2023 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | 0 | 1,621 | |
Four Point Three Seven Five Percent Unsecured Senior Notes due 2025 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | 624 | 599 | |
Three Point Seven Five Percent Unsecured Senior Notes due 2027 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | 1,012 | 0 | |
Four Point Eight Seven Five Percent Unsecured Senior Notes due 2047 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | 874 | 0 | |
Carrying Reported Amount Fair Value Disclosure [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Derivative instruments, Assets | 0 | 4 | |
Derivative instruments, Liabilities | 379 | 178 | |
Credit facility | 322 | 0 | |
Carrying Reported Amount Fair Value Disclosure [Member] | Five Point Five Percent Unsecured Senior Notes Due 2022 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | [1] | 0 | 594 |
Carrying Reported Amount Fair Value Disclosure [Member] | Five Point Five Percent Unsecured Senior Notes Due 2023 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | [1] | 0 | 1,555 |
Carrying Reported Amount Fair Value Disclosure [Member] | Four Point Three Seven Five Percent Unsecured Senior Notes due 2025 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | [1] | 593 | 592 |
Carrying Reported Amount Fair Value Disclosure [Member] | Three Point Seven Five Percent Unsecured Senior Notes due 2027 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | [1] | 987 | 0 |
Carrying Reported Amount Fair Value Disclosure [Member] | Four Point Eight Seven Five Percent Unsecured Senior Notes due 2047 [Member] | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Unsecured senior notes | [1] | $ 789 | $ 0 |
[1] | The carrying value includes associated deferred loan costs and any premium (discount). |
Disclosures About Fair Value 59
Disclosures About Fair Value Measurements (Company's Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative, Fair Value, Net | $ (379) | $ (174) |
Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 13 | 59 |
Derivative Asset, Fair Value, Gross Liability | (13) | (55) |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 0 | 4 |
Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 0 |
Derivative Asset, Fair Value, Gross Liability | (1) | 0 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (290) | (137) |
Derivative Liability, Fair Value, Gross Asset | 13 | 55 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (277) | (82) |
Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (103) | (96) |
Derivative Liability, Fair Value, Gross Asset | 1 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (102) | (96) |
Fair Value Inputs Level 1 [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative, Fair Value, Net | 0 | 0 |
Fair Value Inputs Level 1 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Fair Value Inputs Level 1 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Fair Value Inputs Level 1 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Fair Value Inputs Level 1 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Fair Value Inputs Level 2 [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative, Fair Value, Net | (379) | (174) |
Fair Value Inputs Level 2 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 13 | 59 |
Fair Value Inputs Level 2 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 0 |
Fair Value Inputs Level 2 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (290) | (137) |
Fair Value Inputs Level 2 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (103) | (96) |
Fair Value Inputs Level 3 [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative, Fair Value, Net | 0 | 0 |
Fair Value Inputs Level 3 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Fair Value Inputs Level 3 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Asset Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Fair Value Inputs Level 3 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Current [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Fair Value Inputs Level 3 [Member] | Commodity Derivative Price Swap Contracts [Member] | Derivative Liability Noncurrent [Member] | ||
Fair Value Of Derivatives Disclosure Information [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | $ 0 | $ 0 |
Disclosures About Fair Value 60
Disclosures About Fair Value Measurements (Carrying Amounts, Estimated Fair Values And Impairment Expense Of Long-Lived Assets For Continuing And Discontinued Operations) (Detail) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Carrying Amount | $ 3,438 | $ 105 | $ 18 |
Estimated Fair Value (Level 3) | 1,913 | 52 | 10 |
Impairment Expense | $ 1,525 | $ 53 | $ 8 |
Derivative Financial Instrume61
Derivative Financial Instruments (Gains And Losses Reported In Earnings Related To Commodity Derivative Instruments) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items] | |||
Net settlements received from (paid on) derivatives | $ 79 | $ 625 | $ 633 |
Gain (loss) on derivatives | (126) | (369) | 700 |
Oil Commodity Derivative [Member] | |||
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items] | |||
Net settlements received from (paid on) derivatives | 79 | 609 | 597 |
Gain (loss) on derivatives | (172) | (337) | 675 |
Natural Gas Commodity Derivative [Member] | |||
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items] | |||
Net settlements received from (paid on) derivatives | 0 | 16 | 36 |
Gain (loss) on derivatives | $ 46 | $ (32) | $ 25 |
Derivative Financial Instrume62
Derivative Financial Instruments (Outstanding Commodity Derivative Contracts) (Detail) - Minimum [Member] | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019MMBTUbbl$ / bbl$ / MMBTU | Sep. 30, 2019MMBTUbbl$ / bbl$ / MMBTU | Jun. 30, 2019MMBTUbbl$ / bbl$ / MMBTU | Mar. 31, 2019MMBTUbbl$ / bbl$ / MMBTU | Dec. 31, 2018MMBTUbbl$ / bbl$ / MMBTU | Sep. 30, 2018MMBTUbbl$ / bbl$ / MMBTU | Jun. 30, 2018MMBTUbbl$ / bbl$ / MMBTU | Mar. 31, 2018MMBTUbbl$ / bbl$ / MMBTU | Dec. 31, 2019MMBTUbbl$ / bbl$ / MMBTU | Dec. 31, 2018MMBTUbbl$ / bbl$ / MMBTU | ||
Oil Swaps [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume - Current Year | bbl | [1] | 7,432,007 | 7,931,318 | 8,965,170 | 10,123,629 | 34,452,124 | |||||
Price - Current Year | $ / bbl | [1] | 51.57 | 51.65 | 51.92 | 52.05 | 51.82 | |||||
Volume - Year One | bbl | [1] | 5,681,000 | 5,946,000 | 6,254,500 | 6,613,000 | 24,494,500 | |||||
Price - Year One | $ / bbl | [1] | 52.36 | 52.37 | 52.33 | 52.36 | 52.35 | |||||
Oil Basis Swaps [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume - Current Year | bbl | [2] | 7,451,000 | 8,066,000 | 8,855,000 | 10,059,000 | 34,431,000 | |||||
Price - Current Year | $ / bbl | [2] | (0.93) | (0.89) | (0.88) | (0.8) | (0.87) | |||||
Volume - Year One | bbl | [2] | 5,933,000 | 6,210,000 | 6,505,500 | 6,870,000 | 25,518,500 | |||||
Price - Year One | $ / bbl | [2] | (1.01) | (0.99) | (0.98) | (0.96) | (0.98) | |||||
Natural Gas Swap [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume - Current Year | MMBTU | [3] | 14,504,000 | 14,819,000 | 16,101,000 | 16,556,000 | 61,980,000 | |||||
Price - Current Year | $ / MMBTU | [3] | 3.03 | 3.04 | 3.04 | 3.05 | 3.04 | |||||
Volume - Year One | MMBTU | [3] | 4,329,535 | 4,418,537 | 4,501,387 | 4,591,533 | 17,840,992 | |||||
Price - Year One | $ / MMBTU | [3] | 2.86 | 2.86 | 2.86 | 2.86 | 2.86 | |||||
[1] | The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. | ||||||||||
[2] | The basis differential price is between Midland – WTI and Cushing – WTI. | ||||||||||
[3] | The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. |
Debt (Summary Of Long-Term Debt
Debt (Summary Of Long-Term Debt) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Credit facility | $ 322 | $ 0 |
Unamortized original issue premium (discount), net | (6) | 22 |
Senior notes issuance costs, net | (25) | (31) |
Less: current portion | 0 | 0 |
Total long-term debt | 2,691 | 2,741 |
5.5% unsecured senior notes due 2022 | ||
Debt Instrument [Line Items] | ||
Unsecured senior notes | 0 | 600 |
5.5% unsecured senior notes due 2023 | ||
Debt Instrument [Line Items] | ||
Unsecured senior notes | 0 | 1,550 |
4.375% unsecured senior notes due 2025 | ||
Debt Instrument [Line Items] | ||
Unsecured senior notes | 600 | 600 |
3.75% unsecured senior notes due 2027 | ||
Debt Instrument [Line Items] | ||
Unsecured senior notes | 1,000 | 0 |
4.875% unsecured senior notes due 2047 | ||
Debt Instrument [Line Items] | ||
Unsecured senior notes | $ 800 | $ 0 |
Debt (Narrative) (Detail)
Debt (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Line Items] | |||
Proceeds from debt, net of issuance costs | $ 1,777 | ||
Aggregate principal amount of 5.5% Notes tenders received | 1,232 | ||
Loss on extinguishment of debt | (66) | $ (56) | $ 0 |
Make-whole premium for early redemption | 63 | 42 | 0 |
Senior notes issuance costs, net | $ 25 | 31 | |
Percentage of notes tendered | 57.30% | ||
Percent of par tendered | 102.934% | ||
Credit Facility [Member] | |||
Debt Disclosure [Line Items] | |||
Line of credit maturity date | May 9, 2022 | ||
Aggregate lender commitments | $ 2,000 | ||
Unused lender commitments | 1,700 | ||
Debt Related Commitment Fees | 6 | 8 | 7 |
Loss on extinguishment of debt | $ 1 | ||
Commitment fees on unused portion of available commitment | 0.25% | ||
J.P. Morgan Chase Bank Prime Rate [Member] | |||
Debt Disclosure [Line Items] | |||
Line Of Credit Facility Interest Rate At Period End | 4.50% | ||
Alternate Base Rate [Member] | Credit Facility [Member] | |||
Debt Disclosure [Line Items] | |||
Line Of Credit Facility Interest Rate At Period End | 0.50% | ||
Additional percentage added to federal funds effective rate for ABR loans | 0.50% | ||
Additional percentage added to LIBOR rate for ABR loans | 1.00% | ||
London Interbank Offered Rate [Member] | Credit Facility [Member] | |||
Debt Disclosure [Line Items] | |||
Line Of Credit Facility Interest Rate At Period End | 1.50% | ||
3.75% unsecured senior notes due 2027 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | $ 1,000 | 0 | |
Interest rate | 3.75% | ||
Debt Instrument Percentage Due | 99.636% | ||
4.875% unsecured senior notes due 2047 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | $ 800 | 0 | |
Interest rate | 4.875% | ||
Debt Instrument Percentage Due | 99.749% | ||
5.5% unsecured senior notes due 2022 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | $ 0 | $ 600 | |
Interest rate | 5.50% | ||
Aggregate principal amount of notes offered for tender | 600 | ||
5.5% unsecured senior notes due 2023 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | 0 | $ 1,550 | |
Interest rate | 5.50% | ||
Aggregate principal amount of notes offered for tender | 1,550 | ||
4.375% unsecured senior notes due 2025 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | 600 | $ 600 | |
Interest rate | 4.375% | ||
Debt Instrument Percentage Due | 100.00% | ||
Proceeds from debt, net of issuance costs | $ 592 | ||
6.5% unsecured senior notes due 2022 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | 0 | 600 | |
Loss on extinguishment of debt | 28 | ||
Make-whole premium for early redemption | 20 | ||
Write-off of unamortized deferred loan costs | 7 | ||
Outstanding principal amount satisfied and discharged | $ 600 | ||
Percent of par satisfied and discharged | 103.25% | ||
Interest paid on senior notes | $ 1 | $ 20 | |
7.0% unsecured senior notes due 2021 | |||
Debt Disclosure [Line Items] | |||
Unsecured senior notes | $ 0 | $ 600 | |
Percent of par redeemed | 103.50% | ||
Loss on extinguishment of debt | $ 28 | ||
Make-whole premium for early redemption | 21 | ||
Write-off of unamortized deferred loan costs | $ 7 |
Schedule of Extinguishment of D
Schedule of Extinguishment of Debt (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Extinguishment Of Debt [Line Items] | |||
Make-whole premium for early redemption | $ 63 | $ 42 | $ 0 |
Prepaid interest | (6) | (9) | (9) |
Loss on extinguishment of debt | (66) | $ (56) | $ 0 |
Tender Offer [Member] | |||
Extinguishment Of Debt [Line Items] | |||
Tender premium | 36 | ||
Make-whole premium for early redemption | 0 | ||
Prepaid interest | 0 | ||
Total cash | 36 | ||
Unamortized original issue premium | (11) | ||
Unamortized deferred loan costs | 12 | ||
Total non-cash | 1 | ||
Loss on extinguishment of debt | 37 | ||
Extinguishment [Member] | |||
Extinguishment Of Debt [Line Items] | |||
Tender premium | 0 | ||
Make-whole premium for early redemption | 25 | ||
Prepaid interest | 2 | ||
Total cash | 27 | ||
Unamortized original issue premium | (8) | ||
Unamortized deferred loan costs | 9 | ||
Total non-cash | 1 | ||
Loss on extinguishment of debt | 28 | ||
Credit Facility Amendment [Member] | |||
Extinguishment Of Debt [Line Items] | |||
Tender premium | 0 | ||
Make-whole premium for early redemption | 0 | ||
Prepaid interest | 0 | ||
Total cash | 0 | ||
Unamortized original issue premium | 0 | ||
Unamortized deferred loan costs | 1 | ||
Total non-cash | 1 | ||
Loss on extinguishment of debt | 1 | ||
Total [Member] | |||
Extinguishment Of Debt [Line Items] | |||
Tender premium | 36 | ||
Make-whole premium for early redemption | 25 | ||
Prepaid interest | 2 | ||
Total cash | 63 | ||
Unamortized original issue premium | (19) | ||
Unamortized deferred loan costs | 22 | ||
Total non-cash | 3 | ||
Loss on extinguishment of debt | $ 66 |
Debt (Principal Maturities Of D
Debt (Principal Maturities Of Debt) (Detail) $ in Millions | Dec. 31, 2017USD ($) |
Disclosure Debt Principal Maturities Of Debt [Abstract] | |
2,018 | $ 0 |
2,019 | 0 |
2,020 | 0 |
2,021 | 0 |
2,022 | 322 |
Thereafter | 2,400 |
Total | $ 2,722 |
Debt (Summary Of Interest Expen
Debt (Summary Of Interest Expense) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure Debt Summary Of Interest Expense [Abstract] | |||
Cash payments for interest | $ (139) | $ (232) | $ (211) |
Non-cash interest | 6 | 9 | 9 |
Net changes in accruals | 4 | (37) | 0 |
Interest costs incurred | 149 | 204 | 220 |
Less: capitalized interest | (3) | 0 | (5) |
Total interest expense | $ 146 | $ 204 | $ 215 |
Commitments And Contingencies68
Commitments And Contingencies (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments [Line Items] | |||
Annual officers' salaries | $ 8 | ||
Accrued Exposure | 0 | $ 7 | |
Operating leases, lease payments | $ 10 | $ 8 | $ 8 |
Commitments And Contingencies69
Commitments And Contingencies (Future Commitments) (Detail) $ in Millions | Dec. 31, 2017USD ($) |
Disclosure Commitments And Contingencies Future Commitments [Abstract] | |
2,018 | $ 33 |
2,019 | 51 |
2,020 | 33 |
2,021 | 29 |
2,022 | 26 |
Thereafter | 84 |
Total | $ 256 |
Commitments And Contingencies70
Commitments And Contingencies (Future Minimum Lease Commitments Under Non-Cancellable Operating Leases) (Detail) $ in Millions | Dec. 31, 2017USD ($) |
Disclosure Commitments And Contingencies Future Minimum Lease Commitments Under Non Cancellable Operating Leases [Abstract] | |
2,018 | $ 10 |
2,019 | 8 |
2,020 | 7 |
2,021 | 5 |
2,022 | 0 |
Thereafter | 1 |
Total | $ 31 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure Income Taxes Narrative [Abstract] | |||
Corporate Income Tax Rate, Current | 35.00% | ||
Corporate Income Tax Rate, As Amended | 21.00% | ||
Provisional change in deferred tax assets and liabilities | $ (398) | $ 0 | $ 0 |
AMT credits | 10 | ||
Income taxes receivable, current | 5 | ||
Change in estimated effective statutory state income tax | 0 | (21) | (9) |
Excess tax benefit (deficiency) [discrete item] | 6 | 0 | 0 |
Income (loss) at U.S. federal statutory rate | 308 | (818) | 34 |
Income (loss) before income taxes | 881 | $ (2,338) | $ 97 |
State Tax Rate Increase (Reduction) | 1.00% | (9.00%) | |
Income Tax Rate Increase (Reduction) | 5.00% | ||
Federal Net Operating Loss | 122 | $ 539 | |
Net Operating Loss Carried Back to Prior Year | 6 | ||
Net Operating Loss Current Year Utilization | 411 | ||
Net Operating Loss Remaining After Prior Year Carried Back | 533 | ||
State Net Operating Loss | 111 | ||
Net deferred tax liabilities | $ 687 | $ 766 |
Income Taxes (Income Tax Expens
Income Taxes (Income Tax Expense (Benefit) Attributable To Income (Loss) From Continuing Operations) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure Income Taxes Income Tax Expense (Benefit) Attributable To Income Loss From Continuing Operations [Abstract] | |||
U.S. federal, current | $ (6) | $ (12) | $ 0 |
U.S. state and local, current | 2 | 0 | 1 |
Total current income tax expense (benefit) | (4) | (12) | 1 |
U.S. federal, deferred | (94) | (771) | 40 |
U.S. state and local, deferred | 23 | (93) | (10) |
Total deferred income tax expense (benefit) | (71) | (864) | 30 |
Total income tax expense (benefit) attributable to income from continuing operations | $ (75) | $ (876) | $ 31 |
Income Taxes (Reconciliation Be
Income Taxes (Reconciliation Between The Income Tax Expense (Benefit) And The Reported Amounts Of Income Tax Expense (Benefiit)) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure Income Taxes Reconciliation Between The Income Tax Expense Benefit And The Reported Amounts Of Income Tax Expense (Benefit) [Abstract] | |||
Income (loss) at U.S. federal statutory rate | $ 308 | $ (818) | $ 34 |
Provisional change in deferred tax assets and liabilities | (398) | 0 | 0 |
State income taxes (net of federal tax effect) | 17 | (41) | 3 |
Revisions of previous estimates | 0 | 1 | (1) |
Change in estimated effective statutory state income tax | 0 | (21) | (9) |
Excess tax benefit related to stock-based compensation | (6) | 0 | 0 |
Nondeductible expense & other | 4 | 3 | 4 |
Total income tax expense (benefit) attributable to income from continuing operations | $ (75) | $ (876) | $ 31 |
Effective tax rate | (9.00%) | 38.00% | 32.00% |
Income Taxes (Deferred Tax Asse
Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Components of Deferred Tax Assets and Liabilities [Abstract] | ||
Stock-based compensation | $ 18 | $ 39 |
Derivative instruments | 87 | 64 |
Asset retirement obligation | 33 | 48 |
Net operating losses and credits | 31 | 177 |
Other | 13 | 24 |
Total deferred tax assets | 182 | 352 |
Oil and Natural Gas Properties deduction of intangible drilling cost due to tax purpose | (852) | (1,095) |
Intangible assets | (5) | (9) |
Other | (12) | (14) |
Total deferred tax liabilities | (869) | (1,118) |
Net deferred tax liabilities | $ (687) | $ (766) |
Major Customers and Derivativ75
Major Customers and Derivative Counterparties (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Plains Marketing and Transportation Inc [Member] | |||
Revenue, Major Customer [Line Items] | |||
Entity Wide Receivables Major Customer | $ 72 | ||
Plains Marketing and Transportation Inc [Member] | Revenue [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major Customer Percentage | 21.00% | 29.00% | 11.00% |
Holly Frontier Refining and Marketing LLC [Member] | |||
Revenue, Major Customer [Line Items] | |||
Entity Wide Receivables Major Customer | $ 36 | ||
Holly Frontier Refining and Marketing LLC [Member] | Revenue [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major Customer Percentage | 10.00% | 16.00% | 25.00% |
Enterprise Crude Oil LLC [Member] | |||
Revenue, Major Customer [Line Items] | |||
Entity Wide Receivables Major Customer | $ 30 | ||
Enterprise Crude Oil LLC [Member] | Revenue [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major Customer Percentage | 8.00% | 7.00% | 12.00% |
Related Party Transactions (Sch
Related Party Transactions (Schedule Of Related Party Transactions) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |||
Amounts paid | $ 7 | $ 4 | $ 6 |
Ownership interest in partnership | 3.50% |
Earnings Per Share (Reconciliat
Earnings Per Share (Reconciliation Of Earnings Attributable To Common Shares Basic And Diluted) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Net income (loss) as reported | $ 956 | $ (1,462) | $ 66 | |
Participating basic earnings | [1] | (7) | 0 | (1) |
Basic earnings attributable to common stockholders | 949 | (1,462) | 65 | |
Reallocation of participating earnings | 0 | 0 | 0 | |
Diluted earnings attributable to common stockholders | $ 949 | $ (1,462) | $ 65 | |
[1] | Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed 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. |
Earnings Per Share (Reconcili78
Earnings Per Share (Reconciliation Of The Weighted Average Common Shares Outstanding) (Detail) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items] | |||
Basic | 147,320 | 134,755 | 119,926 |
Diluted | 147,956 | 134,755 | 120,373 |
Stock Options [Member] | |||
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items] | |||
Dilutive shares | 3 | 0 | 25 |
Performance Units [Member] | |||
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items] | |||
Dilutive shares | 633 | 0 | 422 |
Earnings Per Share (Summary Of
Earnings Per Share (Summary Of The Common Stock Options And Restricted Stock) (Detail) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Performance Units [Member] | |||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | |||
Antidilutive common shares | 81 | 0 | 0 |
Other Current Liabilities (Sche
Other Current Liabilities (Schedule Of Other Current Liabilities) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Other Liabilities Disclosure [Abstract] | ||
Accrued production costs | $ 72 | $ 63 |
Payroll related matters | 40 | 35 |
Accrued interest | 36 | 32 |
Settlements due on derivatives | 25 | 0 |
Asset retirement obligations | 12 | 10 |
Other | 31 | 12 |
Other current liabilities | $ 216 | $ 152 |
Subsidiary Guarantors (Condense
Subsidiary Guarantors (Condensed Consolidating Balance Sheet) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
ASSETS | ||||
Accounts receivable - related parties | $ 0 | $ 0 | ||
Other current assets | 592 | 562 | ||
Oil and natural gas properties, net | 12,807 | 11,086 | ||
Property and equipment, net | 234 | 216 | ||
Investment in subsidiaries | 0 | 0 | ||
Other long-term assets | 99 | 255 | ||
Total assets | 13,732 | 12,119 | ||
LIABILITIES AND EQUITY | ||||
Other current liabilities | 1,165 | 753 | ||
Long-term debt | 2,691 | 2,741 | ||
Other long-term liabilities | 961 | 1,002 | ||
Equity | 8,915 | 7,623 | $ 6,943 | $ 5,281 |
Total liabilities and stockholders' equity | 13,732 | 12,119 | ||
Consolidation Eliminations [Member] | ||||
ASSETS | ||||
Accounts receivable - related parties | (8,167) | (8,655) | ||
Other current assets | 0 | 0 | ||
Oil and natural gas properties, net | 0 | 0 | ||
Property and equipment, net | 0 | 0 | ||
Investment in subsidiaries | (3,202) | (1,989) | ||
Other long-term assets | 0 | 0 | ||
Total assets | (11,369) | (10,644) | ||
LIABILITIES AND EQUITY | ||||
Accounts payable - related parties | (8,167) | (8,655) | ||
Other current liabilities | 0 | 0 | ||
Long-term debt | 0 | 0 | ||
Other long-term liabilities | 0 | 0 | ||
Equity | (3,202) | (1,989) | ||
Total liabilities and stockholders' equity | (11,369) | (10,644) | ||
Parent Company [Member] | Reportable Legal Entities [Member] | ||||
ASSETS | ||||
Accounts receivable - related parties | 8,836 | 8,991 | ||
Other current assets | 6 | 12 | ||
Oil and natural gas properties, net | 0 | 0 | ||
Property and equipment, net | 0 | 0 | ||
Investment in subsidiaries | 3,202 | 1,989 | ||
Other long-term assets | 23 | 11 | ||
Total assets | 12,067 | 11,003 | ||
LIABILITIES AND EQUITY | ||||
Accounts payable - related parties | (669) | (336) | ||
Other current liabilities | 341 | 113 | ||
Long-term debt | 2,691 | 2,741 | ||
Other long-term liabilities | 789 | 862 | ||
Equity | 8,915 | 7,623 | ||
Total liabilities and stockholders' equity | 12,067 | 11,003 | ||
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
ASSETS | ||||
Accounts receivable - related parties | (669) | (336) | ||
Other current assets | 576 | 550 | ||
Oil and natural gas properties, net | 12,192 | 11,086 | ||
Property and equipment, net | 234 | 216 | ||
Investment in subsidiaries | 0 | 0 | ||
Other long-term assets | 76 | 244 | ||
Total assets | 12,409 | 11,760 | ||
LIABILITIES AND EQUITY | ||||
Accounts payable - related parties | 8,223 | 8,991 | ||
Other current liabilities | 821 | 640 | ||
Long-term debt | 0 | 0 | ||
Other long-term liabilities | 166 | 140 | ||
Equity | 3,199 | 1,989 | ||
Total liabilities and stockholders' equity | 12,409 | $ 11,760 | ||
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
ASSETS | ||||
Accounts receivable - related parties | 0 | |||
Other current assets | 10 | |||
Oil and natural gas properties, net | 615 | |||
Property and equipment, net | 0 | |||
Investment in subsidiaries | 0 | |||
Other long-term assets | 0 | |||
Total assets | 625 | |||
LIABILITIES AND EQUITY | ||||
Accounts payable - related parties | 613 | |||
Other current liabilities | 3 | |||
Long-term debt | 0 | |||
Other long-term liabilities | 6 | |||
Equity | 3 | |||
Total liabilities and stockholders' equity | $ 625 |
Subsidiary Guarantors (Conden82
Subsidiary Guarantors (Condensed Consolidating Statement Of Operations) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Condensed Financial Statements Captions [Line Items] | |||
Total operating revenues | $ 2,586 | $ 1,635 | $ 1,804 |
Total operating costs and expenses | (1,512) | (3,704) | (1,477) |
Income (loss) from operations | 1,074 | (2,069) | 327 |
Interest expense | (146) | (204) | (215) |
Loss on extinguishment of debt | (66) | (56) | 0 |
Other, net | 19 | (9) | (15) |
Income (loss) before income taxes | 881 | (2,338) | 97 |
Income tax (expense) benefit | 75 | 876 | (31) |
Net income (loss) | 956 | (1,462) | 66 |
Consolidation Eliminations [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Total operating revenues | 0 | 0 | 0 |
Total operating costs and expenses | 0 | 0 | 0 |
Income (loss) from operations | 0 | 0 | 0 |
Interest expense | 0 | 0 | 0 |
Loss on extinguishment of debt | 0 | 0 | |
Other, net | (1,221) | 1,710 | 387 |
Income (loss) before income taxes | (1,221) | 1,710 | 387 |
Income tax (expense) benefit | 0 | 0 | 0 |
Net income (loss) | (1,221) | 1,710 | 387 |
Parent Company [Member] | Reportable Legal Entities [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Total operating revenues | 0 | 0 | 0 |
Total operating costs and expenses | 129 | 370 | (697) |
Income (loss) from operations | (129) | (370) | 697 |
Interest expense | 145 | 202 | 213 |
Loss on extinguishment of debt | (66) | (56) | |
Other, net | 1,221 | (1,710) | (387) |
Income (loss) before income taxes | 881 | (2,338) | 97 |
Income tax (expense) benefit | (75) | (876) | 31 |
Net income (loss) | 956 | (1,462) | 66 |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Total operating revenues | 2,566 | 1,635 | 1,804 |
Total operating costs and expenses | 1,366 | 3,334 | 2,174 |
Income (loss) from operations | 1,200 | (1,699) | (370) |
Interest expense | 1 | 2 | 2 |
Loss on extinguishment of debt | 0 | 0 | |
Other, net | 19 | (9) | (15) |
Income (loss) before income taxes | 1,218 | (1,710) | (387) |
Income tax (expense) benefit | 0 | 0 | 0 |
Net income (loss) | 1,218 | $ (1,710) | $ (387) |
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Total operating revenues | 20 | ||
Total operating costs and expenses | 17 | ||
Income (loss) from operations | 3 | ||
Interest expense | 0 | ||
Loss on extinguishment of debt | 0 | ||
Other, net | 0 | ||
Income (loss) before income taxes | 3 | ||
Income tax (expense) benefit | 0 | ||
Net income (loss) | $ 3 |
Subsidiary Guarantors (Conden83
Subsidiary Guarantors (Condensed Consolidating Statement Of Cash Flows) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Condensed Financial Statements Captions [Line Items] | |||
Net cash provided by (used in) operating activities | $ 1,695 | $ 1,384 | $ 1,530 |
Net cash flows provided by (used in) investing activities | (1,719) | (2,225) | (2,602) |
Net cash flows provided by (used in) financing activities | (29) | 665 | 1,301 |
Net increase (decrease) in cash and cash equivalents | (53) | (176) | 229 |
Cash and cash equivalents at beginning of period | 53 | 229 | 0 |
Cash and cash equivalents at end of period | 0 | 53 | 229 |
Consolidation Eliminations [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Net cash provided by (used in) operating activities | 0 | 0 | 0 |
Net cash flows provided by (used in) investing activities | 0 | 0 | 0 |
Net cash flows provided by (used in) financing activities | 0 | 0 | 0 |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents at beginning of period | 0 | 0 | 0 |
Cash and cash equivalents at end of period | 0 | 0 | 0 |
Parent Company [Member] | Reportable Legal Entities [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Net cash provided by (used in) operating activities | 145 | (665) | (1,394) |
Net cash flows provided by (used in) investing activities | 0 | 0 | 0 |
Net cash flows provided by (used in) financing activities | (145) | 665 | 1,394 |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents at beginning of period | 0 | 0 | 0 |
Cash and cash equivalents at end of period | 0 | 0 | 0 |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Net cash provided by (used in) operating activities | 1,549 | 2,049 | 2,924 |
Net cash flows provided by (used in) investing activities | (1,105) | (2,225) | (2,602) |
Net cash flows provided by (used in) financing activities | (497) | 0 | (93) |
Net increase (decrease) in cash and cash equivalents | (53) | (176) | 229 |
Cash and cash equivalents at beginning of period | 53 | 229 | 0 |
Cash and cash equivalents at end of period | 0 | 53 | $ 229 |
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Financial Statements Captions [Line Items] | |||
Net cash provided by (used in) operating activities | 1 | ||
Net cash flows provided by (used in) investing activities | (614) | ||
Net cash flows provided by (used in) financing activities | 613 | ||
Net increase (decrease) in cash and cash equivalents | 0 | ||
Cash and cash equivalents at beginning of period | 0 | ||
Cash and cash equivalents at end of period | $ 0 | $ 0 |
Subsequent Events (Narrative) (
Subsequent Events (Narrative) (Detail) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Subsequent Event [Line Items] | ||||
Proceeds From Sale Of Oil And Gas Property And Equipment | $ 280 | $ 29 | $ 0 | $ 0 |
Subsequent Events (New Commodit
Subsequent Events (New Commodity Derivative Contracts) (Detail) - Subsequent Event [Member] - Minimum [Member] | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2020bbl$ / bbl | Sep. 30, 2020bbl$ / bbl | Jun. 30, 2020bbl$ / bbl | Mar. 31, 2020bbl$ / bbl | Dec. 31, 2019bbl$ / bbl | Sep. 30, 2019bbl$ / bbl | Jun. 30, 2019bbl$ / bbl | Mar. 31, 2019bbl$ / bbl | Dec. 31, 2018MMBTUbbl$ / bbl$ / MMBTU | Sep. 30, 2018MMBTUbbl$ / bbl$ / MMBTU | Jun. 30, 2018MMBTUbbl$ / bbl$ / MMBTU | Mar. 31, 2018MMBTUbbl$ / bbl$ / MMBTU | Dec. 31, 2020bbl$ / bbl | Dec. 31, 2019bbl$ / bbl | Dec. 31, 2018MMBTUbbl$ / bbl$ / MMBTU | ||
Oil Swaps [Member] | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Volume - Current Year | bbl | [1] | 674,000 | 1,013,000 | 1,213,000 | 915,000 | 3,815,000 | ||||||||||
Price - Current Year | $ / bbl | [1] | 63.11 | 63.34 | 63.48 | 63.64 | 63.42 | ||||||||||
Volume - Year One | bbl | [1] | 552,000 | 636,000 | 748,000 | 876,000 | 2,812,000 | ||||||||||
Price - Year One | $ / bbl | [1] | 58.08 | 58.1 | 58.12 | 58.14 | 58.11 | ||||||||||
Volume - Year Two | bbl | [1] | 1,012,000 | 1,012,000 | 1,001,000 | 1,001,000 | 4,026,000 | ||||||||||
Price - Year Two | $ / bbl | [1] | 54.8 | 54.8 | 54.8 | 54.8 | 54.8 | ||||||||||
Oil Basis Swaps [Member] | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Volume - Current Year | bbl | [2] | 306,000 | 399,000 | 637,000 | 615,000 | 1,957,000 | ||||||||||
Price - Current Year | $ / bbl | [2] | (0.1) | (0.07) | 0.06 | 0.13 | 0.03 | ||||||||||
Volume - Year One | bbl | [2] | 0 | 184,000 | 182,000 | 180,000 | 546,000 | ||||||||||
Price - Year One | $ / bbl | [2] | 0 | (0.27) | (0.27) | (0.27) | (0.27) | ||||||||||
Volume - Year Two | bbl | [2] | 2,208,000 | 2,208,000 | 2,184,000 | 2,184,000 | 8,784,000 | ||||||||||
Price - Year Two | $ / bbl | [2] | (0.09) | (0.09) | (0.09) | (0.09) | (0.09) | ||||||||||
Natural Gas Swap [Member] | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Volume - Current Year | MMBTU | [3] | 274,000 | 921,000 | 878,000 | 1,277,000 | 3,350,000 | ||||||||||
Price - Current Year | $ / MMBTU | [3] | 3.08 | 3.08 | 3.08 | 3.08 | 3.08 | ||||||||||
[1] | The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. | |||||||||||||||
[2] | The basis differential price is between Midland – WTI and Cushing – WTI. | |||||||||||||||
[3] | The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. |