Document And Entity Information
Document And Entity Information - USD ($) $ / shares in Units, $ in Billions | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 22, 2019 | Jun. 29, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | CARRIZO OIL & GAS INC | ||
Entity Central Index Key | 1,040,593 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 91,627,738 | ||
Share Price | $ 27.85 | ||
Entity Public Float | $ 2.2 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Shell Company | false | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 2,282,000 | $ 9,540,000 |
Accounts receivable, net | 99,723,000 | 107,441,000 |
Derivative assets | 39,904,000 | 0 |
Other current assets | 8,460,000 | 5,897,000 |
Total current assets | 150,369,000 | 122,878,000 |
Oil and gas properties, full cost method | ||
Proved properties, net | 2,333,470,000 | 1,965,347,000 |
Unproved properties, not being amortized | 673,833,000 | 660,287,000 |
Other property and equipment, net | 11,221,000 | 10,176,000 |
Total property and equipment, net | 3,018,524,000 | 2,635,810,000 |
Other long-term assets | 16,207,000 | 19,616,000 |
Total Assets | 3,185,100,000 | 2,778,304,000 |
Current liabilities | ||
Accounts payable | 98,811,000 | 74,558,000 |
Revenues and royalties payable | 49,003,000 | 52,154,000 |
Accrued capital expenditures | 60,004,000 | 119,452,000 |
Accrued interest | 18,377,000 | 28,362,000 |
Derivative liabilities | 55,205,000 | 57,121,000 |
Other current liabilities | 40,609,000 | 41,175,000 |
Total current liabilities | 322,009,000 | 372,822,000 |
Long-term debt | 1,633,591,000 | 1,629,209,000 |
Asset retirement obligations | 18,360,000 | 23,497,000 |
Derivative liabilities | 40,817,000 | 112,332,000 |
Deferred Tax Liabilities, Net | 8,017,000 | 3,635,000 |
Other long-term liabilities | 6,980,000 | 51,650,000 |
Liabilities | 2,029,774,000 | 2,193,145,000 |
Commitments and contingencies | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | 174,422,000 | 214,262,000 |
Shareholders’ equity | ||
Common stock, $0.01 par value, 180,000,000 shares authorized; 91,627,738 issued and outstanding as of December 31, 2018 and 81,454,621 issued and outstanding as of December 31, 2017 | 916,000 | 815,000 |
Additional paid-in capital | 2,131,535,000 | 1,926,056,000 |
Accumulated deficit | (1,151,547,000) | (1,555,974,000) |
Total shareholders’ equity | 980,904,000 | 370,897,000 |
Total Liabilities and Shareholders’ Equity | $ 3,185,100,000 | $ 2,778,304,000 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Temporary Equity, Shares Authorized | 10,000,000 | 10,000,000 |
Temporary Equity, Shares Issued | 200,000 | 250,000 |
Temporary Equity, Shares Outstanding | 200,000 | 250,000 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 180,000,000 | 180,000,000 |
Common stock, shares issued (in shares) | 91,627,738 | 81,454,621 |
Common stock, shares outstanding (in shares) | 91,627,738 | 81,454,621 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues | $ 1,065,942,000 | $ 745,888,000 | $ 443,594,000 |
Total revenues | 1,065,942,000 | 745,888,000 | 443,594,000 |
Costs and Expenses | |||
Lease operating | 161,596,000 | 139,854,000 | 98,717,000 |
Production taxes | 50,591,000 | 32,509,000 | 19,046,000 |
Ad valorem taxes | 10,422,000 | 7,267,000 | 5,559,000 |
Depreciation, depletion and amortization | 299,530,000 | 262,589,000 | 213,962,000 |
General and administrative, net | 68,617,000 | 66,229,000 | 74,972,000 |
(Gain) loss on derivatives, net | (6,709,000) | 59,103,000 | 49,073,000 |
Interest expense, net | 62,413,000 | 80,870,000 | 79,403,000 |
Impairment of proved oil and gas properties | 0 | 0 | 576,540,000 |
Loss on extinguishment of debt | 9,586,000 | 4,170,000 | 0 |
Other expense, net | 296,000 | 2,157,000 | 1,796,000 |
Total costs and expenses | 656,342,000 | 654,748,000 | 1,119,068,000 |
OTHER INCOME AND EXPENSES | |||
Income (Loss) Before Income Taxes | 409,600,000 | 91,140,000 | (675,474,000) |
Income tax expense | (5,173,000) | (4,030,000) | 0 |
Net Income (Loss) | 404,427,000 | 87,110,000 | (675,474,000) |
Dividends on preferred stock | (18,161,000) | (7,781,000) | 0 |
Accretion on preferred stock | (3,057,000) | (862,000) | 0 |
Gain (Loss) On Redemption Of Preferred Stock | (7,133,000) | 0 | 0 |
Net Income (Loss) Attributable to Common Shareholders | $ 376,076,000 | $ 78,467,000 | $ (675,474,000) |
Net Income (Loss) Attributable to Common Shareholders Per Common Share | |||
Net income (loss) per share, basic (in dollars per share) | $ 4.40 | $ 1.07 | $ (11.27) |
Net Income (Loss) Attributable to Common Shareholders Per Common Share - Diluted | |||
Net income (loss) per share, diluted (in dollars per share) | $ 4.32 | $ 1.06 | $ (11.27) |
Weighted Average Common Shares Outstanding | |||
Basic (in shares) | 85,509 | 73,421 | 59,932 |
Diluted (in shares) | 87,143 | 73,993 | 59,932 |
Oil and Condensate | |||
Revenues | $ 911,554,000 | $ 633,233,000 | $ 378,073,000 |
Natural Gas Liquids | |||
Revenues | 96,585,000 | 47,405,000 | 22,428,000 |
Natural Gas | |||
Revenues | $ 57,803,000 | $ 65,250,000 | $ 43,093,000 |
Consolidated Statements Of Shar
Consolidated Statements Of Shareholders' Equity - USD ($) | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Retained Earnings (Accumulated Deficit) [Member] |
Total shareholders' equity at Dec. 31, 2015 | $ 444,054,000 | $ 583,000 | $ 1,411,081,000 | $ (967,610,000) |
Total shareholders' equity, shares at Dec. 31, 2015 | 58,332,993 | |||
Stock-based compensation expense | 31,194,000 | 31,194,000 | ||
Issuance of common stock upon grants of employee stock awards or units | (55,000) | $ 8,000 | (63,000) | |
Issuance of common stock upon grants of employee stock awards or units, shares | 799,506 | |||
Sale of common stock, net of offering costs | $ 223,739,000 | $ 60,000 | 223,679,000 | |
Sale of common stock, net of offering costs, shares | 6,000,000 | 6,000,000 | ||
Dividends on preferred stock | $ 0 | |||
Accretion on preferred stock | 0 | |||
Gain (Loss) On Redemption Of Preferred Stock | 0 | |||
Net income (loss) | (675,474,000) | (675,474,000) | ||
Total shareholders' equity at Dec. 31, 2016 | 23,458,000 | $ 651,000 | 1,665,891,000 | (1,643,084,000) |
Total shareholders' equity, shares at Dec. 31, 2016 | 65,132,499 | |||
Stock-based compensation expense | 23,625,000 | 23,625,000 | ||
Issuance of common stock upon grants of employee stock awards or units | (34,000) | $ 8,000 | (42,000) | |
Issuance of common stock upon grants of employee stock awards or units, shares | 722,122 | |||
Sale of common stock, net of offering costs | $ 222,378,000 | $ 156,000 | 222,222,000 | |
Sale of common stock, net of offering costs, shares | 15,600,000 | 15,600,000 | ||
Proceeds from Issuance of Warrants | $ 23,003,000 | 23,003,000 | ||
Dividends on preferred stock | (7,781,000) | (7,781,000) | ||
Accretion on preferred stock | (862,000) | (862,000) | ||
Gain (Loss) On Redemption Of Preferred Stock | 0 | |||
Net income (loss) | 87,110,000 | 87,110,000 | ||
Total shareholders' equity at Dec. 31, 2017 | 370,897,000 | $ 815,000 | 1,926,056,000 | (1,555,974,000) |
Total shareholders' equity, shares at Dec. 31, 2017 | 81,454,621 | |||
Stock-based compensation expense | 20,412,000 | 20,412,000 | ||
Issuance of common stock upon grants of employee stock awards or units | (227,000) | $ 6,000 | (233,000) | |
Issuance of common stock upon grants of employee stock awards or units, shares | 673,117 | |||
Sale of common stock, net of offering costs | $ 213,746,000 | $ 95,000 | 213,651,000 | |
Sale of common stock, net of offering costs, shares | 9,500,000 | 9,500,000 | ||
Dividends on preferred stock | $ (18,161,000) | (18,161,000) | ||
Accretion on preferred stock | (3,057,000) | (3,057,000) | ||
Gain (Loss) On Redemption Of Preferred Stock | (7,133,000) | (7,133,000) | ||
Net income (loss) | 404,427,000 | 404,427,000 | ||
Total shareholders' equity at Dec. 31, 2018 | $ 980,904,000 | $ 916,000 | $ 2,131,535,000 | $ (1,151,547,000) |
Total shareholders' equity, shares at Dec. 31, 2018 | 91,627,738 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash Flows From Operating Activities | |||
Net income (loss) | $ 404,427 | $ 87,110 | $ (675,474) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||
Depreciation, depletion and amortization | 299,530 | 262,589 | 213,962 |
Impairment of proved oil and gas properties | 0 | 0 | 576,540 |
(Gain) loss on derivatives, net | (6,709) | 59,103 | 49,073 |
Cash received (paid) for derivative settlements, net | (96,307) | 7,773 | 119,369 |
Loss on extinguishment of debt | 9,586 | 4,170 | 0 |
Stock-based compensation expense, net | 13,524 | 14,309 | 36,086 |
Deferred income tax expense | 4,381 | 3,635 | 0 |
Non-cash interest expense, net | 2,567 | 3,657 | 4,172 |
Other, net | 4,216 | 2,337 | 3,753 |
Changes in components of working capital and other assets and liabilities- | |||
Accounts receivable | 24,008 | (41,630) | (12,836) |
Accounts payable | 16,013 | 11,822 | (30,130) |
Accrued liabilities | (19,154) | 11,512 | (7,938) |
Other assets and liabilities, net | (2,527) | (3,406) | (3,809) |
Net cash provided by operating activities | 653,555 | 422,981 | 272,768 |
Cash Flows From Investing Activities | |||
Capital expenditures | (968,828) | (654,711) | (480,929) |
Acquisitions of oil and gas properties | (204,854) | (695,774) | (153,521) |
Proceeds from divestitures of oil and gas properties | 381,434 | 197,564 | 15,564 |
Other, net | (3,720) | (6,531) | (946) |
Net cash used in investing activities | (795,968) | (1,159,452) | (619,832) |
Cash Flows From Financing Activities | |||
Issuance of senior notes, net of issuance costs | 0 | 245,418 | 0 |
Redemptions of senior notes and other long-term debt | (460,540) | (152,813) | 0 |
Redemption of preferred stock | (50,030) | 0 | 0 |
Borrowings under credit agreement | 3,309,400 | 1,992,523 | 770,291 |
Repayments of borrowings under credit agreement | (2,856,269) | (1,788,223) | (683,291) |
Payments of credit facility amendment fees | (1,674) | (4,469) | (1,330) |
Sale of common stock, net of offering costs | 213,746 | 222,378 | 223,739 |
Sale of preferred stock, net of issuance costs | 0 | 236,404 | 0 |
Payments of dividends on preferred stock | (18,161) | (7,781) | 0 |
Other, net | (1,317) | (1,620) | (1,069) |
Net cash provided by financing activities | 135,155 | 741,817 | 308,340 |
Net Increase (Decrease) in Cash and Cash Equivalents | (7,258) | 5,346 | (38,724) |
Cash and Cash Equivalents, Beginning of Year | 9,540 | 4,194 | 42,918 |
Cash and Cash Equivalents, End of Year | $ 2,282 | $ 9,540 | $ 4,194 |
Nature Of Operations
Nature Of Operations | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature Of Operations | 1. Nature of Operations Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and natural gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | 2. Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, fair value of preferred stock upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock. Cash and Cash Equivalents Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $70.4 million and $62.6 million as of December 31, 2018 and 2017 , respectively. Accounts Receivable The Company’s accounts receivable consist primarily of receivables from crude oil, NGL, and natural gas purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s receivables from the sale of crude oil are collected within one month and receivables from the sale of NGL and natural gas are collected within two months. The Company establishes an allowance for doubtful accounts when it determines it is probable that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. The Company’s allowance for doubtful accounts and bad debt expense was immaterial for all periods presented. Concentration of Credit Risk and Major Customers The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: Years Ended December 31, 2018 2017 2016 Shell Trading (US) Company 73% 69% 56% Flint Hills Resources, LP * * 15% * - Less than 10% for the respective year. The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with seventeen counterparties to minimize its credit exposure to any individual counterparty. Oil and Gas Properties Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred. Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds are assessed on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs along with associated capitalized interest are reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10% , (b) the costs of unproved properties not being amortized, and (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2018 , 2017 and 2016 , the Company did not have any sales of oil and gas properties that significantly altered such relationship. Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years. Debt Issuance Costs Debt issuance costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related senior notes. Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration arrangements determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration arrangements are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 13. Fair Value Measurements” for additional discussion. Asset Retirement Obligations The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or economic lives of the oil and gas wells, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations” for additional discussion. Commitments and Contingencies Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies” for additional discussion. Revenue Recognition The Company’s revenues are comprised solely of revenues from customers and include the sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of December 31, 2018 and December 31, 2017 , receivables from contracts with customers were $77.1 million and $85.6 million , respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of operations. Crude oil sales. Crude oil production is primarily sold at the wellhead at an agreed upon index price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the wellhead, net of transportation costs incurred by the purchaser. Natural gas and NGL sales. Natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. The Company evaluates whether it is the principal or agent in the transaction and has concluded it is the principal and the purchasers of the NGLs and residue gas are the customers. Revenue is recognized on a gross basis, with gathering, processing and transportation fees recognized as lease operating expense in the consolidated statements of operations as the Company maintains control throughout processing. Transaction Price Allocated to Remaining Performance Obligations . The Company applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative purposes. The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets. The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of operations in the period in which the changes occur. Deferred premium obligations associated with the Company’s commodity derivative instruments are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of operations in the period in which the deferred premium obligations are incurred. Cash flows are impacted to the extent that settlements of commodity derivative instruments, including deferred premium obligations, and contingent consideration arrangements result in cash received or paid during the period and are recognized as “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows. Cash received or paid in settlement of contingent consideration assets or liabilities, respectively, are classified as cash flows from financing activities up to the divestiture or acquisition date fair value with any excess classified as cash flows from operating activities. The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 12. Derivative Instruments” for additional discussion. Preferred Stock and Common Stock Warrants The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets. When preferred stock is issued with common stock warrants, the common stock warrants are evaluated separately to determine if they are a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the common stock warrants for equity classification and has determined they qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and common stock warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The common stock warrants do not require further adjustments from their relative fair value at the issuance date. Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows. See “Note 9. Preferred Stock and Common Stock Warrants” for further details of the Company’s outstanding preferred stock and common stock warrants. Stock-Based Compensation The Company recognized stock-based compensation expense, net of amounts capitalized to oil and gas properties associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“Cash SARs”), and performance share awards, which is recognized as “General and administrative expense, net” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 11. Stock-Based Compensation” for further details of the awards discussed below. Restricted Stock Awards and Units . Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on the fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. Stock Appreciation Rights. For Cash SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the straight-line method, except for Cash SARs with performance conditions, in which case the Company uses the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the Cash SAR. The liability for Cash SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months, with the remainder classified as “Other long-term liabilities” in the consolidated balance sheets. Cash SARs typically expire between five and seven years after the date of grant. If Cash SARs expire unexercised, the cumulative compensation costs associated with such Cash SARs will be zero . Performance Shares. For performance shares, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. Each performance share represents the right to receive one share of common stock, however, the number of performance shares that vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three year performance period, the last day of which is also the vesting date. Compensation costs related to the performance shares will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved. Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized. Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance shares, and common stock warrants. The Company includes the number of restricted stock awards and units and common stock warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance shares in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. The Company has excluded any impact of the preferred stock to the calculation of diluted weighted average common shares outstanding as it has the positive intent and ability to redeem the preferred stock in cash. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. The following table summarizes the calculation of net income (loss) attributable to common shareholders per common share: Years Ended December 31, 2018 2017 2016 (In thousands, except per share amounts) Net Income (Loss) $404,427 $87,110 ($675,474 ) Dividends on preferred stock (18,161 ) (7,781 ) — Accretion on preferred stock (3,057 ) (862 ) — Loss on redemption of preferred stock (7,133 ) — — Net Income (Loss) Attributable to Common Shareholders $376,076 $78,467 ($675,474 ) Basic weighted average common shares outstanding 85,509 73,421 59,932 Dilutive effect of restricted stock and performance shares 949 269 — Dilutive effect of common stock warrants 685 303 — Diluted weighted average common shares outstanding 87,143 73,993 59,932 Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $4.40 $1.07 ($11.27 ) Diluted $4.32 $1.06 ($11.27 ) The computation of diluted net income attributable to common shareholders per common share excluded certain restricted stock and performance shares as the impacts were anti-dilutive. The following table presents the weighted average anti-dilutive securities for the periods presented: Years Ended December 31, 2018 2017 2016 (In thousands) Anti-dilutive restricted stock and performance shares 19 52 669 Industry Segment and Geographic Information The Company operates in only one industry segment, w |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Acquisitions and Divestitures [Abstract] | |
Acquisitions and Divestitures Disclosures | 3. Acquisitions and Divestitures of Oil and Gas Properties 2018 Acquisitions and Divestitures Devon Acquisition. On August 13, 2018, the Company entered into a purchase and sale agreement with Devon Energy Production Company, L.P. (“Devon”), a subsidiary of Devon Energy Corporation, to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas (the “Devon Properties”) for an agreed upon price of $215.0 million , with an effective date of April 1, 2018, subject to customary purchase price adjustments (the “Devon Acquisition”). The Company paid $21.5 million as a deposit on August 13, 2018 and $183.4 million upon initial closing on October 17, 2018, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Company estimates the aggregate purchase price will be $196.6 million , however, the final purchase price remains subject to post-closing adjustments. The Company funded the Devon Acquisition with net proceeds from the common stock offering completed on August 17, 2018, which, pending the closing of the Devon Acquisition, were used to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 10. Shareholders’ Equity” for further discussion. The Devon Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase Price Allocation (In thousands) Assets Oil and gas properties Proved properties $47,370 Unproved properties 150,253 Total oil and gas properties $197,623 Total assets acquired $197,623 Liabilities Revenues and royalties payable $855 Asset retirement obligations 170 Total liabilities assumed $1,025 Net Assets Acquired $196,598 The results of operations for the Devon Acquisition have been included in the Company’s consolidated statements of operations since the October 17, 2018 closing date, including total revenues $4.6 million and net income attributable to common shareholders of $2.7 million for the year ended December 31, 2018 . Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017 , assuming the Devon Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Devon Acquisition. Years Ended December 31, 2018 2017 (In thousands, except per share amounts) Total revenues $1,086,742 $753,474 Net Income Attributable to Common Shareholders $384,639 $78,118 Net Income Attributable to Common Shareholders Per Common Share Basic $4.21 $0.94 Diluted $4.13 $0.94 Weighted Average Common Shares Outstanding Basic 91,444 82,921 Diluted 93,077 83,493 Delaware Basin Divestiture. On July 11, 2018, the Company closed on the divestiture of certain non-operated assets in the Delaware Basin for an agreed upon price of $30.0 million , with an effective date of May 1, 2018, subject to customary purchase price adjustments. The Company received $31.4 million upon closing on July 11, 2018 and paid $0.5 million upon post-closing on October 22, 2018, for aggregate net proceeds of $30.9 million . Eagle Ford Divestiture. On December 11, 2017, the Company entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of its assets in the Eagle Ford Shale for an agreed upon price of $245.0 million , with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. The Company received $24.5 million as a deposit on December 11, 2017, $211.7 million upon closing on January 31, 2018, $10.0 million for leases that were not conveyed at closing on February 16, 2018, and paid $0.5 million upon post-closing on July 19, 2018, for aggregate net proceeds of $245.7 million . Niobrara Divestiture. On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million , with an effective date of October 1, 2017, subject to customary purchase price adjustments. The Company received $14.0 million as a deposit on November 20, 2017, $122.6 million upon closing on January 19, 2018, and paid $1.0 million upon post-closing on August 14, 2018, for aggregate net proceeds of $135.6 million . As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. See “Note 12. Derivative Instruments” and “Note 13. Fair Value Measurements” for further discussion. The aggregate net proceeds for each of the 2018 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized. 2017 Acquisitions and Divestitures ExL Acquisition. On June 28, 2017, the Company entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward counties, Texas for an agreed upon price of $648.0 million , with an effective date of May 1, 2017, subject to customary purchase price adjustments (the “ExL Acquisition”). The Company paid $75.0 million as a deposit on June 28, 2017, $601.0 million upon closing on August 10, 2017 and $3.8 million upon post-closing on December 8, 2017, for an aggregate cash consideration of $679.8 million , which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. As part of the ExL Acquisition, the Company agreed to a contingent consideration arrangement (the “Contingent ExL Consideration”), which was determined to be an embedded derivative. See “Note 12. Derivative Instruments” and “Note 13. Fair Value Measurements” for further discussion. The Company funded the ExL Acquisition with net proceeds from the sale of preferred stock on August 10, 2017, net proceeds from the common stock offering completed on July 3, 2017, and net proceeds from the senior notes offering completed on July 14, 2017. See “Note 9. Preferred Stock and Common Stock Warrants”, “Note 10. Shareholders’ Equity” and “Note 6. Long-Term Debt” for further discussion. The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note 13. Fair Value Measurements” for further discussion. The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $106 Oil and gas properties Proved properties 294,754 Unproved properties 443,194 Total oil and gas properties $737,948 Total assets acquired $738,054 Liabilities Revenues and royalties payable $5,785 Asset retirement obligations 153 Contingent ExL Consideration 52,300 Total liabilities assumed $58,238 Net Assets Acquired $679,816 The results of operations for the ExL Acquisition have been included in the Company’s consolidated statements of operations since the August 10, 2017 closing date, including total revenues and net income attributable to common shareholders for the years ended December 31, 2018 and 2017 as shown in the table below: Years Ended December 31, 2018 2017 (In thousands) Total revenues $225,135 $53,548 Net Income Attributable to Common Shareholders $176,881 $44,304 Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition. Years Ended December 31, 2017 2016 (In thousands, except per share amounts) Total revenues $781,378 $454,913 Net Income (Loss) Attributable to Common Shareholders $91,931 ($688,180 ) Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.25 ($9.11 ) Diluted $1.24 ($9.11 ) Weighted Average Common Shares Outstanding Basic 73,421 75,532 Diluted 73,993 75,532 Marcellus Divestiture. On October 5, 2017, the Company entered into a purchase and sale agreement with BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an agreed upon price of $84.0 million . The Company received $6.3 million into escrow as a deposit on October 5, 2017 and $67.6 million upon closing on November 21, 2017, for aggregate net proceeds of $73.9 million . As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Marcellus Consideration”), which was determined to be an embedded derivative. See “Note 12. Derivative Instruments” and “Note 13. Fair Value Measurements” for further discussion. Effective August 2008, the Company’s wholly-owned subsidiary, Carrizo (Marcellus) LLC, entered into a joint venture with ACP II Marcellus LLC (“ACP II”), an affiliate of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP, together with its affiliates, “Avista”). There have been no revenues, expenses, or operating cash flows in the Avista Marcellus joint venture during the years ended December 31, 2018, 2017, and 2016. The Avista Marcellus joint venture agreements terminated during the third quarter of 2018 in connection with the sale of the remaining immaterial assets. Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which has the ability to control Avista and its affiliates. ACP II’s Board of Managers has the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACP II. Mr. Webster is not a member of ACP II’s Board of Managers. The terms of the Avista Marcellus joint venture were approved by a special committee of the Company’s independent directors. Additionally, in 2018, the Company’s Board of Directors determined that Mr. Webster is independent with respect to the Company. Utica Divestiture . On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale for an agreed upon price of $62.0 million . The Company received $6.2 million as a deposit on August 31, 2017, $54.4 million upon closing on November 15, 2017, and $2.5 million upon post-closing on December 28, 2017, for aggregate net proceeds of $63.1 million . As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Utica Consideration”), which was determined to be an embedded derivative. See “Note 12. Derivative Instruments” and “Note 13. Fair Value Measurements” for further discussion. Delaware Basin Divestiture. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for aggregate net proceeds of $15.3 million . The aggregate net proceeds for each of the 2017 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized. 2016 Acquisitions and Divestitures Sanchez Acquisition. On October 24, 2016, the Company entered into a purchase and sale agreement with Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation to acquire oil and gas properties located in the Eagle Ford Shale for an agreed upon price of $181.0 million , with an effective date of June 1, 2016, subject to customary purchase price adjustments (the “Sanchez Acquisition”). The Company paid $10.0 million as a deposit on October 24, 2016, $143.5 million upon initial closing on December 14, 2016, and $7.0 million and $9.8 million on January 9, 2017 and April 13, 2017, respectively, for leases that were not conveyed to the Company at the time of the initial closing, for aggregate cash consideration of $170.3 million , which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Sanchez Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then currently available information. The results of operations for the Sanchez Acquisition have been included in the Company’s consolidated statements of operations since the December 14, 2016 closing date, including total revenues and net income attributable to common shareholders for the years ended December 31, 2018 , 2017 , and 2016 as shown in the table below: Years Ended December 31, 2018 2017 2016 (In thousands) Total revenues $57,780 $37,780 $1,459 Net Income Attributable to Common Shareholders $38,551 $16,459 $966 The Company did not have any material divestitures for the year ended December 31, 2016 . |
Property And Equipment, Net
Property And Equipment, Net | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property And Equipment, Net | 4. Property and Equipment, Net As of December 31, 2018 and 2017 , total property and equipment, net consisted of the following: December 31, 2018 2017 Oil and gas properties, full cost method (In thousands) Proved properties $6,278,321 $5,615,153 Accumulated DD&A and impairments (3,944,851 ) (3,649,806 ) Proved properties, net 2,333,470 1,965,347 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 608,830 612,589 Capitalized interest 65,003 47,698 Total unproved properties, not being amortized 673,833 660,287 Other property and equipment 29,191 25,625 Accumulated depreciation (17,970 ) (15,449 ) Other property and equipment, net 11,221 10,176 Total property and equipment, net $3,018,524 $2,635,810 The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $17.0 million , $14.8 million and $10.5 million for the years ended December 31, 2018, 2017 and 2016 , respectively. The Company capitalized interest costs to unproved properties totaling $36.6 million , $28.3 million and $17.0 million for the years ended December 31, 2018, 2017 and 2016 , respectively. Costs not subject to amortization totaling $673.8 million at December 31, 2018 were incurred in the following periods: $218.9 million in 2018 , $397.7 million in 2017 and $57.2 million in 2016 . Impairments of Proved Oil and Gas Properties The Company did not recognize impairments of proved oil and gas properties for the years ended December 31, 2018 and 2017 . Primarily due to declines in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of proved oil and gas properties of $576.5 million for the year ended December 31, 2016. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 5. Income Taxes The components of income tax expense were as follows: Years Ended December 31, 2018 2017 2016 (In thousands) Current income tax expense U.S. Federal $— $— $— State (792 ) (395 ) — Total current income tax expense (792 ) (395 ) — Deferred income tax expense U.S. Federal — — — State (4,381 ) (3,635 ) — Total deferred income tax expense (4,381 ) (3,635 ) — Income tax expense ($5,173 ) ($4,030 ) $— The Company’s income tax expense differs from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016, to income (loss) before income taxes as follows: Years Ended December 31, 2018 2017 2016 (In thousands) Income (loss) before income taxes $409,600 $91,140 ($675,474 ) Income tax (expense) benefit at the U.S. federal statutory rate (86,016 ) (31,899 ) 236,416 State income tax (expense) benefit, net of U.S. federal income tax benefit (5,173 ) (4,030 ) 3,894 Tax deficiencies related to stock-based compensation (2,572 ) (3,089 ) — Provisional impact of Tax Cuts and Jobs Act — (211,724 ) — Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act — 211,724 — (Increase) decrease in valuation allowance due to current period activity 90,116 35,376 (240,864 ) Other (1,528 ) (388 ) 554 Income tax expense ($5,173 ) ($4,030 ) $— Significant changes in the Company’s operations impact the apportionment of taxable income to the states where the Company owns oil and gas properties. As discussed in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties,” beginning in 2017 and continuing into 2018, the Company divested all of its assets in Marcellus, Utica, and Niobrara, and is currently operating solely in Texas. This operational shift has resulted in current and deferred tax liabilities in Texas that cannot be offset against the full valuation allowance that the Company has maintained. Deferred Income Taxes As of December 31, 2018 and 2017 , the net deferred income tax liabilities are comprised of the following: December 31, 2018 2017 (In thousands) Deferred income tax liabilities Oil and gas properties ($16,610 ) ($3,635 ) Derivative assets (10,008 ) (2,140 ) Total deferred income tax liabilities (26,618 ) (5,775 ) Deferred income tax assets Net operating loss carryforward - U.S. federal and state 235,788 242,915 Oil and gas properties — 50,177 Asset retirement obligations 3,927 4,996 Derivative liabilities 20,165 35,585 Other 1,634 1,496 Total deferred income tax assets 261,514 335,169 Deferred income tax asset valuation allowance (242,913 ) (333,029 ) Net deferred income tax assets 18,601 2,140 Net deferred income tax liabilities ($8,017 ) ($3,635 ) Tax Cuts and Jobs Act On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. Due to the uncertainty regarding the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 (“SAB 118”) which allowed the Company to provide a provisional estimate of the impacts of the Act in its earnings for the year ended December 31, 2017 and also provided a one-year measurement period in which the Company would record additional impacts from the enactment of the Act as they are identified. As a result, the Company remeasured its deferred tax balances by applying the reduced rate and recorded a provisional deferred tax expense of $211.7 million during the year ended December 31, 2017. This provisional deferred tax expense was fully offset by a $211.7 million deferred tax benefit as a result of the associated change in the valuation allowance against the net deferred tax assets. As reflected in the rate reconciliation above, the change in the deferred tax balances due to the rate reduction had no impact on the net deferred tax balances reported in the consolidated balance sheets as of December 31, 2017 and no impact in the consolidated statements of operations for the year ended December 31, 2017. In August 2018, the Internal Revenue Service (“IRS”) issued Notice 2018-68, Guidance on the Application of Section 162(m) (“Notice 2018-68”), which provides initial guidance on the application of Section 162(m), as amended. Notice 2018-68 provided guidance regarding the group of covered employees subject to Section 162(m)’s deduction limit under the Act and the scope of transition relief available under the Act. In November 2018, the IRS issued proposed regulations on business interest expense deduction limitations for tax years beginning after 2017, which included an expanded definition of what is considered interest expense as well as changes to the calculation of a taxpayer’s adjusted taxable income in computing the interest expense limitation. The Company has assessed these proposed regulations as they pertain to the provisional tax estimate for the year ended December 31, 2018, and has concluded it will have no interest expense deduction limitation to be carried forward to future years for the 2018 tax year. As of December 31, 2018, the Company has completed its accounting for the tax effects of enactment of the Act, with immaterial changes made to the provisional estimate that was recorded in earnings for the year ended December 31, 2017. Deferred Tax Asset Valuation Allowance The deferred tax asset valuation allowance was $242.9 million , $333.0 million , and $564.4 million as of December 31, 2018, 2017, and 2016, respectively. Effective January 1, 2017, the Company adopted ASU 2016-09, and recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017. Decreases in the valuation allowance for the years ended December 31, 2018 and 2017 were based primarily on the pre-tax income recorded during those periods. Throughout 2016, 2017, and 2018, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not the deferred taxes would not be realized. The Company intends to maintain a full valuation allowance against its deferred tax assets until there is sufficient evidence to support the reversal of such valuation allowance. Net Operating Loss Carryforwards and Other Net Operating Loss Carryforwards. As of December 31, 2018 , the Company had U.S. federal net operating loss carryforwards of approximately $1,062.5 million that, if not utilized in earlier periods, will expire between 2026 and 2037 . The ability of the Company to utilize its U.S. loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the Company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Due to the issuance of the Preferred Stock and the common stock offering associated with the ExL Acquisition, as well as the common stock offering in August 2018, the Company’s calculated ownership change percentage increased, however, as of December 31, 2018, the Company did not have a Section 382 limitation on the ability to utilize its U.S. net operating loss carryforwards. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes and therefore a limitation on the annual utilization of the U. S. net operating loss carryforwards. Other. The Company files income tax returns in the U.S. federal jurisdiction and various states, each with varying statutes of limitations. The 2006 through 2018 tax years generally remain subject to examination by federal and state tax authorities. As of December 31, 2018 , 2017 and 2016 , the Company had no uncertain tax positions. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt | 6. Long-Term Debt Long-term debt consisted of the following as of December 31, 2018 and 2017 : December 31, 2018 2017 (In thousands) Senior Secured Revolving Credit Facility due 2022 $744,431 $291,300 7.50% Senior Notes due 2020 — 450,000 Unamortized premium for 7.50% Senior Notes — 579 Unamortized debt issuance costs for 7.50% Senior Notes — (4,492 ) 6.25% Senior Notes due 2023 650,000 650,000 Unamortized debt issuance costs for 6.25% Senior Notes (6,878 ) (8,208 ) 8.25% Senior Notes due 2025 250,000 250,000 Unamortized debt issuance costs for 8.25% Senior Notes (3,962 ) (4,395 ) Other long-term debt due 2028 — 4,425 Long-term debt $1,633,591 $1,629,209 Senior Secured Revolving Credit Facility The Company has a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2018 , had a borrowing base of $1.3 billion , with an elected commitment amount of $1.1 billion , and borrowings outstanding of $744.4 million at a weighted average interest rate of 4.17% . The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement. On January 31, 2018, as a result of the Eagle Ford divestiture, the Company’s borrowing base under the senior secured revolving credit facility was reduced from $900.0 million to $830.0 million , however, the elected commitment amount remained unchanged at $800.0 million . See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for details of the Eagle Ford divestiture. On May 4, 2018, the Company entered into the twelfth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $1.0 billion , with an elected commitment amount of $900.0 million , until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from 2.00% - 3.00% to 1.50% - 2.50% and base rate loans from 1.00% - 2.00% to 0.50% - 1.50% , each depending on level of facility usage, (iii) amend the covenant limiting payment of dividends and distributions on equity to increase the Company’s ability to make dividends and distributions on its equity interests and (iv) amend certain other provisions, in each case as set forth therein. On October 29, 2018, the Company entered into the thirteenth amendment to its credit agreement governing its revolving credit facility to, among other things, (i) establish the borrowing base at $1.3 billion , with an elected commitment amount of $1.1 billion , until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from 1.50% - 2.50% to 1.25% - 2.25% and base rate loans from 0.50% - 1.50% to 0.25% - 1.25% , each depending on the level of facility usage and each subject to an increase of 0.25% for any period during which the ratio of Total Debt to EBITDA exceeds 3.00 to 1.00, (iii) amend the definition of Capital Leases, and (iv) amend certain other definitions and provisions. The obligations of the Company under the credit agreement are guaranteed by the Company’s material subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination. Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00% , or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations. Ratio of Outstanding Borrowings to Lender Commitments Applicable Margin for Base Rate Loans Applicable Margin for Eurodollar Loans Commitment Fee Less than 25% 0.25% 1.25% 0.375% Greater than or equal to 25% but less than 50% 0.50% 1.50% 0.375% Greater than or equal to 50% but less than 75% 0.75% 1.75% 0.500% Greater than or equal to 75% but less than 90% 1.00% 2.00% 0.500% Greater than or equal to 90% 1.25% 2.25% 0.500% The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt issuance costs and is net of cash and cash equivalents, EBITDA will be calculated based on the last four fiscal quarters after giving pro forma effect to EBITDA for material acquisitions and divestitures of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of December 31, 2018 , the ratio of Total Debt to EBITDA was 2.41 to 1.00 and the Current Ratio was 1.51 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings. The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions and divestitures of oil and gas properties, mergers, transactions with affiliates, hedging transactions and other matters. The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). Senior Notes 8.25% Senior Notes due 2025. On July 14, 2017, the Company closed a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 (the “ 8.25% Senior Notes”), which mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. The Company used the net proceeds of $245.4 million , net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for the ExL Acquisition that closed during the third quarter of 2017 and for general corporate purposes. 6.25% Senior Notes due 2023. Since April 15, 2018, the Company has had the right to redeem all or a portion of the 6.25% Senior Notes due 2023 (the “ 6.25% Senior Notes”) at redemption prices decreasing from 104.688% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest. If a Change of Control (as defined in the indentures governing the 8.25% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. The indentures governing the 8.25% Senior Notes and the 6.25% Senior Notes contain covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments. At December 31, 2018 , the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility. Redemptions of 7.50% Senior Notes During the fourth quarter of 2017, the Company redeemed $150.0 million of the outstanding aggregate principal amount of its 7.50% Senior Notes at a price equal to 101.875% of par, plus accrued and unpaid interest. The Company paid $156.0 million upon the redemption, which included a redemption premium of $2.8 million and accrued and unpaid interest of $3.2 million . As a result of the redemption, the Company recorded a loss on extinguishment of debt of $4.2 million , which included the redemption premium of $2.8 million and the write-off of associated unamortized premiums and debt issuance costs of $1.4 million . During the first and fourth quarters of 2018, the Company redeemed $320.0 million of the outstanding aggregate principal amount of its 7.50% Senior Notes at a price equal to 101.875% of par and the remaining $130.0 million outstanding aggregate principal amount at a redemption price of 100% of par, respectively, both plus accrued and unpaid interest. The Company paid a total of $468.6 million upon the redemptions, which included redemption premiums of $6.0 million and accrued and unpaid interest of $12.6 million . As a result of the redemptions, the Company recorded a loss on extinguishment of debt of $9.6 million , which included the redemption premiums of $6.0 million and the write-off of associated unamortized premiums and debt issuance costs of $3.6 million . Redemption of Other Long-Term Debt On May 3, 2018, the Company redeemed the remaining $4.4 million outstanding aggregate principal amount of its 4.375% Convertible Senior Notes due 2028 at a price equal to 100% of par. Upon the redemption, the Company paid $4.5 million , which included accrued and unpaid interest of $0.1 million . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 7. Asset Retirement Obligations The following table sets forth a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (In thousands) Asset retirement obligations, beginning of period $23,792 $21,240 Liabilities incurred 1,676 3,920 Increase due to acquisition of oil and gas properties 170 153 Liabilities settled — (343 ) Reduction due to divestitures of oil and gas properties (8,547 ) (2,671 ) Accretion expense 1,366 1,799 Revisions to estimated cash flows 245 (306 ) Asset retirement obligations, end of period 18,702 23,792 Current asset retirement obligations (included in other current liabilities) (342 ) (295 ) Non-current asset retirement obligations $18,360 $23,497 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 8. Commitments and Contingencies From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. Pursuant to various purchase and sale agreements related to our divested assets in the Eagle Ford Shale, Marcellus Shale, Utica Shale, and Niobrara Formation, the Company has indemnified the respective purchasers against certain liabilities that they may incur with respect to the assets acquired from the Company. The Company believes such indemnities are customary in purchase and sale transactions in our industry. Such indemnities may include, among others, breach of representations and warranties, tax liabilities, employee compensation, litigation, personal injury, transport or disposal of hazardous substances, calculation and payments of royalties, environmental matters and rights-of-way. While the outcome of these events cannot be predicted with certainty, as of December 31, 2018, management does not expect these indemnifications to have a materially adverse effect on the financial position or results of operations of the Company. The financial position and results of operations of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, tax changes, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable. Rent expense included in general and administrative expense, net for the years ended December 31, 2018 , 2017 and 2016 was $1.4 million , $1.7 million , and $2.0 million , respectively, and includes rent expense for the Company’s corporate and field offices. The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of natural gas or produced water to be delivered, as of December 31, 2018 . 2019 2020 2021 2022 2023 2024 and Thereafter Total (In thousands) Operating leases $10,024 $9,154 $6,249 $3,639 $3,680 $20,978 $53,724 Drilling rig contracts (1) 37,077 16,867 813 — — — 54,757 Delivery commitments (2) 3,726 2,807 2,487 30 7 19 9,076 Produced water disposal commitments (3) 18,139 20,894 20,898 20,954 10,471 9,769 101,125 Other 1,800 1,050 — — — — 2,850 Total $70,766 $50,772 $30,447 $24,623 $14,158 $30,766 $221,532 (1) Drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will generally be billed for their working interest share of such costs. (2) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas. (3) Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2018 | |
Preferred Stock [Abstract] | |
Preferred Stock | 9. Preferred Stock and Common Stock Warrants On August 20, 2017, the Company closed on the issuance and sale in a private placement of (i) $250.0 million initial liquidation preference ( 250,000 shares) of 8.875% redeemable preferred stock, par value $0.01 per share (the “Preferred Stock”) and (ii) warrants for 2,750,000 shares of the Company’s common stock, with a term of ten years and an exercise price of $16.08 per share, exercisable only on a net share settlement basis (the “Warrants”), for a cash purchase price equal to $970.00 per share of Preferred Stock to certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”). The closing occurred contemporaneously with the closing of the ExL Acquisition. The Company used the proceeds of approximately $236.4 million , net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. Net proceeds were allocated between the Preferred Stock and the Warrants based on their relative fair values at the issuance date, with $213.4 million allocated to the Preferred Stock and $23.0 million allocated to the Warrants. The fair value of the Preferred Stock was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the per share cash purchase price, redemption premiums, and liquidation preference, all as discussed further below, as well as redemption assumptions provided by the Company. The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $16.08 Expected term (in years) 10.0 Expected volatility 62.9 % Risk-free interest rate 2.2 % Dividend yield — % See “Note 13. Fair Value Measurements” for further discussion of the significant inputs used in the Preferred Stock fair value calculation. The Preferred Stock is presented as temporary equity in the consolidated balance sheets with the issuance date fair value accreted to the initial liquidation preference using the effective interest method. The Warrants are presented in “Additional paid-in capital” in the consolidated balance sheets at their issuance date fair value. The following table sets forth a reconciliation of changes in the carrying amount of Preferred Stock for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (In thousands) Preferred Stock, beginning of period $214,262 $— Relative fair value at issuance — 213,400 Redemption of Preferred Stock (42,897 ) — Accretion on Preferred Stock 3,057 862 Preferred Stock, end of period $174,422 $214,262 The Preferred Stock has a liquidation preference of $1,000.00 per share and bears an annual cumulative dividend rate of 8.875% , payable on March 15, June 15, September 15 and December 15 of any given year. The Company may elect to pay all or a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any preferred stock dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending: Period Percentage On or after December 15, 2018 and on or prior to September 15, 2019 75 % On or after December 15, 2019 and on or prior to September 15, 2020 50 % If the Company fails to satisfy the Preferred Stock dividend on the applicable dividend payment date, then the unpaid dividend will be added to the liquidation preference until paid. The Preferred Stock outstanding is not mandatorily redeemable, but can be redeemed at the Company’s option and, in certain circumstances, at the option of the holders of the Preferred Stock. On or prior to August 10, 2018, the Company had the right to redeem up to 50,000 shares of Preferred Stock, in cash, at $1,000.00 per share, plus accrued and unpaid dividends in an amount not to exceed the sum of the cash proceeds of divestitures of oil and gas properties and related assets, the sale or issuance of the Company’s common stock and the sale of any of the Company’s wholly owned subsidiaries. In addition, at any time on or prior to August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at a redemption premium of 104.4375% , plus accrued and unpaid dividends and the present value on the redemption date of all quarterly dividends that would be payable from the redemption date through August 10, 2020. After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends. Period Percentage After August 10, 2020 but on or prior to August 10, 2021 104.4375 % After August 10, 2021 but on or prior to August 10, 2022 102.21875 % After August 10, 2022 100 % The holders of the Preferred Stock have the option to cause the Company to redeem the Preferred Stock under the following conditions: • Upon the Company’s failure to pay a quarterly dividend within three months of the applicable payment date; • On or after August 10, 2024, if the Preferred Shares remain outstanding; or • Upon the occurrence of certain changes of control. For the first two conditions described above, the Company has the option to settle any such redemption in cash or shares of its common stock and the holders of the Preferred Stock may elect to revoke or reduce the redemption if the Company elects to settle in shares of common stock. The Preferred Stock are non-voting shares except as required by the Company’s articles of incorporation or bylaws. However, so long as the GSO Funds beneficially own more than 50% of the Preferred Stock, the consent of the holders of the Preferred Stock will be required prior to issuing stock senior to or on parity with the Preferred Stock, incurring indebtedness subject to a leverage ratio, agreeing to certain restrictions on dividends on, or redemption of, the Preferred Stock and declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year subject to a leverage ratio. Additionally, if the Company does not redeem the Preferred Stock before August 10, 2024, in connection with a change of control or failure to pay a quarterly dividend within three months of the applicable payment date, the holders of the Preferred Stock are entitled to additional rights including: • Increasing the dividend rate to 12.0% per annum until August 10, 2024 and thereafter to the greater of 12.0% per annum and the one-month LIBOR plus 10.0% ; • Electing up to two directors to the Company’s Board of Directors; and • Requiring approval by the holders of the Preferred Stock to incur indebtedness subject to a leverage ratio, declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year or issuing equity of the Company’s subsidiaries to third parties. Loss on Redemption of Preferred Stock During the first quarter of 2018, the Company redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million , consisting of the $50.0 million redemption price and accrued and unpaid dividends of $0.5 million . The Company recognized a $7.1 million loss on the redemption due to the excess of the $50.0 million redemption price over the $42.9 million redemption date carrying value of the Preferred Stock. |
Shareholder's Equity
Shareholder's Equity | 12 Months Ended |
Dec. 31, 2018 | |
Shareholder's Equity [Abstract] | |
Stockholders' Equity Note Disclosure | 10. Shareholders’ Equity Increase in Authorized Common Shares At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 90,000,000 to 180,000,000 . Sales of Common Stock On August 17, 2018, the Company completed a public offering of 9.5 million shares of its common stock at a price per share of $22.55 . The Company used the proceeds of $213.7 million , net of offering costs, to fund the Devon Acquisition and for general corporate purposes. Pending the closing of the Devon Acquisition, the Company used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. On July 3, 2017, the Company completed a public offering of 15.6 million shares of its common stock at a price per share of $14.28 . The Company used the proceeds of $222.4 million , net of offering costs, to fund a portion of the ExL Acquisition and for general corporate purposes. On October 28, 2016, the Company completed a public offering of 6.0 million shares of its common stock at a price per share of $37.32 . The Company used the proceeds of $223.7 million , net of offering costs, to fund the Sanchez Acquisition and repay borrowings under the revolving credit facility. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the acquisitions discussed above. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Shareholders' Equity And Stock Incentive Plan [Abstract] | |
Shareholders' Equity And Stock Incentive Plan | 11. Stock-Based Compensation Equity-based incentive awards are granted under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”) and the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The 2017 Incentive Plan replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”) and, from the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan. However, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. Under the 2017 Incentive Plan, the Compensation Committee of the Board of Directors (the “Committee”) may grant restricted stock awards and units, stock appreciation rights that can be settled in cash or shares of common stock, performance shares, and stock options to employees, independent contractors, and non-employee directors. Under the Cash SAR Plan, the Committee may grant stock appreciation rights that may only be settled in cash to employees and independent contractors. The 2017 Incentive Plan provides that up to 2,675,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan at the effective date of the 2017 Incentive Plan, may be granted (the “Maximum Share Limit”). Each restricted stock award and unit and performance share granted under the 2017 Incentive Plan counts as 1.35 shares against the Maximum Share Limit. Each stock option and stock appreciation right to be settled in shares of common stock granted under the 2017 Incentive Plan counts as 1.00 share against the Maximum Share Limit. Cash SARs granted under the 2017 Incentive Plan and the Cash SAR Plan do not count against the Maximum Share Limit. There have been no grants of stock appreciation rights to be settled in shares of common stock and there are no outstanding stock options. As of December 31, 2018 , there were 258,785 shares of common stock available for grant under the 2017 Incentive Plan. Restricted Stock Awards and Units The table below summarizes restricted stock award and unit activity for the years ended December 31, 2018 , 2017 and 2016 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2016 Unvested restricted stock awards and units, beginning of period 1,041,997 $44.22 Granted 887,254 $27.80 Vested (811,136 ) $36.32 Forfeited (6,405 ) $34.46 Unvested restricted stock awards and units, end of period 1,111,710 $36.93 For the Year Ended December 31, 2017 Unvested restricted stock awards and units, beginning of period 1,111,710 $36.93 Granted 1,020,465 $25.63 Vested (635,965 ) $39.62 Forfeited (13,555 ) $29.11 Unvested restricted stock awards and units, end of period 1,482,655 $28.07 For the Year Ended December 31, 2018 Unvested restricted stock awards and units, beginning of period 1,482,655 $28.07 Granted 1,458,421 $15.49 Vested (621,399 ) $31.48 Forfeited (53,010 ) $17.72 Unvested restricted stock awards and units, end of period 2,266,667 $19.28 Grant activity primarily consisted of restricted stock units to employees and independent contractors as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above and vest ratably over an approximate three -year period. As of December 31, 2018 , unrecognized compensation costs related to unvested restricted stock awards and units was $23.2 million and will be recognized over a weighted average period of 1.9 years. The aggregate fair value of restricted stock awards and units that vested during the years ended December 31, 2018 , 2017 and 2016 was $10.2 million , $20.3 million and $26.3 million , respectively. Cash SARs The table below summarizes the Cash SAR activity for the years ended December 31, 2018 , 2017 and 2016 : Stock Appreciation Rights Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Aggregate Intrinsic Value of Exercises (In millions) For the Year Ended December 31, 2016 Outstanding, beginning of period 700,453 $21.86 Granted 376,260 $27.30 Exercised (354,075 ) $23.89 $5.2 Forfeited — — Expired — — Outstanding, end of period 722,638 $23.69 Vested, end of period 350,840 $19.87 Vested and exercisable, end of period 350,840 $19.87 For the Year Ended December 31, 2017 Outstanding, beginning of period 722,638 $23.69 Granted 342,440 $26.94 Exercised (219,279 ) $17.28 $2.1 Forfeited — — Expired (131,561 ) $24.19 Outstanding, end of period 714,238 $27.12 Vested, end of period 185,899 $27.30 Vested and exercisable, end of period — $27.30 For the Year Ended December 31, 2018 Outstanding, beginning of period 714,238 $27.12 Granted 616,686 $14.67 Exercised — — $— Forfeited — — Expired — — Outstanding, end of period 1,330,924 $21.35 4.3 $— Vested, end of period 543,018 $27.18 Vested and exercisable, end of period — $27.18 2.5 $— Grant activity primarily consisted of Cash SARs to certain employees and independent contractors as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above. The Cash SARs granted during the year ended December 31, 2018 vest ratably over an approximate three year period and expire approximately seven years from the grant date. The Cash SARs granted during the years ended December 31, 2017 and 2016 vest ratably over an approximate two year period and expire approximately five years from the grant date. The grant date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model, was $4.9 million , $4.1 million , and $3.7 million for the years ended December 31, 2018, 2017, and 2016, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per Cash SAR granted during the years ended December 31, 2018 , 2017 , and 2016 : Years Ended December 31, 2018 2017 2016 Expected term (in years) 6.0 4.2 3.9 Expected volatility 54.3 % 54.3 % 45.1 % Risk-free interest rate 2.8 % 1.8 % 1.3 % Dividend yield — % — % — % Grant date fair value per Cash SAR $7.89 $12.00 $9.88 The liability for Cash SARs as of December 31, 2018 and 2017 was $1.8 million and $4.4 million , respectively, all of which was classified as “Other current liabilities” in the consolidated balance sheets in the respective period. Unrecognized compensation costs related to unvested Cash SARs were $2.4 million as of December 31, 2018 , and will be recognized over a weighted average period of 2.2 years. Performance Shares The table below summarizes performance share activity for the years ended December 31, 2018 , 2017 and 2016 : Target Performance Shares (1) Weighted Average Grant Date Fair Value For the Year Ended December 31, 2016 Unvested performance shares, beginning of period 112,859 $66.83 Granted 41,651 $35.71 Vested at end of performance period — — Forfeited — — Unvested performance shares, end of period 154,510 $58.44 For the Year Ended December 31, 2017 Unvested performance shares, beginning of period 154,510 $58.44 Granted 46,787 $35.14 Vested at end of performance period (56,342 ) $68.15 Forfeited — — Unvested performance shares, end of period 144,955 $47.14 For the Year Ended December 31, 2018 Unvested performance shares, beginning of period 144,955 $47.14 Granted 93,771 $19.09 Vested at end of performance period (49,458 ) $65.51 Did not vest at end of performance period (7,059 ) $65.51 Forfeited — — Unvested performance shares, end of period 182,209 $27.01 (1) The number of performance shares that vest may vary from the number of target performance shares granted depending on the Company ’ s final TSR ranking for the approximate three -year performance period. Grant activity primarily consisted of performance shares to certain employees and independent contractors as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above. For the year ended December 31, 2018, as a result of the Company’s final TSR ranking during the performance period, a multiplier of 88% was applied to the 56,517 target performance shares that were granted in 2015, resulting in the vesting of 49,458 shares and 7,059 shares that did not vest. For the year ended December 31, 2017, as a result of the Company’s final TSR ranking during the performance period, a multiplier of 164% was applied to the 56,342 target performance shares that were granted in 2014, resulting in the vesting of 92,200 shares. The Company did not have any performance shares that vested during the year ended December 31, 2016. The aggregate fair value of performance shares that vested during the years ended December 31, 2018 and 2017 was $0.8 million and $2.6 million , respectively. For the years ended December 31, 2018, 2017 and 2016, the grant date fair value of the performance shares, calculated using a Monte Carlo simulation, was $1.8 million , $1.6 million , and $1.5 million , respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance share granted during the years ended December 31, 2018 , 2017 and 2016 : Years Ended December 31, 2018 2017 2016 Number of simulations 500,000 500,000 500,000 Expected term (in years) 3.0 3.0 3.0 Expected volatility 61.5 % 59.2 % 55.3 % Risk-free interest rate 2.4 % 1.5 % 1.2 % Dividend yield — % — % — % Grant date fair value per performance share $19.09 $35.14 $35.71 As of December 31, 2018 , unrecognized compensation costs related to unvested performance shares were $2.1 million and will be recognized over a weighted average period of 1.8 years. Stock-Based Compensation Expense, Net The following table sets forth the components of stock-based compensation expense, net: Years Ended December 31, 2018 2017 2016 (In thousands) Restricted stock awards and units $18,434 $21,372 $28,196 Cash SARs (2,571 ) (5,023 ) 9,675 Performance shares 1,785 2,442 2,806 17,648 18,791 40,677 Less: amounts capitalized to oil and gas properties (4,124 ) (4,482 ) (4,591 ) Total stock-based compensation expense, net $13,524 $14,309 $36,086 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | 12. Derivative Instruments Commodity Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. Since the Company derives a significant portion of its revenues from sales of crude oil, crude oil price volatility represents the Company’s most significant commodity price risk. While the use of commodity derivative instruments limits or partially reduces the downside risk of adverse commodity price movements, such use also limits the upside from favorable commodity price movements. The Company does not enter into commodity derivative instruments for speculative purposes. The Company’s commodity derivative instruments, which settle on a monthly basis over the term of the contract for contracted volumes, consist of over-the-counter price swaps, three-way collars, sold call options and basis swaps, each of which is described below. Price swaps are settled based on differences between a fixed price and the settlement price of a referenced index. If the settlement price of the referenced index is below the fixed price, the Company receives the difference from the counterparty. If the referenced settlement price is above the fixed price, the Company pays the difference to the counterparty. Three-way collars consist of a purchased put option (floor price), a sold call option (ceiling price) and a sold put option (sub-floor price) and are settled based on differences between the floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and sub-floor price. If the settlement price of the referenced index is below the sub-floor price, the Company receives the difference between the floor price and sub-floor price from the counterparty. If the settlement price of the referenced index is between the floor price and sub-floor price, the Company receives the difference between the floor price and the settlement price of the referenced index from the counterparty. If the settlement price of the referenced index is between the floor price and ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty. Sold call options are settled based on differences between the ceiling price and the settlement price of a referenced index. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty. If the settlement price of the referenced index is below the ceiling price, no payments are due to or from either party. Premiums from the sale of call options have been used to enhance the fixed price of certain contemporaneously executed price swaps. Purchased call options executed contemporaneously with sold call options in order to increase the ceiling price of existing sold call options have been presented on a net basis in the table below. Basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. If the differential between the settlement prices of the two referenced indexes is greater than the fixed price differential, the Company receives the difference from the counterparty. If the differential between the settlement prices of the two referenced indexes is less than the fixed price differential, the Company pays the difference to the counterparty. The referenced index of the Company’s price swaps, three-way collars and sold call options is U.S. New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) for crude oil and NYMEX Henry Hub for natural gas, as applicable. The prices received by the Company for the sale of its production generally vary from these referenced index prices due to adjustments for delivery location (basis) and other factors. The referenced indexes of the Company’s basis swaps, which are used to mitigate location price risk for a portion of its production, are Argus WTI Cushing (“WTI Cushing”) and the applicable index price of the Company’s crude oil sales contracts is Argus WTI Midland (“WTI Midland”) for its Delaware Basin crude oil production and Argus Light Louisiana Sweet (“LLS”) for its Eagle Ford crude oil production. The Company has incurred premiums on certain of its commodity derivative instruments in order to obtain a higher floor price and/or higher ceiling price. Payment of these premiums are deferred until the applicable contracts settle on a monthly basis over the term of the contract or, in some cases, during the final 12 months of the contract and are referred to as deferred premium obligations. As of December 31, 2018 , the Company had the following outstanding commodity derivative instruments at weighted average contract volumes and prices: Commodity Period Type of Contract Index Volumes Sub-Floor Floor Price Ceiling Price Fixed Crude oil 1Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 1Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 1Q19 Basis Swaps WTI Midland-WTI Cushing 5,500 — — — ($5.24 ) Crude oil 1Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 2Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 2Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 2Q19 Basis Swaps WTI Midland-WTI Cushing 6,000 — — — ($5.38 ) Crude oil 2Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 3Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 3Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 3Q19 Basis Swaps WTI Midland-WTI Cushing 7,000 — — — ($5.56 ) Crude oil 3Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 4Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 4Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 4Q19 Basis Swaps WTI Midland-WTI Cushing 11,000 — — — ($3.84 ) Crude oil 4Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 2020 Basis Swaps WTI Midland-WTI Cushing 13,000 — — — ($1.27 ) Crude oil 2020 Sold Call Options NYMEX WTI 4,575 — — $75.98 — Crude oil 2021 Basis Swaps WTI Midland-WTI Cushing 6,000 — — — $0.03 Commodity Period Type of Contract Index Volumes (MMBtu per day) Sub-Floor Price ($ per MMBtu) Floor Price ($ per MMBtu) Ceiling Price ($ per MMBtu) Fixed Price Differential ($ per MMBtu) Natural gas 1Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 2Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 3Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 4Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 2020 Sold Call options NYMEX Henry Hub 33,000 — — $3.50 — The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods often resulting in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to ISDAs, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Counterparties to the Company’s commodity derivative instruments who are a Lender Counterparty allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the Lender Counterparty with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties to the Company’s commodity derivative instruments who are a Non-Lender Counterparty can require commodity derivative instruments to be novated to a Lender Counterparty if the Company’s net liability position exceeds the Company’s unsecured credit limit with the Non-Lender Counterparty and therefore do not require the posting of cash collateral. Because each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with seventeen counterparties to minimize its credit exposure to any individual counterparty. Contingent Consideration Arrangements The purchase and sale agreements of the ExL Acquisition and divestitures of the Company’s assets in the Niobrara, Marcellus and Utica, included contingent consideration arrangements that require the Company to pay or entitle the Company to receive specified amounts if commodity prices exceed specified thresholds, which are summarized in the table below. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further discussion. Contingent Consideration Arrangements Years Threshold (1) Contingent Receipt (Payment) - Annual Contingent Receipt (Payment) - Aggregate Limit (In thousands) Contingent ExL Consideration 2018 $50.00 ($50,000 ) 2019 50.00 (50,000 ) 2020 50.00 (50,000 ) 2021 50.00 (50,000 ) ($125,000 ) Contingent Niobrara Consideration 2018 $55.00 $5,000 2019 55.00 5,000 2020 60.00 5,000 — Contingent Marcellus Consideration 2018 $3.13 $3,000 2019 3.18 3,000 2020 3.30 3,000 $7,500 Contingent Utica Consideration 2018 $50.00 $5,000 2019 53.00 5,000 2020 56.00 5,000 — (1) The price used to determine whether the specified threshold for each year has been met for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration. The price used to determine whether the specified threshold for each year has been met for the Contingent Marcellus Consideration is the average monthly settlement price per MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc. Derivative Assets and Liabilities The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of December 31, 2018 and December 31, 2017 are summarized below: December 31, 2018 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $50,406 ($20,502 ) $29,904 Contingent Niobrara Consideration 5,000 — 5,000 Contingent Utica Consideration 5,000 — 5,000 Derivative assets $60,406 ($20,502 ) $39,904 Commodity derivative instruments 6,083 (4,236 ) 1,847 Contingent Niobrara Consideration 2,035 — 2,035 Contingent Marcellus Consideration 1,369 — 1,369 Contingent Utica Consideration 2,501 — 2,501 Other long-term assets $11,988 ($4,236 ) $7,752 Commodity derivative instruments ($15,345 ) $10,140 ($5,205 ) Deferred premium obligations (10,362 ) 10,362 — Contingent ExL Consideration (50,000 ) — (50,000 ) Derivative liabilities-current ($75,707 ) $20,502 ($55,205 ) Commodity derivative instruments (10,751 ) 518 (10,233 ) Deferred premium obligations (3,718 ) 3,718 — Contingent ExL Consideration (30,584 ) — (30,584 ) Derivative liabilities-non current ($45,053 ) $4,236 ($40,817 ) December 31, 2017 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $4,869 ($4,869 ) $— Derivative assets $4,869 ($4,869 ) $— Commodity derivative instruments 9,505 (9,505 ) — Contingent Marcellus Consideration 2,205 — 2,205 Contingent Utica Consideration 7,985 — 7,985 Other long-term assets $19,695 ($9,505 ) $10,190 Commodity derivative instruments ($52,671 ) ($4,450 ) ($57,121 ) Deferred premium obligations (9,319 ) 9,319 — Derivative liabilities-current ($61,990 ) $4,869 ($57,121 ) Commodity derivative instruments (24,609 ) (2,098 ) (26,707 ) Deferred premium obligations (11,603 ) 11,603 — Contingent ExL Consideration (85,625 ) — (85,625 ) Derivative liabilities-non current ($121,837 ) $9,505 ($112,332 ) See “Note 13. Fair Value Measurements” for additional information regarding the fair value of the Company’s derivative instruments. (Gain) Loss on Derivatives, Net The components of “(Gain) loss on derivatives, net” in the consolidated statements of operations for the years ended December 31, 2018 , 2017 , and 2016 are summarized below: Years Ended December 31, 2018 2017 2016 (In thousands) (Gain) Loss on Derivatives, Net Crude oil ($9,726 ) $22,839 $23,609 NGL 4,439 1,322 — Natural gas (421 ) (15,399 ) 19,584 Deferred premium obligations 1,875 18,401 5,880 Contingent ExL Consideration (5,041 ) 33,325 — Contingent Niobrara Consideration 845 — — Contingent Marcellus Consideration 836 455 — Contingent Utica Consideration 484 (1,840 ) — (Gain) Loss on Derivatives, Net ($6,709 ) $59,103 $49,073 Cash Received (Paid) for Derivative Settlements, Net For the years ended December 31, 2018 , 2017 , and 2016 , there were no settlements of contingent consideration arrangements, however, the specified pricing thresholds related to the Contingent ExL Consideration, the Contingent Niobrara Consideration, and the Contingent Utica Consideration were exceeded for the year ended December 31, 2018. See “Note 16. Subsequent Events” for further discussion. The components of “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows for the years ended December 31, 2018 , 2017 , and 2016 are summarized below: Years Ended December 31, 2018 2017 2016 Cash Flows from Operating Activities (In thousands) Cash Received (Paid) for Derivative Settlements, Net Crude oil ($78,570 ) $9,883 $125,098 NGL (6,378 ) — — Natural gas (1,710 ) (54 ) — Deferred premium obligations (9,649 ) (2,056 ) (5,729 ) Cash Received (Paid) for Derivative Settlements, Net ($96,307 ) $7,773 $119,369 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 13. Fair Value Measurements Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2 – Other inputs that are observable directly or indirectly such as 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. Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables summarize the Company’s derivative instrument assets and liabilities measured at fair value on a recurring basis as of December 31, 2018 and 2017 : December 31, 2018 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $31,751 $— Contingent Niobrara Consideration — 7,035 — Contingent Marcellus Consideration — 1,369 — Contingent Utica Consideration — 7,501 — Liabilities Commodity derivative instruments $— ($15,438 ) $— Contingent ExL Consideration — (80,584 ) — December 31, 2017 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $— $— Contingent Niobrara Consideration — — — Contingent Marcellus Consideration — — 2,205 Contingent Utica Consideration — — 7,985 Liabilities Commodity derivative instruments $— ($83,828 ) $— Contingent ExL Consideration — — (85,625 ) The asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. Commodity derivative instruments. The fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model which uses contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments including forward oil and gas price curves, discount rates and volatility factors, and are therefore designated as Level 2 within the valuation hierarchy. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for commodity derivative assets and the Company’s credit quality for commodity derivative liabilities. Contingent consideration arrangements. The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors, and risk adjusted discount rates, which include adjustments for the counterparties’ credit quality for contingent consideration assets and the Company’s credit quality for the contingent consideration liabilities. These inputs are substantially observable in active markets throughout the full term of the contingent consideration arrangements or can be derived from observable data and are therefore designated as Level 2 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods. The following tables present the reconciliation of changes in the fair values of the contingent consideration arrangements, which were designated within the valuation hierarchy as Level 2 for the year ended December 31, 2018 and Level 3 for the year ended December 31, 2017 : Contingent Consideration Arrangements Assets Liability (In thousands) Balance as of January 1, 2017 $— $— Recognition of (acquisition) divestiture date fair value 8,805 (52,300 ) Gain (loss) on change in fair value, net (1) 1,385 (33,325 ) Transfers into (out of) Level 3 — — Balance as of December 31, 2017 $10,190 ($85,625 ) Recognition of divestiture date fair value 7,880 — Gain (loss) on changes in fair value, net (1) (2,165 ) 5,041 Transfers out of Level 3 (15,905 ) 80,584 Balance as of December 31, 2018 $— $— (1) Recognized as “(Gain) loss on derivatives, net” in the consolidated statements of operations. During 2018, the Company determined that the contingent consideration arrangements met the requirements to be designated as Level 2 in the valuation hierarchy due to the increased observability of the forward oil and gas price curves used in determining the fair value throughout the full term of the contingent consideration arrangements resulting in the transfer out of Level 3. See “Note 12. Derivative Instruments” for additional information regarding the contingent consideration arrangements. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured as of the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include forward oil and gas price curves, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs, and a risk adjusted discount rate. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for additional discussion. The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 7. Asset Retirement Obligations” for additional discussion. The fair value measurements of the Preferred Stock are measured as of the issuance date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company. See “Note 9. Preferred Stock and Common Stock Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants. Fair Value of Other Financial Instruments The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the principal amounts of the Company’s senior notes and other long-term debt with the fair values measured using quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy. See “Note 6. Long-Term Debt” for additional discussion. December 31, 2018 December 31, 2017 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 7.50% Senior Notes due 2020 $— $— $450,000 $459,518 6.25% Senior Notes due 2023 650,000 599,625 650,000 674,375 8.25% Senior Notes due 2025 250,000 244,375 250,000 274,375 Other long-term debt due 2028 — — 4,425 4,445 |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | 12 Months Ended |
Dec. 31, 2018 | |
Condensed Consolidating Financial Information [Abstract] | |
Condensed Consolidating Financial Information | 14. Condensed Consolidating Financial Information The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities. CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,341,680 $114,005 $— ($3,305,316 ) $150,369 Total property and equipment, net 7,951 3,011,387 3,028 (3,842 ) 3,018,524 Investment in subsidiaries (419,159 ) — — 419,159 — Other long-term assets 28,124 5,906 — (17,823 ) 16,207 Total Assets $2,958,596 $3,131,298 $3,028 ($2,907,822 ) $3,185,100 Liabilities and Shareholders’ Equity Current liabilities $135,980 $3,491,337 $3,028 ($3,308,336 ) $322,009 Long-term liabilities 1,650,589 59,120 — (1,944 ) 1,707,765 Preferred stock 174,422 — — — 174,422 Total shareholders’ equity 997,605 (419,159 ) — 402,458 980,904 Total Liabilities and Shareholders’ Equity $2,958,596 $3,131,298 $3,028 ($2,907,822 ) $3,185,100 December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,441,633 $105,533 $— ($3,424,288 ) $122,878 Total property and equipment, net 5,953 2,630,707 3,028 (3,878 ) 2,635,810 Investment in subsidiaries (999,793 ) — — 999,793 — Other long-term assets 9,270 10,346 — — 19,616 Total Assets $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 Liabilities and Shareholders’ Equity Current liabilities $165,701 $3,631,401 $3,028 ($3,427,308 ) $372,822 Long-term liabilities 1,689,466 114,978 — 15,879 1,820,323 Preferred stock 214,262 — — — 214,262 Total shareholders’ equity 387,634 (999,793 ) — 983,056 370,897 Total Liabilities and Shareholders’ Equity $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $162 $1,065,780 $— $— $1,065,942 Total costs and expenses 176,406 479,973 — (37 ) 656,342 Income (loss) before income taxes (176,244 ) 585,807 — 37 409,600 Income tax expense — (5,173 ) — — (5,173 ) Equity in income of subsidiaries 580,634 — — (580,634 ) — Net income $404,390 $580,634 $— ($580,597 ) $404,427 Dividends on preferred stock (18,161 ) — — — (18,161 ) Accretion on preferred stock (3,057 ) — — — (3,057 ) Loss on redemption of preferred stock (7,133 ) — — — (7,133 ) Net income attributable to common shareholders $376,039 $580,634 $— ($580,597 ) $376,076 Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $302 $745,586 $— $— $745,888 Total costs and expenses 195,728 459,057 — (37 ) 654,748 Income (loss) before income taxes (195,426 ) 286,529 — 37 91,140 Income tax expense — (4,030 ) — — (4,030 ) Equity in income of subsidiaries 282,499 — — (282,499 ) — Net income $87,073 $282,499 $— ($282,462 ) $87,110 Dividends on preferred stock (7,781 ) — — — (7,781 ) Accretion on preferred stock (862 ) — — — (862 ) Loss on redemption of preferred stock — — — — — Net income attributable to common shareholders $78,430 $282,499 $— ($282,462 ) $78,467 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $482 $443,112 $— $— $443,594 Total costs and expenses 208,054 910,522 — 492 1,119,068 Loss before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax expense — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Loss on redemption of preferred stock — — — — — Net loss attributable to common shareholders ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($269,318 ) $922,873 $— $— $653,555 Net cash provided by (used in) investing activities 126,905 (792,383 ) — (130,490 ) (795,968 ) Net cash provided by (used in) financing activities 135,155 (130,490 ) — 130,490 135,155 Net decrease in cash and cash equivalents (7,258 ) — — — (7,258 ) Cash and cash equivalents, beginning of year 9,540 — — — 9,540 Cash and cash equivalents, end of year $2,282 $— $— $— $2,282 Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($121,107 ) $544,088 $— $— $422,981 Net cash used in investing activities (615,364 ) (1,155,340 ) — 611,252 (1,159,452 ) Net cash provided by financing activities 741,817 611,252 — (611,252 ) 741,817 Net increase in cash and cash equivalents 5,346 — — — 5,346 Cash and cash equivalents, beginning of year 4,194 — — — 4,194 Cash and cash equivalents, end of year $9,540 $— $— $— $9,540 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities 308,340 268,283 740 (269,023 ) 308,340 Net decrease in cash and cash equivalents (38,724 ) — — — (38,724 ) Cash and cash equivalents, beginning of year 42,918 — — — 42,918 Cash and cash equivalents, end of year $4,194 $— $— $— $4,194 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Disclosures | 15. Supplemental Cash Flow Information Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Years Ended December 31, 2018 2017 2016 (In thousands) Operating activities: Cash paid for interest, net of amounts capitalized $59,846 $77,213 $75,231 Cash paid for income taxes — — — Investing activities: Increase (decrease) in capital expenditure payables and accruals ($53,722 ) $102,272 ($21,492 ) Supplemental non-cash investing activities: Fair value of contingent consideration assets on date of divestiture (7,880 ) (8,805 ) — Fair value of contingent consideration liabilities on date of acquisition — 52,300 — Liabilities assumed in connection with the Sanchez Acquisition — — 4,880 Stock-based compensation expense capitalized to oil and gas properties 4,124 4,482 4,591 Asset retirement obligations capitalized to oil and gas properties 2,132 3,726 1,927 Supplemental non-cash financing activities: Non-cash loss on extinguishment of debt, net 3,586 1,357 — |
Subsequent Events (Unaudited)
Subsequent Events (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | 16. Subsequent Events (Unaudited) Hedging Subsequent to December 31, 2018 , the Company entered into the following commodity derivative instruments at weighted average contract volumes and prices: Commodity Period Type of Contract Index Volumes Fixed Price Sub-Floor Floor Price Ceiling Price Crude oil 2020 Price Swaps NYMEX WTI 3,000 $55.06 — — — Crude oil 2020 Three-Way Collars NYMEX WTI 6,000 — $45.00 $55.00 $64.69 Contingent Consideration Arrangements For the year ended December 31, 2018, the specified pricing thresholds related to the Contingent ExL Consideration, the Contingent Niobrara Consideration, and the Contingent Utica Consideration were exceeded. As a result, in January 2019, we paid $50.0 million and received $10.0 million from settlement of these contingent consideration arrangements. |
Supplemental Disclosures About
Supplemental Disclosures About Oil And Gas Producing Activities | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental Disclosures About Oil And Gas Producing Activities | 17. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited) Costs Incurred Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Years Ended December 31, 2018 2017 2016 (In thousands) Property acquisition costs Proved properties $47,370 $303,307 $90,661 Unproved properties 182,220 525,061 113,535 Total property acquisition costs 229,590 828,368 204,196 Exploration costs 48,570 91,098 37,508 Development costs 809,637 569,982 374,134 Total costs incurred $1,087,797 $1,489,448 $615,838 Costs incurred exclude capitalized interest on unproved properties of $36.6 million , $28.3 million , and $17.0 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Included in exploration and development costs are non-cash additions related to the estimated future asset retirement obligations of the Company’s oil and gas properties of $1.9 million , $3.5 million and $1.9 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Non-cash additions related to the estimated future asset retirement obligations associated with the Devon Acquisition of $0.2 million , the ExL Acquisition of $0.1 million , and the Sanchez Acquisition of $2.0 million are included in acquisition costs of proved properties for the years ended December 31, 2018, 2017 and 2016, respectively. The internal cost of employee compensation and benefits, including stock-based compensation, capitalized to proved or unproved oil and gas properties of $17.0 million , $14.8 million and $10.5 million for the years ended December 31, 2018 , 2017 and 2016 , respectively, are included in exploration, development and unproved property acquisition costs. Proved Oil and Gas Reserve Quantities Proved oil and gas reserves are generally those quantities of crude oil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserve quantities at December 31, 2018 , 2017 , and 2016 and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company, L.P. Such estimates have been prepared in accordance with guidelines established by the SEC. All of the Company’s proved reserves are attributable to properties within the United States. The Company’s proved reserves and changes in proved reserves are as follows: Crude Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total Proved Reserves (MBoe) Proved reserves: January 1, 2016 109,588 20,221 244,938 170,632 Extensions and discoveries 40,074 8,612 59,318 58,572 Revisions of previous estimates (16,731 ) (3,230 ) 1,481 (19,713 ) Purchases of reserves in place 4,810 122 7,282 6,145 Production (9,423 ) (1,788 ) (25,574 ) (15,473 ) December 31, 2016 128,318 23,937 287,445 200,163 Extensions and discoveries 50,476 13,781 98,980 80,754 Revisions of previous estimates (19,838 ) (909 ) 27,774 (16,118 ) Purchases of reserves in place 21,634 8,642 94,962 46,103 Sales of reserves in place (650 ) (526 ) (170,219 ) (29,546 ) Production (12,566 ) (2,327 ) (28,472 ) (19,639 ) December 31, 2017 167,374 42,598 310,470 261,717 Extensions and discoveries 65,352 30,195 212,758 131,007 Revisions of previous estimates (31,287 ) 1,936 (6,006 ) (30,352 ) Purchases of reserves in place 2,205 967 7,953 4,498 Sales of reserves in place (9,676 ) (2,872 ) (17,475 ) (15,461 ) Production (14,232 ) (3,701 ) (24,639 ) (22,040 ) December 31, 2018 179,736 69,123 483,061 329,369 Proved developed reserves: December 31, 2015 42,311 7,933 154,725 76,032 December 31, 2016 51,062 9,387 187,054 91,625 December 31, 2017 69,632 17,447 131,355 108,972 December 31, 2018 75,267 25,809 178,941 130,899 Proved undeveloped reserves: December 31, 2015 67,277 12,288 90,213 94,600 December 31, 2016 77,256 14,550 100,391 108,538 December 31, 2017 97,742 25,151 179,115 152,745 December 31, 2018 104,469 43,314 304,120 198,470 Extensions and discoveries For the year ended December 31, 2018, the Company added 12,687 MBoe of proved developed reserves and 118,320 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 30% and 70% , respectively, of the total extensions and discoveries. For the year ended December 31, 2017, the Company added 6,473 MBoe of proved developed reserves and 74,281 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 51% and 48% , respectively, of the total extensions and discoveries. For the year ended December 31, 2016, the Company added 6,525 MBoe of proved developed reserves and 52,047 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20% , respectively, of the total extensions and discoveries. Revisions of previous estimates For the year ended December 31, 2018, revisions of previous estimates reduced the Company’s proved reserves by 30,352 MBoe. Included in revisions of previous estimates were: • Positive revisions due to price of 3,764 MBoe. • Net negative revisions of 12,363 MBoe primarily due to negative revisions of 14,907 MBoe in the Eagle Ford, partially offset by positive revisions of 2,544 MBoe in the Delaware Basin. The negative revisions in the Eagle Ford were primarily a result of completion of new wells that negatively impacted the production of adjacent existing producing wells and the associated impact to certain PUD locations, as well as a reduction in spacing and the average lateral length for certain PUD locations. • Negative revisions of 21,753 MBoe, primarily in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The primary drivers of the changes in our previously approved development plan are the reallocation of capital to areas providing the greatest opportunities to increase capital efficiency and maximize project-level economics within our reduced capital expenditure plan, which includes a shift to larger-scale development projects. For the year ended December 31, 2017, revisions of previous estimates reduced the Company’s proved reserves by 16,118 MBoe. Included in revisions of previous estimates were: • Positive revisions due to price of 2,684 MBoe. • Negative revisions of 4,500 MBoe primarily in the Eagle Ford due to a downward shift of the type curve for certain PUD locations partially offset by positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017. • Negative revisions in proved undeveloped reserves of 14,302 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads. For the year ended December 31, 2016, revisions of previous estimates reduced the Company’s proved reserves by 19,713 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 6,705 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 3,228 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 3,477 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations due to loss of tail reserves; • Negative revisions of 6,083 MBoe primarily in Eagle Ford as the EURs for certain PUD locations were reduced as a result of tighter spacing and shorter lateral lengths partially offset by positive revisions in Marcellus; • Negative revisions in proved undeveloped reserves of 6,925 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the move to a more efficient development plan which includes drilling and completing larger pads and the recent Sanchez Acquisition. Purchases of reserves in place For the year ended December 31, 2018, purchases of reserves in place included 4,498 MBoe of proved developed reserves associated with the Devon Acquisition. For the year ended December 31, 2017, purchases of reserves in place included 26,009 MBoe of proved developed reserves and 20,094 MBoe of proved undeveloped reserves associated with the ExL Acquisition. For the year ended December 31, 2016, purchases of reserves in place included 4,978 MBoe of proved developed reserves and 1,167 MBoe of proved undeveloped reserves associated with the Sanchez Acquisition. Sales of reserves in place For the year ended December 31, 2018, sales of reserves in place included 13,465 MBoe of proved developed reserves and 1,996 MBoe of proved undeveloped reserves associated with the Eagle Ford and Niobrara Formation divestitures. For the year ended December 31, 2017, sales of reserves in place included 22,249 MBoe of proved developed reserves and 7,297 MBoe of proved undeveloped reserves associated with the Marcellus Shale and Utica Shale divestitures. There were no sales of reserves in place for the year ended December 31, 2016. Standardized Measure The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2018 2017 2016 (In thousands) Future cash inflows $14,461,143 $10,109,752 $5,903,629 Future production costs (4,572,397 ) (3,202,201 ) (2,241,928 ) Future development costs (1,964,450 ) (1,699,909 ) (1,264,493 ) Future income taxes (1) (1,005,837 ) (445,056 ) — Future net cash flows 6,918,459 4,762,586 2,397,208 Less 10% annual discount to reflect timing of cash flows (3,282,901 ) (2,297,544 ) (1,093,779 ) Standardized measure of discounted future net cash flows $3,635,558 $2,465,042 $1,303,429 (1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016. Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2018 2017 2016 Crude oil ($/Bbl) $63.80 $49.87 $39.60 NGLs ($/Bbl) $26.15 $19.78 $11.66 Natural gas ($/Mcf) $2.46 $2.96 $1.89 Future operating and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. Future income taxes, which include the effects of the Tax Cuts and Jobs Act for the years ended December 31, 2018 and 2017, are based on current statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve estimates. Changes in Standardized Measure Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below: Years Ended December 31, 2018 2017 2016 (In thousands) Standardized measure at beginning of year $2,465,042 $1,303,429 $1,365,224 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production $809,182 $710,773 ($346,763 ) Net change in estimated future development costs (9,627 ) (51,854 ) 74,407 Net change due to revisions in quantity estimates (250,817 ) (42,214 ) (150,245 ) Accretion of discount 263,837 130,343 136,522 Changes in production rates (timing) and other (19,539 ) (116,056 ) (111,137 ) Total revisions to reserves proved in prior years 793,036 630,992 (397,216 ) Net change due to extensions and discoveries, net of estimated future development and production costs 1,127,748 597,502 313,201 Net change due to purchases of reserves in place 60,264 452,932 43,426 Net change due to divestitures of reserves in place (181,308 ) (106,608 ) — Sales of crude oil, NGLs and natural gas produced, net of production costs (843,333 ) (566,258 ) (320,272 ) Previously estimated development costs incurred 496,600 326,383 299,066 Net change in income taxes (282,491 ) (173,330 ) — Net change in standardized measure of discounted future net cash flows 1,170,516 1,161,613 (61,795 ) Standardized measure at end of year $3,635,558 $2,465,042 $1,303,429 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data | 18. Quarterly Financial Data (Unaudited) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2018 and 2017 : Year Ended December 31, 2018 First Quarter (3) Second Quarter (4) Third Quarter Fourth Quarter (5) (In thousands, except per share amounts) Total revenues $225,280 $263,973 $303,375 $273,314 Operating profit (1) $108,992 $140,265 $165,141 $129,405 Net income $27,492 $35,309 $81,346 $260,280 Net income attributable to common shareholders $14,743 $30,095 $76,118 $255,120 Net income attributable to common shareholders per common share (2) Basic $0.18 $0.37 $0.88 $2.79 Diluted $0.18 $0.36 $0.85 $2.75 Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter (6) Fourth Quarter (7) (In thousands, except per share amounts) Total revenues $151,355 $166,483 $181,279 $246,771 Operating profit (1) $57,953 $63,147 $69,364 $113,205 Net income (loss) $40,021 $56,306 $7,823 ($17,040 ) Net income (loss) attributable to common shareholders $40,021 $56,306 $5,574 ($23,434 ) Net income (loss) attributable to common shareholders per common share (2) Basic $0.61 $0.86 $0.07 ($0.29 ) Diluted $0.61 $0.85 $0.07 ($0.29 ) (1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A. (2) The sum of quarterly net income (loss) attributable to common shareholders per common share does not agree with the total year net income (loss) attributable to common shareholders per common share as each computation is based on the weighted average of common shares outstanding during the period. (3) First quarter of 2018 included the following: a. $29.6 million loss on derivatives, net b. $8.7 million loss on extinguishment of debt as a result of the redemption of $320.0 million aggregate principal amount of 7.50% Senior Notes. b. $7.1 million loss on redemption of preferred stock as a result of the redemption of 50,000 shares of Preferred Stock. (4) Second quarter of 2018 included the following: a. $67.7 million loss on derivatives, net (5) Fourth quarter of 2018 included the following: a. $159.4 million gain on derivatives, net (6) Third quarter of 2017 included the following: a. $24.4 million loss on derivatives, net (7) Fourth quarter of 2017 included the following: a. $86.1 million loss on derivatives, net. b. $4.2 million loss on extinguishment of debt as a result of the redemption of $150.0 million aggregate principal amount of 7.50% Senior Notes. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Subsequent Events, Policy [Policy Text Block] | Subsequent Events The Company evaluates subsequent events through the date the financial statements are issued. See “Note 16. Subsequent Events” for further discussion. |
Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. |
Reclassifications | Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, fair value of preferred stock upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $70.4 million and $62.6 million as of December 31, 2018 and 2017 , respectively. |
Accounts Receivable | Accounts Receivable The Company’s accounts receivable consist primarily of receivables from crude oil, NGL, and natural gas purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s receivables from the sale of crude oil are collected within one month and receivables from the sale of NGL and natural gas are collected within two months. The Company establishes an allowance for doubtful accounts when it determines it is probable that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. The Company’s allowance for doubtful accounts and bad debt expense was immaterial for all periods presented. |
Concentration of Credit Risk | Concentration of Credit Risk and Major Customers The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: Years Ended December 31, 2018 2017 2016 Shell Trading (US) Company 73% 69% 56% Flint Hills Resources, LP * * 15% * - Less than 10% for the respective year. The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with seventeen counterparties to minimize its credit exposure to any individual counterparty. |
Major Customers | The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: Years Ended December 31, 2018 2017 2016 Shell Trading (US) Company 73% 69% 56% Flint Hills Resources, LP * * 15% |
Oil and Gas Properties | Oil and Gas Properties Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred. Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds are assessed on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs along with associated capitalized interest are reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10% , (b) the costs of unproved properties not being amortized, and (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2018 , 2017 and 2016 , the Company did not have any sales of oil and gas properties that significantly altered such relationship. Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years. |
Debt Issuance Costs | Debt Issuance Costs Debt issuance costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related senior notes. |
Financial Instruments | Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration arrangements determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration arrangements are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 13. Fair Value Measurements” for additional discussion. |
Asset Retirement Obligations | Asset Retirement Obligations The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or economic lives of the oil and gas wells, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations” for additional discussion. |
Commitments and Contingencies | Commitments and Contingencies Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies” for additional discussion. |
Revenue Recognition | Revenue Recognition The Company’s revenues are comprised solely of revenues from customers and include the sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of December 31, 2018 and December 31, 2017 , receivables from contracts with customers were $77.1 million and $85.6 million , respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of operations. Crude oil sales. Crude oil production is primarily sold at the wellhead at an agreed upon index price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the wellhead, net of transportation costs incurred by the purchaser. Natural gas and NGL sales. Natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. The Company evaluates whether it is the principal or agent in the transaction and has concluded it is the principal and the purchasers of the NGLs and residue gas are the customers. Revenue is recognized on a gross basis, with gathering, processing and transportation fees recognized as lease operating expense in the consolidated statements of operations as the Company maintains control throughout processing. Transaction Price Allocated to Remaining Performance Obligations . The Company applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. |
Derivative Instruments | Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative purposes. The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets. The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of operations in the period in which the changes occur. Deferred premium obligations associated with the Company’s commodity derivative instruments are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of operations in the period in which the deferred premium obligations are incurred. Cash flows are impacted to the extent that settlements of commodity derivative instruments, including deferred premium obligations, and contingent consideration arrangements result in cash received or paid during the period and are recognized as “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows. Cash received or paid in settlement of contingent consideration assets or liabilities, respectively, are classified as cash flows from financing activities up to the divestiture or acquisition date fair value with any excess classified as cash flows from operating activities. The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 12. Derivative Instruments” for additional discussion. |
Preferred Stock | Preferred Stock and Common Stock Warrants The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets. When preferred stock is issued with common stock warrants, the common stock warrants are evaluated separately to determine if they are a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the common stock warrants for equity classification and has determined they qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and common stock warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The common stock warrants do not require further adjustments from their relative fair value at the issuance date. Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows. See “Note 9. Preferred Stock and Common Stock Warrants” for further details of the Company’s outstanding preferred stock and common stock warrants. |
Warrants | When preferred stock is issued with common stock warrants, the common stock warrants are evaluated separately to determine if they are a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the common stock warrants for equity classification and has determined they qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and common stock warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The common stock warrants do not require further adjustments from their relative fair value at the issuance date. Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows. See “Note 9. Preferred Stock and Common Stock Warrants” for further details of the Company’s outstanding preferred stock and common stock warrants. |
Stock-Based Compensation | Stock-Based Compensation The Company recognized stock-based compensation expense, net of amounts capitalized to oil and gas properties associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“Cash SARs”), and performance share awards, which is recognized as “General and administrative expense, net” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 11. Stock-Based Compensation” for further details of the awards discussed below. Restricted Stock Awards and Units . Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on the fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. Stock Appreciation Rights. For Cash SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the straight-line method, except for Cash SARs with performance conditions, in which case the Company uses the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the Cash SAR. The liability for Cash SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months, with the remainder classified as “Other long-term liabilities” in the consolidated balance sheets. Cash SARs typically expire between five and seven years after the date of grant. If Cash SARs expire unexercised, the cumulative compensation costs associated with such Cash SARs will be zero . Performance Shares. For performance shares, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. Each performance share represents the right to receive one share of common stock, however, the number of performance shares that vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three year performance period, the last day of which is also the vesting date. Compensation costs related to the performance shares will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved. |
Income Taxes | Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized. |
Earnings Per Share | Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance shares, and common stock warrants. The Company includes the number of restricted stock awards and units and common stock warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance shares in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. The Company has excluded any impact of the preferred stock to the calculation of diluted weighted average common shares outstanding as it has the positive intent and ability to redeem the preferred stock in cash. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. The following table summarizes the calculation of net income (loss) attributable to common shareholders per common share: Years Ended December 31, 2018 2017 2016 (In thousands, except per share amounts) Net Income (Loss) $404,427 $87,110 ($675,474 ) Dividends on preferred stock (18,161 ) (7,781 ) — Accretion on preferred stock (3,057 ) (862 ) — Loss on redemption of preferred stock (7,133 ) — — Net Income (Loss) Attributable to Common Shareholders $376,076 $78,467 ($675,474 ) Basic weighted average common shares outstanding 85,509 73,421 59,932 Dilutive effect of restricted stock and performance shares 949 269 — Dilutive effect of common stock warrants 685 303 — Diluted weighted average common shares outstanding 87,143 73,993 59,932 Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $4.40 $1.07 ($11.27 ) Diluted $4.32 $1.06 ($11.27 ) The computation of diluted net income attributable to common shareholders per common share excluded certain restricted stock and performance shares as the impacts were anti-dilutive. The following table presents the weighted average anti-dilutive securities for the periods presented: Years Ended December 31, 2018 2017 2016 (In thousands) Anti-dilutive restricted stock and performance shares 19 52 669 |
Recently Adopted Accounting Pronouncements | Recently Adopted Accounting Standards Revenue From Contracts with Customers . Effective January 1, 2018, the Company adopted ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASC 606”) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information for the years ended December 31, 2017 and 2016 has not been recast and continues to be reported under the accounting standards in effect for that period. Additionally, adoption of ASC 606 did not impact net income attributable to common shareholders. The tables below summarize the impact of adoption for the year ended December 31, 2018 : Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase % Increase (In thousands) Revenues Crude oil $911,554 $910,975 $579 0.1 % Natural gas liquids 96,585 91,608 4,977 5.4 % Natural gas 57,803 55,023 2,780 5.1 % Total revenues 1,065,942 1,057,606 8,336 0.8 % Costs and Expenses Lease operating 161,596 153,260 8,336 5.4 % Income Before Income Taxes $409,600 $409,600 $— — % Changes to crude oil, NGL, and natural gas revenues and lease operating expense are due to the conclusion that the Company controls the product throughout processing before transferring to the customer for certain natural gas processing arrangements. Therefore, any transportation, gathering, and processing fees incurred prior to transfer of control are included in lease operating expense. Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or divestitures) of assets or businesses. Effective January 1, 2018, the Company adopted ASU 2017-01 using the prospective method and applied the clarified definition of a business to subsequent acquisitions and divestitures. Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. Effective January 1, 2018, the Company adopted ASU 2016-15 using the retrospective approach as prescribed by ASU 2016-15. There were no changes to the statement of cash flows as a result of adoption. Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption. Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero . Effective January 1, 2017, all windfall tax benefits and tax shortfalls are recorded as income tax expense or benefit in the consolidated statements of operations, whereas prior to adoption, windfall tax benefits were recorded as an increase to additional paid-in capital. In addition, windfall tax benefits, along with tax shortfalls, are now required to be classified as an operating cash flow as opposed to a financing cash flow. Further, the Company has elected to account for forfeitures of share-based payment awards as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings. |
Recently Issued Accounting Pronouncements | Recently Issued Accounting Pronouncements Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use (“ROU”) asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. The Company will adopt ASU 2016-02 effective January 1, 2019, using the modified retrospective approach. The Company will make certain elections allowing it to not reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements, not to recognize ROU assets or lease liabilities for short-term leases, and will not separate lease components from non-lease components for specified asset classes. The Company has implemented a third party software which will be used to track and account for lease activity. As of December 31, 2018, the Company anticipates that the adoption of ASU 2016-02 will result in the recognition of ROU assets and lease liabilities on its consolidated balance sheets ranging from $75.0 million to $100.0 million primarily associated with office space contracts, drilling rig contracts, and contracts for the use of vehicles, information technology infrastructure and well equipment. However, the Company does not expect ASU 2016-02 to have a significant impact on its consolidated statements of operations or consolidated statements of cash flows. The Company is finalizing its accounting policies, controls, processes, and disclosures that will change as a result of adopting the new standard. As permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of Revenue by Major Customers by Reporting Segments | The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: Years Ended December 31, 2018 2017 2016 Shell Trading (US) Company 73% 69% 56% Flint Hills Resources, LP * * 15% |
Schedule of Earnings Per Share, Basic and Diluted | The following table summarizes the calculation of net income (loss) attributable to common shareholders per common share: Years Ended December 31, 2018 2017 2016 (In thousands, except per share amounts) Net Income (Loss) $404,427 $87,110 ($675,474 ) Dividends on preferred stock (18,161 ) (7,781 ) — Accretion on preferred stock (3,057 ) (862 ) — Loss on redemption of preferred stock (7,133 ) — — Net Income (Loss) Attributable to Common Shareholders $376,076 $78,467 ($675,474 ) Basic weighted average common shares outstanding 85,509 73,421 59,932 Dilutive effect of restricted stock and performance shares 949 269 — Dilutive effect of common stock warrants 685 303 — Diluted weighted average common shares outstanding 87,143 73,993 59,932 Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $4.40 $1.07 ($11.27 ) Diluted $4.32 $1.06 ($11.27 ) |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | The following table presents the weighted average anti-dilutive securities for the periods presented: Years Ended December 31, 2018 2017 2016 (In thousands) Anti-dilutive restricted stock and performance shares 19 52 669 |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles | The tables below summarize the impact of adoption for the year ended December 31, 2018 : Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase % Increase (In thousands) Revenues Crude oil $911,554 $910,975 $579 0.1 % Natural gas liquids 96,585 91,608 4,977 5.4 % Natural gas 57,803 55,023 2,780 5.1 % Total revenues 1,065,942 1,057,606 8,336 0.8 % Costs and Expenses Lease operating 161,596 153,260 8,336 5.4 % Income Before Income Taxes $409,600 $409,600 $— — % |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Devon Acquisition [Member] | |
Business Acquisition [Line Items] | |
Schedule of Assets Acquired and Liabilities Assumed | The following presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase Price Allocation (In thousands) Assets Oil and gas properties Proved properties $47,370 Unproved properties 150,253 Total oil and gas properties $197,623 Total assets acquired $197,623 Liabilities Revenues and royalties payable $855 Asset retirement obligations 170 Total liabilities assumed $1,025 Net Assets Acquired $196,598 |
Business Acquisition, Pro Forma Information | The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017 , assuming the Devon Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Devon Acquisition. Years Ended December 31, 2018 2017 (In thousands, except per share amounts) Total revenues $1,086,742 $753,474 Net Income Attributable to Common Shareholders $384,639 $78,118 Net Income Attributable to Common Shareholders Per Common Share Basic $4.21 $0.94 Diluted $4.13 $0.94 Weighted Average Common Shares Outstanding Basic 91,444 82,921 Diluted 93,077 83,493 |
ExL Acquisition [Member] | |
Business Acquisition [Line Items] | |
Schedule of Assets Acquired and Liabilities Assumed | The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $106 Oil and gas properties Proved properties 294,754 Unproved properties 443,194 Total oil and gas properties $737,948 Total assets acquired $738,054 Liabilities Revenues and royalties payable $5,785 Asset retirement obligations 153 Contingent ExL Consideration 52,300 Total liabilities assumed $58,238 Net Assets Acquired $679,816 |
Schedule of Revenue and Income Since Acquisition Date | The results of operations for the ExL Acquisition have been included in the Company’s consolidated statements of operations since the August 10, 2017 closing date, including total revenues and net income attributable to common shareholders for the years ended December 31, 2018 and 2017 as shown in the table below: Years Ended December 31, 2018 2017 (In thousands) Total revenues $225,135 $53,548 Net Income Attributable to Common Shareholders $176,881 $44,304 |
Business Acquisition, Pro Forma Information | Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition. Years Ended December 31, 2017 2016 (In thousands, except per share amounts) Total revenues $781,378 $454,913 Net Income (Loss) Attributable to Common Shareholders $91,931 ($688,180 ) Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.25 ($9.11 ) Diluted $1.24 ($9.11 ) Weighted Average Common Shares Outstanding Basic 73,421 75,532 Diluted 73,993 75,532 |
Sanchez Acquisition [Member] | |
Business Acquisition [Line Items] | |
Schedule of Revenue and Income Since Acquisition Date | The results of operations for the Sanchez Acquisition have been included in the Company’s consolidated statements of operations since the December 14, 2016 closing date, including total revenues and net income attributable to common shareholders for the years ended December 31, 2018 , 2017 , and 2016 as shown in the table below: Years Ended December 31, 2018 2017 2016 (In thousands) Total revenues $57,780 $37,780 $1,459 Net Income Attributable to Common Shareholders $38,551 $16,459 $966 |
Property And Equipment, Net (Ta
Property And Equipment, Net (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Property and Equipment | As of December 31, 2018 and 2017 , total property and equipment, net consisted of the following: December 31, 2018 2017 Oil and gas properties, full cost method (In thousands) Proved properties $6,278,321 $5,615,153 Accumulated DD&A and impairments (3,944,851 ) (3,649,806 ) Proved properties, net 2,333,470 1,965,347 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 608,830 612,589 Capitalized interest 65,003 47,698 Total unproved properties, not being amortized 673,833 660,287 Other property and equipment 29,191 25,625 Accumulated depreciation (17,970 ) (15,449 ) Other property and equipment, net 11,221 10,176 Total property and equipment, net $3,018,524 $2,635,810 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule Of Components Of Income Tax (Expense) Benefit | The components of income tax expense were as follows: Years Ended December 31, 2018 2017 2016 (In thousands) Current income tax expense U.S. Federal $— $— $— State (792 ) (395 ) — Total current income tax expense (792 ) (395 ) — Deferred income tax expense U.S. Federal — — — State (4,381 ) (3,635 ) — Total deferred income tax expense (4,381 ) (3,635 ) — Income tax expense ($5,173 ) ($4,030 ) $— |
Schedule Of Effective Income Tax Rate Reconciliation | The Company’s income tax expense differs from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016, to income (loss) before income taxes as follows: Years Ended December 31, 2018 2017 2016 (In thousands) Income (loss) before income taxes $409,600 $91,140 ($675,474 ) Income tax (expense) benefit at the U.S. federal statutory rate (86,016 ) (31,899 ) 236,416 State income tax (expense) benefit, net of U.S. federal income tax benefit (5,173 ) (4,030 ) 3,894 Tax deficiencies related to stock-based compensation (2,572 ) (3,089 ) — Provisional impact of Tax Cuts and Jobs Act — (211,724 ) — Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act — 211,724 — (Increase) decrease in valuation allowance due to current period activity 90,116 35,376 (240,864 ) Other (1,528 ) (388 ) 554 Income tax expense ($5,173 ) ($4,030 ) $— |
Schedule Of Deferred Tax Assets And Liabilities | As of December 31, 2018 and 2017 , the net deferred income tax liabilities are comprised of the following: December 31, 2018 2017 (In thousands) Deferred income tax liabilities Oil and gas properties ($16,610 ) ($3,635 ) Derivative assets (10,008 ) (2,140 ) Total deferred income tax liabilities (26,618 ) (5,775 ) Deferred income tax assets Net operating loss carryforward - U.S. federal and state 235,788 242,915 Oil and gas properties — 50,177 Asset retirement obligations 3,927 4,996 Derivative liabilities 20,165 35,585 Other 1,634 1,496 Total deferred income tax assets 261,514 335,169 Deferred income tax asset valuation allowance (242,913 ) (333,029 ) Net deferred income tax assets 18,601 2,140 Net deferred income tax liabilities ($8,017 ) ($3,635 ) |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule Of Debt | Long-term debt consisted of the following as of December 31, 2018 and 2017 : December 31, 2018 2017 (In thousands) Senior Secured Revolving Credit Facility due 2022 $744,431 $291,300 7.50% Senior Notes due 2020 — 450,000 Unamortized premium for 7.50% Senior Notes — 579 Unamortized debt issuance costs for 7.50% Senior Notes — (4,492 ) 6.25% Senior Notes due 2023 650,000 650,000 Unamortized debt issuance costs for 6.25% Senior Notes (6,878 ) (8,208 ) 8.25% Senior Notes due 2025 250,000 250,000 Unamortized debt issuance costs for 8.25% Senior Notes (3,962 ) (4,395 ) Other long-term debt due 2028 — 4,425 Long-term debt $1,633,591 $1,629,209 |
Interest and Commitment Fee Rates | Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00% , or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations. Ratio of Outstanding Borrowings to Lender Commitments Applicable Margin for Base Rate Loans Applicable Margin for Eurodollar Loans Commitment Fee Less than 25% 0.25% 1.25% 0.375% Greater than or equal to 25% but less than 50% 0.50% 1.50% 0.375% Greater than or equal to 50% but less than 75% 0.75% 1.75% 0.500% Greater than or equal to 75% but less than 90% 1.00% 2.00% 0.500% Greater than or equal to 90% 1.25% 2.25% 0.500% |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Roll Forward Of Asset Retirement Obligations | The following table sets forth a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (In thousands) Asset retirement obligations, beginning of period $23,792 $21,240 Liabilities incurred 1,676 3,920 Increase due to acquisition of oil and gas properties 170 153 Liabilities settled — (343 ) Reduction due to divestitures of oil and gas properties (8,547 ) (2,671 ) Accretion expense 1,366 1,799 Revisions to estimated cash flows 245 (306 ) Asset retirement obligations, end of period 18,702 23,792 Current asset retirement obligations (included in other current liabilities) (342 ) (295 ) Non-current asset retirement obligations $18,360 $23,497 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Total Minimum Commitments From Long-Term Non-Cancelable Operating Leases, Drilling Rig, Seismic And Pipeline Volume Commitments | The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of natural gas or produced water to be delivered, as of December 31, 2018 . 2019 2020 2021 2022 2023 2024 and Thereafter Total (In thousands) Operating leases $10,024 $9,154 $6,249 $3,639 $3,680 $20,978 $53,724 Drilling rig contracts (1) 37,077 16,867 813 — — — 54,757 Delivery commitments (2) 3,726 2,807 2,487 30 7 19 9,076 Produced water disposal commitments (3) 18,139 20,894 20,898 20,954 10,471 9,769 101,125 Other 1,800 1,050 — — — — 2,850 Total $70,766 $50,772 $30,447 $24,623 $14,158 $30,766 $221,532 |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Preferred Stock [Abstract] | |
Warrants, Valuation Assumptions | The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $16.08 Expected term (in years) 10.0 Expected volatility 62.9 % Risk-free interest rate 2.2 % Dividend yield — % |
Preferred Stock | The following table sets forth a reconciliation of changes in the carrying amount of Preferred Stock for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (In thousands) Preferred Stock, beginning of period $214,262 $— Relative fair value at issuance — 213,400 Redemption of Preferred Stock (42,897 ) — Accretion on Preferred Stock 3,057 862 Preferred Stock, end of period $174,422 $214,262 |
Schedule of Preferred Stock Dividends Paid in Common Stock | The Company may elect to pay all or a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any preferred stock dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending: Period Percentage On or after December 15, 2018 and on or prior to September 15, 2019 75 % On or after December 15, 2019 and on or prior to September 15, 2020 50 % |
Schedule of Preferred Stock Redemption Premiums | After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends. Period Percentage After August 10, 2020 but on or prior to August 10, 2021 104.4375 % After August 10, 2021 but on or prior to August 10, 2022 102.21875 % After August 10, 2022 100 % |
Stock-based Compensation (Table
Stock-based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Shareholders' Equity And Stock Incentive Plan [Abstract] | |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The table below summarizes restricted stock award and unit activity for the years ended December 31, 2018 , 2017 and 2016 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2016 Unvested restricted stock awards and units, beginning of period 1,041,997 $44.22 Granted 887,254 $27.80 Vested (811,136 ) $36.32 Forfeited (6,405 ) $34.46 Unvested restricted stock awards and units, end of period 1,111,710 $36.93 For the Year Ended December 31, 2017 Unvested restricted stock awards and units, beginning of period 1,111,710 $36.93 Granted 1,020,465 $25.63 Vested (635,965 ) $39.62 Forfeited (13,555 ) $29.11 Unvested restricted stock awards and units, end of period 1,482,655 $28.07 For the Year Ended December 31, 2018 Unvested restricted stock awards and units, beginning of period 1,482,655 $28.07 Granted 1,458,421 $15.49 Vested (621,399 ) $31.48 Forfeited (53,010 ) $17.72 Unvested restricted stock awards and units, end of period 2,266,667 $19.28 |
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity | The table below summarizes the Cash SAR activity for the years ended December 31, 2018 , 2017 and 2016 : Stock Appreciation Rights Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Aggregate Intrinsic Value of Exercises (In millions) For the Year Ended December 31, 2016 Outstanding, beginning of period 700,453 $21.86 Granted 376,260 $27.30 Exercised (354,075 ) $23.89 $5.2 Forfeited — — Expired — — Outstanding, end of period 722,638 $23.69 Vested, end of period 350,840 $19.87 Vested and exercisable, end of period 350,840 $19.87 For the Year Ended December 31, 2017 Outstanding, beginning of period 722,638 $23.69 Granted 342,440 $26.94 Exercised (219,279 ) $17.28 $2.1 Forfeited — — Expired (131,561 ) $24.19 Outstanding, end of period 714,238 $27.12 Vested, end of period 185,899 $27.30 Vested and exercisable, end of period — $27.30 For the Year Ended December 31, 2018 Outstanding, beginning of period 714,238 $27.12 Granted 616,686 $14.67 Exercised — — $— Forfeited — — Expired — — Outstanding, end of period 1,330,924 $21.35 4.3 $— Vested, end of period 543,018 $27.18 Vested and exercisable, end of period — $27.18 2.5 $— |
Schedule of Share-based Payment Award, Non-Options, Valuation Assumptions | The following table summarizes the assumptions used and the resulting grant date fair value per Cash SAR granted during the years ended December 31, 2018 , 2017 , and 2016 : Years Ended December 31, 2018 2017 2016 Expected term (in years) 6.0 4.2 3.9 Expected volatility 54.3 % 54.3 % 45.1 % Risk-free interest rate 2.8 % 1.8 % 1.3 % Dividend yield — % — % — % Grant date fair value per Cash SAR $7.89 $12.00 $9.88 |
Schedule of Share-based Compensation, Performance Shares Award Activity | The table below summarizes performance share activity for the years ended December 31, 2018 , 2017 and 2016 : Target Performance Shares (1) Weighted Average Grant Date Fair Value For the Year Ended December 31, 2016 Unvested performance shares, beginning of period 112,859 $66.83 Granted 41,651 $35.71 Vested at end of performance period — — Forfeited — — Unvested performance shares, end of period 154,510 $58.44 For the Year Ended December 31, 2017 Unvested performance shares, beginning of period 154,510 $58.44 Granted 46,787 $35.14 Vested at end of performance period (56,342 ) $68.15 Forfeited — — Unvested performance shares, end of period 144,955 $47.14 For the Year Ended December 31, 2018 Unvested performance shares, beginning of period 144,955 $47.14 Granted 93,771 $19.09 Vested at end of performance period (49,458 ) $65.51 Did not vest at end of performance period (7,059 ) $65.51 Forfeited — — Unvested performance shares, end of period 182,209 $27.01 (1) The number of performance shares that vest may vary from the number of target performance shares granted depending on the Company ’ s final TSR ranking for the approximate three -year performance period. |
Schedule of Share-based Payment Award, Performance Share Award, Valuation Assumptions | The following table summarizes the assumptions used and the resulting grant date fair value per performance share granted during the years ended December 31, 2018 , 2017 and 2016 : Years Ended December 31, 2018 2017 2016 Number of simulations 500,000 500,000 500,000 Expected term (in years) 3.0 3.0 3.0 Expected volatility 61.5 % 59.2 % 55.3 % Risk-free interest rate 2.4 % 1.5 % 1.2 % Dividend yield — % — % — % Grant date fair value per performance share $19.09 $35.14 $35.71 |
Schedule of Compensation Cost, Allocation of Share-based Compensation Costs by Plan | The following table sets forth the components of stock-based compensation expense, net: Years Ended December 31, 2018 2017 2016 (In thousands) Restricted stock awards and units $18,434 $21,372 $28,196 Cash SARs (2,571 ) (5,023 ) 9,675 Performance shares 1,785 2,442 2,806 17,648 18,791 40,677 Less: amounts capitalized to oil and gas properties (4,124 ) (4,482 ) (4,591 ) Total stock-based compensation expense, net $13,524 $14,309 $36,086 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative [Line Items] | |
Schedule of Contingent Consideration | The purchase and sale agreements of the ExL Acquisition and divestitures of the Company’s assets in the Niobrara, Marcellus and Utica, included contingent consideration arrangements that require the Company to pay or entitle the Company to receive specified amounts if commodity prices exceed specified thresholds, which are summarized in the table below. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further discussion. Contingent Consideration Arrangements Years Threshold (1) Contingent Receipt (Payment) - Annual Contingent Receipt (Payment) - Aggregate Limit (In thousands) Contingent ExL Consideration 2018 $50.00 ($50,000 ) 2019 50.00 (50,000 ) 2020 50.00 (50,000 ) 2021 50.00 (50,000 ) ($125,000 ) Contingent Niobrara Consideration 2018 $55.00 $5,000 2019 55.00 5,000 2020 60.00 5,000 — Contingent Marcellus Consideration 2018 $3.13 $3,000 2019 3.18 3,000 2020 3.30 3,000 $7,500 Contingent Utica Consideration 2018 $50.00 $5,000 2019 53.00 5,000 2020 56.00 5,000 — (1) The price used to determine whether the specified threshold for each year has been met for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration. The price used to determine whether the specified threshold for each year has been met for the Contingent Marcellus Consideration is the average monthly settlement price per MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc. |
Schedule of Derivative Instrument Fair Value Assets and Liabilities | The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of December 31, 2018 and December 31, 2017 are summarized below: December 31, 2018 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $50,406 ($20,502 ) $29,904 Contingent Niobrara Consideration 5,000 — 5,000 Contingent Utica Consideration 5,000 — 5,000 Derivative assets $60,406 ($20,502 ) $39,904 Commodity derivative instruments 6,083 (4,236 ) 1,847 Contingent Niobrara Consideration 2,035 — 2,035 Contingent Marcellus Consideration 1,369 — 1,369 Contingent Utica Consideration 2,501 — 2,501 Other long-term assets $11,988 ($4,236 ) $7,752 Commodity derivative instruments ($15,345 ) $10,140 ($5,205 ) Deferred premium obligations (10,362 ) 10,362 — Contingent ExL Consideration (50,000 ) — (50,000 ) Derivative liabilities-current ($75,707 ) $20,502 ($55,205 ) Commodity derivative instruments (10,751 ) 518 (10,233 ) Deferred premium obligations (3,718 ) 3,718 — Contingent ExL Consideration (30,584 ) — (30,584 ) Derivative liabilities-non current ($45,053 ) $4,236 ($40,817 ) December 31, 2017 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $4,869 ($4,869 ) $— Derivative assets $4,869 ($4,869 ) $— Commodity derivative instruments 9,505 (9,505 ) — Contingent Marcellus Consideration 2,205 — 2,205 Contingent Utica Consideration 7,985 — 7,985 Other long-term assets $19,695 ($9,505 ) $10,190 Commodity derivative instruments ($52,671 ) ($4,450 ) ($57,121 ) Deferred premium obligations (9,319 ) 9,319 — Derivative liabilities-current ($61,990 ) $4,869 ($57,121 ) Commodity derivative instruments (24,609 ) (2,098 ) (26,707 ) Deferred premium obligations (11,603 ) 11,603 — Contingent ExL Consideration (85,625 ) — (85,625 ) Derivative liabilities-non current ($121,837 ) $9,505 ($112,332 ) |
Derivative Instruments, (Gain) Loss | The components of “(Gain) loss on derivatives, net” in the consolidated statements of operations for the years ended December 31, 2018 , 2017 , and 2016 are summarized below: Years Ended December 31, 2018 2017 2016 (In thousands) (Gain) Loss on Derivatives, Net Crude oil ($9,726 ) $22,839 $23,609 NGL 4,439 1,322 — Natural gas (421 ) (15,399 ) 19,584 Deferred premium obligations 1,875 18,401 5,880 Contingent ExL Consideration (5,041 ) 33,325 — Contingent Niobrara Consideration 845 — — Contingent Marcellus Consideration 836 455 — Contingent Utica Consideration 484 (1,840 ) — (Gain) Loss on Derivatives, Net ($6,709 ) $59,103 $49,073 |
Schedule of Cash Received for Derivatives | The components of “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows for the years ended December 31, 2018 , 2017 , and 2016 are summarized below: Years Ended December 31, 2018 2017 2016 Cash Flows from Operating Activities (In thousands) Cash Received (Paid) for Derivative Settlements, Net Crude oil ($78,570 ) $9,883 $125,098 NGL (6,378 ) — — Natural gas (1,710 ) (54 ) — Deferred premium obligations (9,649 ) (2,056 ) (5,729 ) Cash Received (Paid) for Derivative Settlements, Net ($96,307 ) $7,773 $119,369 |
Crude Oil [Member] | |
Derivative [Line Items] | |
Schedule of Derivative Positions | Commodity Period Type of Contract Index Volumes Sub-Floor Floor Price Ceiling Price Fixed Crude oil 1Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 1Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 1Q19 Basis Swaps WTI Midland-WTI Cushing 5,500 — — — ($5.24 ) Crude oil 1Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 2Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 2Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 2Q19 Basis Swaps WTI Midland-WTI Cushing 6,000 — — — ($5.38 ) Crude oil 2Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 3Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 3Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 3Q19 Basis Swaps WTI Midland-WTI Cushing 7,000 — — — ($5.56 ) Crude oil 3Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 4Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 4Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 4Q19 Basis Swaps WTI Midland-WTI Cushing 11,000 — — — ($3.84 ) Crude oil 4Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 2020 Basis Swaps WTI Midland-WTI Cushing 13,000 — — — ($1.27 ) Crude oil 2020 Sold Call Options NYMEX WTI 4,575 — — $75.98 — Crude oil 2021 Basis Swaps WTI Midland-WTI Cushing 6,000 — — — $0.03 Subsequent to December 31, 2018 , the Company entered into the following commodity derivative instruments at weighted average contract volumes and prices: Commodity Period Type of Contract Index Volumes Fixed Price Sub-Floor Floor Price Ceiling Price Crude oil 2020 Price Swaps NYMEX WTI 3,000 $55.06 — — — Crude oil 2020 Three-Way Collars NYMEX WTI 6,000 — $45.00 $55.00 $64.69 |
Natural Gas [Member] | |
Derivative [Line Items] | |
Schedule of Derivative Positions | Commodity Period Type of Contract Index Volumes (MMBtu per day) Sub-Floor Price ($ per MMBtu) Floor Price ($ per MMBtu) Ceiling Price ($ per MMBtu) Fixed Price Differential ($ per MMBtu) Natural gas 1Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 2Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 3Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 4Q19 Sold Call options NYMEX Henry Hub 33,000 — — $3.25 — Natural gas 2020 Sold Call options NYMEX Henry Hub 33,000 — — $3.50 — |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | The following tables summarize the Company’s derivative instrument assets and liabilities measured at fair value on a recurring basis as of December 31, 2018 and 2017 : December 31, 2018 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $31,751 $— Contingent Niobrara Consideration — 7,035 — Contingent Marcellus Consideration — 1,369 — Contingent Utica Consideration — 7,501 — Liabilities Commodity derivative instruments $— ($15,438 ) $— Contingent ExL Consideration — (80,584 ) — December 31, 2017 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $— $— Contingent Niobrara Consideration — — — Contingent Marcellus Consideration — — 2,205 Contingent Utica Consideration — — 7,985 Liabilities Commodity derivative instruments $— ($83,828 ) $— Contingent ExL Consideration — — (85,625 ) |
Fair Value, Unobservable Input Reconciliation | The following tables present the reconciliation of changes in the fair values of the contingent consideration arrangements, which were designated within the valuation hierarchy as Level 2 for the year ended December 31, 2018 and Level 3 for the year ended December 31, 2017 : Contingent Consideration Arrangements Assets Liability (In thousands) Balance as of January 1, 2017 $— $— Recognition of (acquisition) divestiture date fair value 8,805 (52,300 ) Gain (loss) on change in fair value, net (1) 1,385 (33,325 ) Transfers into (out of) Level 3 — — Balance as of December 31, 2017 $10,190 ($85,625 ) Recognition of divestiture date fair value 7,880 — Gain (loss) on changes in fair value, net (1) (2,165 ) 5,041 Transfers out of Level 3 (15,905 ) 80,584 Balance as of December 31, 2018 $— $— (1) Recognized as “(Gain) loss on derivatives, net” in the consolidated statements of operations. |
Schedule of Fair Value of Debt Instruments | The following table presents the principal amounts of the Company’s senior notes and other long-term debt with the fair values measured using quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy. See “Note 6. Long-Term Debt” for additional discussion. December 31, 2018 December 31, 2017 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 7.50% Senior Notes due 2020 $— $— $450,000 $459,518 6.25% Senior Notes due 2023 650,000 599,625 650,000 674,375 8.25% Senior Notes due 2025 250,000 244,375 250,000 274,375 Other long-term debt due 2028 — — 4,425 4,445 |
Condensed Consolidating Finan_2
Condensed Consolidating Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Condensed Consolidating Financial Information [Abstract] | |
Condensed Consolidating Financial Information | 14. Condensed Consolidating Financial Information The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities. CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,341,680 $114,005 $— ($3,305,316 ) $150,369 Total property and equipment, net 7,951 3,011,387 3,028 (3,842 ) 3,018,524 Investment in subsidiaries (419,159 ) — — 419,159 — Other long-term assets 28,124 5,906 — (17,823 ) 16,207 Total Assets $2,958,596 $3,131,298 $3,028 ($2,907,822 ) $3,185,100 Liabilities and Shareholders’ Equity Current liabilities $135,980 $3,491,337 $3,028 ($3,308,336 ) $322,009 Long-term liabilities 1,650,589 59,120 — (1,944 ) 1,707,765 Preferred stock 174,422 — — — 174,422 Total shareholders’ equity 997,605 (419,159 ) — 402,458 980,904 Total Liabilities and Shareholders’ Equity $2,958,596 $3,131,298 $3,028 ($2,907,822 ) $3,185,100 December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,441,633 $105,533 $— ($3,424,288 ) $122,878 Total property and equipment, net 5,953 2,630,707 3,028 (3,878 ) 2,635,810 Investment in subsidiaries (999,793 ) — — 999,793 — Other long-term assets 9,270 10,346 — — 19,616 Total Assets $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 Liabilities and Shareholders’ Equity Current liabilities $165,701 $3,631,401 $3,028 ($3,427,308 ) $372,822 Long-term liabilities 1,689,466 114,978 — 15,879 1,820,323 Preferred stock 214,262 — — — 214,262 Total shareholders’ equity 387,634 (999,793 ) — 983,056 370,897 Total Liabilities and Shareholders’ Equity $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $162 $1,065,780 $— $— $1,065,942 Total costs and expenses 176,406 479,973 — (37 ) 656,342 Income (loss) before income taxes (176,244 ) 585,807 — 37 409,600 Income tax expense — (5,173 ) — — (5,173 ) Equity in income of subsidiaries 580,634 — — (580,634 ) — Net income $404,390 $580,634 $— ($580,597 ) $404,427 Dividends on preferred stock (18,161 ) — — — (18,161 ) Accretion on preferred stock (3,057 ) — — — (3,057 ) Loss on redemption of preferred stock (7,133 ) — — — (7,133 ) Net income attributable to common shareholders $376,039 $580,634 $— ($580,597 ) $376,076 Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $302 $745,586 $— $— $745,888 Total costs and expenses 195,728 459,057 — (37 ) 654,748 Income (loss) before income taxes (195,426 ) 286,529 — 37 91,140 Income tax expense — (4,030 ) — — (4,030 ) Equity in income of subsidiaries 282,499 — — (282,499 ) — Net income $87,073 $282,499 $— ($282,462 ) $87,110 Dividends on preferred stock (7,781 ) — — — (7,781 ) Accretion on preferred stock (862 ) — — — (862 ) Loss on redemption of preferred stock — — — — — Net income attributable to common shareholders $78,430 $282,499 $— ($282,462 ) $78,467 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $482 $443,112 $— $— $443,594 Total costs and expenses 208,054 910,522 — 492 1,119,068 Loss before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax expense — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Loss on redemption of preferred stock — — — — — Net loss attributable to common shareholders ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($269,318 ) $922,873 $— $— $653,555 Net cash provided by (used in) investing activities 126,905 (792,383 ) — (130,490 ) (795,968 ) Net cash provided by (used in) financing activities 135,155 (130,490 ) — 130,490 135,155 Net decrease in cash and cash equivalents (7,258 ) — — — (7,258 ) Cash and cash equivalents, beginning of year 9,540 — — — 9,540 Cash and cash equivalents, end of year $2,282 $— $— $— $2,282 Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($121,107 ) $544,088 $— $— $422,981 Net cash used in investing activities (615,364 ) (1,155,340 ) — 611,252 (1,159,452 ) Net cash provided by financing activities 741,817 611,252 — (611,252 ) 741,817 Net increase in cash and cash equivalents 5,346 — — — 5,346 Cash and cash equivalents, beginning of year 4,194 — — — 4,194 Cash and cash equivalents, end of year $9,540 $— $— $— $9,540 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities 308,340 268,283 740 (269,023 ) 308,340 Net decrease in cash and cash equivalents (38,724 ) — — — (38,724 ) Cash and cash equivalents, beginning of year 42,918 — — — 42,918 Cash and cash equivalents, end of year $4,194 $— $— $— $4,194 |
Schedule Of Condensed Consolidating Balance Sheets | CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,341,680 $114,005 $— ($3,305,316 ) $150,369 Total property and equipment, net 7,951 3,011,387 3,028 (3,842 ) 3,018,524 Investment in subsidiaries (419,159 ) — — 419,159 — Other long-term assets 28,124 5,906 — (17,823 ) 16,207 Total Assets $2,958,596 $3,131,298 $3,028 ($2,907,822 ) $3,185,100 Liabilities and Shareholders’ Equity Current liabilities $135,980 $3,491,337 $3,028 ($3,308,336 ) $322,009 Long-term liabilities 1,650,589 59,120 — (1,944 ) 1,707,765 Preferred stock 174,422 — — — 174,422 Total shareholders’ equity 997,605 (419,159 ) — 402,458 980,904 Total Liabilities and Shareholders’ Equity $2,958,596 $3,131,298 $3,028 ($2,907,822 ) $3,185,100 December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,441,633 $105,533 $— ($3,424,288 ) $122,878 Total property and equipment, net 5,953 2,630,707 3,028 (3,878 ) 2,635,810 Investment in subsidiaries (999,793 ) — — 999,793 — Other long-term assets 9,270 10,346 — — 19,616 Total Assets $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 Liabilities and Shareholders’ Equity Current liabilities $165,701 $3,631,401 $3,028 ($3,427,308 ) $372,822 Long-term liabilities 1,689,466 114,978 — 15,879 1,820,323 Preferred stock 214,262 — — — 214,262 Total shareholders’ equity 387,634 (999,793 ) — 983,056 370,897 Total Liabilities and Shareholders’ Equity $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 |
Schedule Of Condensed Consolidating Statements Of Operations | CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $162 $1,065,780 $— $— $1,065,942 Total costs and expenses 176,406 479,973 — (37 ) 656,342 Income (loss) before income taxes (176,244 ) 585,807 — 37 409,600 Income tax expense — (5,173 ) — — (5,173 ) Equity in income of subsidiaries 580,634 — — (580,634 ) — Net income $404,390 $580,634 $— ($580,597 ) $404,427 Dividends on preferred stock (18,161 ) — — — (18,161 ) Accretion on preferred stock (3,057 ) — — — (3,057 ) Loss on redemption of preferred stock (7,133 ) — — — (7,133 ) Net income attributable to common shareholders $376,039 $580,634 $— ($580,597 ) $376,076 Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $302 $745,586 $— $— $745,888 Total costs and expenses 195,728 459,057 — (37 ) 654,748 Income (loss) before income taxes (195,426 ) 286,529 — 37 91,140 Income tax expense — (4,030 ) — — (4,030 ) Equity in income of subsidiaries 282,499 — — (282,499 ) — Net income $87,073 $282,499 $— ($282,462 ) $87,110 Dividends on preferred stock (7,781 ) — — — (7,781 ) Accretion on preferred stock (862 ) — — — (862 ) Loss on redemption of preferred stock — — — — — Net income attributable to common shareholders $78,430 $282,499 $— ($282,462 ) $78,467 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $482 $443,112 $— $— $443,594 Total costs and expenses 208,054 910,522 — 492 1,119,068 Loss before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax expense — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Loss on redemption of preferred stock — — — — — Net loss attributable to common shareholders ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) |
Schedule Of Condensed Consolidating Statements Of Cash Flows | CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2018 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($269,318 ) $922,873 $— $— $653,555 Net cash provided by (used in) investing activities 126,905 (792,383 ) — (130,490 ) (795,968 ) Net cash provided by (used in) financing activities 135,155 (130,490 ) — 130,490 135,155 Net decrease in cash and cash equivalents (7,258 ) — — — (7,258 ) Cash and cash equivalents, beginning of year 9,540 — — — 9,540 Cash and cash equivalents, end of year $2,282 $— $— $— $2,282 Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($121,107 ) $544,088 $— $— $422,981 Net cash used in investing activities (615,364 ) (1,155,340 ) — 611,252 (1,159,452 ) Net cash provided by financing activities 741,817 611,252 — (611,252 ) 741,817 Net increase in cash and cash equivalents 5,346 — — — 5,346 Cash and cash equivalents, beginning of year 4,194 — — — 4,194 Cash and cash equivalents, end of year $9,540 $— $— $— $9,540 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities 308,340 268,283 740 (269,023 ) 308,340 Net decrease in cash and cash equivalents (38,724 ) — — — (38,724 ) Cash and cash equivalents, beginning of year 42,918 — — — 42,918 Cash and cash equivalents, end of year $4,194 $— $— $— $4,194 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Years Ended December 31, 2018 2017 2016 (In thousands) Operating activities: Cash paid for interest, net of amounts capitalized $59,846 $77,213 $75,231 Cash paid for income taxes — — — Investing activities: Increase (decrease) in capital expenditure payables and accruals ($53,722 ) $102,272 ($21,492 ) Supplemental non-cash investing activities: Fair value of contingent consideration assets on date of divestiture (7,880 ) (8,805 ) — Fair value of contingent consideration liabilities on date of acquisition — 52,300 — Liabilities assumed in connection with the Sanchez Acquisition — — 4,880 Stock-based compensation expense capitalized to oil and gas properties 4,124 4,482 4,591 Asset retirement obligations capitalized to oil and gas properties 2,132 3,726 1,927 Supplemental non-cash financing activities: Non-cash loss on extinguishment of debt, net 3,586 1,357 — |
Subsequent Events (Unaudited) (
Subsequent Events (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Crude Oil [Member] | |
Derivative [Line Items] | |
Schedule of Derivative Positions | Commodity Period Type of Contract Index Volumes Sub-Floor Floor Price Ceiling Price Fixed Crude oil 1Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 1Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 1Q19 Basis Swaps WTI Midland-WTI Cushing 5,500 — — — ($5.24 ) Crude oil 1Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 2Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 2Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 2Q19 Basis Swaps WTI Midland-WTI Cushing 6,000 — — — ($5.38 ) Crude oil 2Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 3Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 3Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 3Q19 Basis Swaps WTI Midland-WTI Cushing 7,000 — — — ($5.56 ) Crude oil 3Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 4Q19 Three-Way Collars NYMEX WTI 27,000 $41.67 $50.96 $74.23 — Crude oil 4Q19 Basis Swaps LLS-WTI Cushing 6,000 — — — $5.16 Crude oil 4Q19 Basis Swaps WTI Midland-WTI Cushing 11,000 — — — ($3.84 ) Crude oil 4Q19 Sold Call Options NYMEX WTI 3,875 — — $81.07 — Crude oil 2020 Basis Swaps WTI Midland-WTI Cushing 13,000 — — — ($1.27 ) Crude oil 2020 Sold Call Options NYMEX WTI 4,575 — — $75.98 — Crude oil 2021 Basis Swaps WTI Midland-WTI Cushing 6,000 — — — $0.03 Subsequent to December 31, 2018 , the Company entered into the following commodity derivative instruments at weighted average contract volumes and prices: Commodity Period Type of Contract Index Volumes Fixed Price Sub-Floor Floor Price Ceiling Price Crude oil 2020 Price Swaps NYMEX WTI 3,000 $55.06 — — — Crude oil 2020 Three-Way Collars NYMEX WTI 6,000 — $45.00 $55.00 $64.69 |
Supplemental Disclosures Abou_2
Supplemental Disclosures About Oil And Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Costs Incurred in Oil And Gas Property Acquisition, Exploration and Development | Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Years Ended December 31, 2018 2017 2016 (In thousands) Property acquisition costs Proved properties $47,370 $303,307 $90,661 Unproved properties 182,220 525,061 113,535 Total property acquisition costs 229,590 828,368 204,196 Exploration costs 48,570 91,098 37,508 Development costs 809,637 569,982 374,134 Total costs incurred $1,087,797 $1,489,448 $615,838 |
Schedule of Proved Oil And Gas Reserves and Changes in Proved Reserves | The Company’s proved reserves and changes in proved reserves are as follows: Crude Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total Proved Reserves (MBoe) Proved reserves: January 1, 2016 109,588 20,221 244,938 170,632 Extensions and discoveries 40,074 8,612 59,318 58,572 Revisions of previous estimates (16,731 ) (3,230 ) 1,481 (19,713 ) Purchases of reserves in place 4,810 122 7,282 6,145 Production (9,423 ) (1,788 ) (25,574 ) (15,473 ) December 31, 2016 128,318 23,937 287,445 200,163 Extensions and discoveries 50,476 13,781 98,980 80,754 Revisions of previous estimates (19,838 ) (909 ) 27,774 (16,118 ) Purchases of reserves in place 21,634 8,642 94,962 46,103 Sales of reserves in place (650 ) (526 ) (170,219 ) (29,546 ) Production (12,566 ) (2,327 ) (28,472 ) (19,639 ) December 31, 2017 167,374 42,598 310,470 261,717 Extensions and discoveries 65,352 30,195 212,758 131,007 Revisions of previous estimates (31,287 ) 1,936 (6,006 ) (30,352 ) Purchases of reserves in place 2,205 967 7,953 4,498 Sales of reserves in place (9,676 ) (2,872 ) (17,475 ) (15,461 ) Production (14,232 ) (3,701 ) (24,639 ) (22,040 ) December 31, 2018 179,736 69,123 483,061 329,369 Proved developed reserves: December 31, 2015 42,311 7,933 154,725 76,032 December 31, 2016 51,062 9,387 187,054 91,625 December 31, 2017 69,632 17,447 131,355 108,972 December 31, 2018 75,267 25,809 178,941 130,899 Proved undeveloped reserves: December 31, 2015 67,277 12,288 90,213 94,600 December 31, 2016 77,256 14,550 100,391 108,538 December 31, 2017 97,742 25,151 179,115 152,745 December 31, 2018 104,469 43,314 304,120 198,470 |
Schedule of Reserves Estimates Average Prices | Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2018 2017 2016 Crude oil ($/Bbl) $63.80 $49.87 $39.60 NGLs ($/Bbl) $26.15 $19.78 $11.66 Natural gas ($/Mcf) $2.46 $2.96 $1.89 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2018 2017 2016 (In thousands) Future cash inflows $14,461,143 $10,109,752 $5,903,629 Future production costs (4,572,397 ) (3,202,201 ) (2,241,928 ) Future development costs (1,964,450 ) (1,699,909 ) (1,264,493 ) Future income taxes (1) (1,005,837 ) (445,056 ) — Future net cash flows 6,918,459 4,762,586 2,397,208 Less 10% annual discount to reflect timing of cash flows (3,282,901 ) (2,297,544 ) (1,093,779 ) Standardized measure of discounted future net cash flows $3,635,558 $2,465,042 $1,303,429 (1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016. |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows | Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below: Years Ended December 31, 2018 2017 2016 (In thousands) Standardized measure at beginning of year $2,465,042 $1,303,429 $1,365,224 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production $809,182 $710,773 ($346,763 ) Net change in estimated future development costs (9,627 ) (51,854 ) 74,407 Net change due to revisions in quantity estimates (250,817 ) (42,214 ) (150,245 ) Accretion of discount 263,837 130,343 136,522 Changes in production rates (timing) and other (19,539 ) (116,056 ) (111,137 ) Total revisions to reserves proved in prior years 793,036 630,992 (397,216 ) Net change due to extensions and discoveries, net of estimated future development and production costs 1,127,748 597,502 313,201 Net change due to purchases of reserves in place 60,264 452,932 43,426 Net change due to divestitures of reserves in place (181,308 ) (106,608 ) — Sales of crude oil, NGLs and natural gas produced, net of production costs (843,333 ) (566,258 ) (320,272 ) Previously estimated development costs incurred 496,600 326,383 299,066 Net change in income taxes (282,491 ) (173,330 ) — Net change in standardized measure of discounted future net cash flows 1,170,516 1,161,613 (61,795 ) Standardized measure at end of year $3,635,558 $2,465,042 $1,303,429 |
Selected Quarterly Financial _2
Selected Quarterly Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Quarterly Financial Information | The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2018 and 2017 : Year Ended December 31, 2018 First Quarter (3) Second Quarter (4) Third Quarter Fourth Quarter (5) (In thousands, except per share amounts) Total revenues $225,280 $263,973 $303,375 $273,314 Operating profit (1) $108,992 $140,265 $165,141 $129,405 Net income $27,492 $35,309 $81,346 $260,280 Net income attributable to common shareholders $14,743 $30,095 $76,118 $255,120 Net income attributable to common shareholders per common share (2) Basic $0.18 $0.37 $0.88 $2.79 Diluted $0.18 $0.36 $0.85 $2.75 Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter (6) Fourth Quarter (7) (In thousands, except per share amounts) Total revenues $151,355 $166,483 $181,279 $246,771 Operating profit (1) $57,953 $63,147 $69,364 $113,205 Net income (loss) $40,021 $56,306 $7,823 ($17,040 ) Net income (loss) attributable to common shareholders $40,021 $56,306 $5,574 ($23,434 ) Net income (loss) attributable to common shareholders per common share (2) Basic $0.61 $0.86 $0.07 ($0.29 ) Diluted $0.61 $0.85 $0.07 ($0.29 ) |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Line Items] | ||
Other Accounts Payable and Accrued Liabilities | $ 70,400,000 | $ 62,600,000 |
Reserves discount factor | 10.00% | |
Contract with Customer, Asset, Gross | $ 77,100,000 | 85,600,000 |
Compensation Cost, Expired Cash Stock Appreciation Rights | $ 0 | |
Tax Adjustments, Settlements, and Unusual Provisions | 15,700,000 | |
Tax Adjustments, Settlements, and Unusual Provisions, Retained Earnings Effect | $ 0 | |
Minimum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Estimated useful life, minimum, years | 3 years | |
Operating Lease, Right-of-Use Asset | $ 75,000,000 | |
Maximum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Estimated useful life, minimum, years | 10 years | |
Operating Lease, Right-of-Use Asset | $ 100,000,000 | |
Restricted Stock Awards And Units [Member] | Minimum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Vesting period, in years | 1 year | |
Restricted Stock Awards And Units [Member] | Maximum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Vesting period, in years | 3 years | |
Stock Appreciation Rights (SARs) [Member] | Minimum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Vesting period, in years | 2 years | |
Expiration period, in years | 5 years | |
Stock Appreciation Rights (SARs) [Member] | Maximum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Vesting period, in years | 3 years | |
Expiration period, in years | 7 years | |
Performance Shares [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Vesting period, in years | 3 years | |
Performance Shares [Member] | Minimum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Range of Awards to Vest Based on Market Condition | 0.00% | |
Performance Shares [Member] | Maximum [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Range of Awards to Vest Based on Market Condition | 200.00% | |
Contractor [Member] | Restricted Stock Awards And Units [Member] | ||
Summary of Significant Accounting Policies [Line Items] | ||
Vesting period, in years | 3 years |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies (Schedule of Major Customers) (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Customer One [Member] | |||
Revenue, Major Customer [Line Items] | |||
Customer percentage of total revenue | 73.00% | 69.00% | 56.00% |
Customer Two [Member] | |||
Revenue, Major Customer [Line Items] | |||
Customer percentage of total revenue | 15.00% |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies (Schedule of Earnings Per Share Reconciliation) (Details) - USD ($) $ / shares in Units, shares in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net Income (Loss) Attributable to Parent | $ 260,280,000 | $ 81,346,000 | $ 35,309,000 | $ 27,492,000 | $ (17,040,000) | $ 7,823,000 | $ 56,306,000 | $ 40,021,000 | $ 404,427,000 | $ 87,110,000 | $ (675,474,000) |
Preferred Stock Dividends, Income Statement Impact | 18,161,000 | 7,781,000 | 0 | ||||||||
Accretion on preferred stock | (3,057,000) | (862,000) | 0 | ||||||||
Gain (Loss) On Redemption Of Preferred Stock | 7,100,000 | (7,133,000) | 0 | 0 | |||||||
Net Income (Loss) Attributable to Common Shareholders | $ 255,120,000 | $ 76,118,000 | $ 30,095,000 | $ 14,743,000 | $ (23,434,000) | $ 5,574,000 | $ 56,306,000 | $ 40,021,000 | $ 376,076,000 | $ 78,467,000 | $ (675,474,000) |
Weighted Average Number of Shares Outstanding, Basic | 85,509 | 73,421 | 59,932 | ||||||||
Nonvested Shares with Forfeitable Dividends | 949 | 269 | 0 | ||||||||
Warrants | 685 | 303 | 0 | ||||||||
Weighted Average Number of Shares Outstanding, Diluted | 87,143 | 73,993 | 59,932 | ||||||||
Net Income (Loss) Attributable to Common Shareholders Per Common Share | |||||||||||
Net Income (Loss) Attributable to Common Shareholders, Per Basic Share | $ 2.79 | $ 0.88 | $ 0.37 | $ 0.18 | $ (0.29) | $ 0.07 | $ 0.86 | $ 0.61 | $ 4.40 | $ 1.07 | $ (11.27) |
Net Income (Loss) Attributable to Common Shareholders, Per Diluted Share | $ 2.75 | $ 0.85 | $ 0.36 | $ 0.18 | $ (0.29) | $ 0.07 | $ 0.85 | $ 0.61 | $ 4.32 | $ 1.06 | $ (11.27) |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies (Schedule of Antidilutive Shares Excluded from Earnings Per Share) (Details) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted Stock And Performance Shares [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 19 | 52 | 669 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies (Schedule of Impact of Adoption) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 273,314 | $ 303,375 | $ 263,973 | $ 225,280 | $ 246,771 | $ 181,279 | $ 166,483 | $ 151,355 | $ 1,065,942 | $ 745,888 | $ 443,594 |
Lease operating | 161,596 | 139,854 | 98,717 | ||||||||
Income (loss) before income taxes | 409,600 | 91,140 | (675,474) | ||||||||
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 1,057,606 | ||||||||||
Lease operating | 153,260 | ||||||||||
Income (loss) before income taxes | 409,600 | ||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Lease operating | 8,336 | ||||||||||
Income (loss) before income taxes | 0 | ||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 8,336 | ||||||||||
Crude Oil [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Percent Difference Between Revenue Guidance In Effect Before And After Topic 606 | 0.10% | ||||||||||
Natural Gas Liquids | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Percent Difference Between Revenue Guidance In Effect Before And After Topic 606 | 5.40% | ||||||||||
Natural Gas [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Percent Difference Between Revenue Guidance In Effect Before And After Topic 606 | 5.10% | ||||||||||
Barrel of Oil Equivalent [Domain] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Percent Difference Between Revenue Guidance In Effect Before And After Topic 606 | 0.80% | ||||||||||
Operating Expense [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Percent Difference Between Revenue Guidance In Effect Before And After Topic 606 | 5.40% | ||||||||||
Income Before Income Taxes [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Percent Difference Between Revenue Guidance In Effect Before And After Topic 606 | 0.00% | ||||||||||
Oil and Condensate | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 911,554 | 633,233 | 378,073 | ||||||||
Oil and Condensate | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 910,975 | ||||||||||
Oil and Condensate | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 579 | ||||||||||
Natural Gas Liquids | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 96,585 | 47,405 | 22,428 | ||||||||
Natural Gas Liquids | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 91,608 | ||||||||||
Natural Gas Liquids | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 4,977 | ||||||||||
Natural Gas | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 57,803 | $ 65,250 | $ 43,093 | ||||||||
Natural Gas | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 55,023 | ||||||||||
Natural Gas | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 2,780 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 8 Months Ended | 12 Months Ended | 15 Months Ended | ||||||||||||||||||||
Feb. 28, 2018 | Jan. 31, 2018 | Apr. 30, 2017 | Jan. 31, 2017 | Dec. 31, 2016 | Oct. 31, 2016 | Dec. 31, 2018 | Sep. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Jul. 31, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Jul. 11, 2018 | Dec. 11, 2017 | Nov. 20, 2017 | Oct. 05, 2017 | Aug. 31, 2017 | |
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Oil and Gas Property | $ 204,854 | $ 695,774 | $ 153,521 | ||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | $ 15,300 | 381,434 | 197,564 | 15,564 | |||||||||||||||||||||
Devon Acquisition [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Purchase Price of Oil and Gas Property and Equipment | $ 215,000 | ||||||||||||||||||||||||
Deposit For Acquisition Of Oil And Gas Properties | 21,500 | ||||||||||||||||||||||||
Payments to Acquire Oil and Gas Property | $ 183,400 | ||||||||||||||||||||||||
Revenue of Acquiree since Acquisition Date, Actual | 4,600 | ||||||||||||||||||||||||
Earnings (Loss) of Acquiree since Acquisition Date, Actual | 2,700 | ||||||||||||||||||||||||
Estimated Aggregate Purchase Price | 196,600 | ||||||||||||||||||||||||
Delaware Basin Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Sale Price of Oil and Gas Property and Equipment | $ 30,000 | ||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 31,400 | 30,900 | |||||||||||||||||||||||
Cash Paid for Post-Closing Adjustments to Divestitures | $ (500) | ||||||||||||||||||||||||
Eagle Ford Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Sale Price of Oil and Gas Property and Equipment | $ 245,000 | ||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | $ 245,700 | ||||||||||||||||||||||||
Cash Paid for Post-Closing Adjustments to Divestitures | (500) | ||||||||||||||||||||||||
Niobrara Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Sale Price of Oil and Gas Property and Equipment | $ 140,000 | ||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | $ 122,600 | $ 14,000 | $ 135,600 | ||||||||||||||||||||||
Cash Paid for Post-Closing Adjustments to Divestitures | $ (1,000) | ||||||||||||||||||||||||
ExL Acquisition [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Purchase Price of Oil and Gas Property and Equipment | $ 648,000 | ||||||||||||||||||||||||
Payments to Acquire Oil and Gas Property | $ 75,000 | 679,800 | |||||||||||||||||||||||
Revenue of Acquiree since Acquisition Date, Actual | 225,135 | 53,548 | |||||||||||||||||||||||
Earnings (Loss) of Acquiree since Acquisition Date, Actual | 176,881 | 44,304 | |||||||||||||||||||||||
Marcellus Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Sale Price of Oil and Gas Property and Equipment | $ 84,000 | ||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 73,900 | ||||||||||||||||||||||||
Utica Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Sale Price of Oil and Gas Property and Equipment | $ 62,000 | ||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 63,100 | ||||||||||||||||||||||||
Sanchez Acquisition [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Agreed Upon Purchase Price of Oil and Gas Property and Equipment | $ 181,000 | ||||||||||||||||||||||||
Payments to Acquire Oil and Gas Property | $ 9,800 | $ 7,000 | $ 143,500 | $ 10,000 | $ 170,300 | ||||||||||||||||||||
Revenue of Acquiree since Acquisition Date, Actual | 57,780 | 37,780 | 1,459 | ||||||||||||||||||||||
Earnings (Loss) of Acquiree since Acquisition Date, Actual | $ 38,551 | $ 16,459 | $ 966 | ||||||||||||||||||||||
Deposit Received Prior To Closing [Member] | Eagle Ford Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 24,500 | ||||||||||||||||||||||||
Deposit Received Prior To Closing [Member] | Marcellus Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 6,300 | ||||||||||||||||||||||||
Deposit Received Prior To Closing [Member] | Utica Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | $ 6,200 | ||||||||||||||||||||||||
Cash Received At Closing [Member] | Eagle Ford Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | $ 211,700 | ||||||||||||||||||||||||
Cash Received At Closing [Member] | Marcellus Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 67,600 | ||||||||||||||||||||||||
Cash Received At Closing [Member] | Utica Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 54,400 | ||||||||||||||||||||||||
Cash Received Post Closing [Member] | Eagle Ford Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | $ 10,000 | ||||||||||||||||||||||||
Cash Received Post Closing [Member] | Utica Shale Divestiture [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from divestitures of oil and gas properties | 2,500 | ||||||||||||||||||||||||
Cash Paid At Closing [Member] | ExL Acquisition [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Oil and Gas Property | $ 601,000 | ||||||||||||||||||||||||
Cash Paid Post Closing [Member] | ExL Acquisition [Member] | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Oil and Gas Property | $ 3,800 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures (Schedule of Consideration Paid for Assets Acquired and Liabilities Assumed) (Table) (Details) - USD ($) $ in Thousands | Oct. 17, 2018 | Aug. 10, 2017 |
Devon Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Business Combination, Oil and Gas Properties, Net | $ 47,370 | |
Business Combination, Unproved Oil and Gas Properties | 150,253 | |
Business Combination, Oil and Gas Properties | 197,623 | |
Business Combination, Total Assets | 197,623 | |
Business Combination, Current Liabilities | 855 | |
Business Combination, Noncurrent Liabilities | 170 | |
Business Combination, Liabilities | 1,025 | |
Business Combination, Net | $ 196,598 | |
ExL Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Business Combination, Current Assets | $ 106 | |
Business Combination, Oil and Gas Properties, Net | 294,754 | |
Business Combination, Unproved Oil and Gas Properties | 443,194 | |
Business Combination, Oil and Gas Properties | 737,948 | |
Business Combination, Total Assets | 738,054 | |
Business Combination, Current Liabilities | 5,785 | |
Business Combination, Noncurrent Liabilities | 153 | |
Business Combination, Contingent Consideration, Liability | 52,300 | |
Business Combination, Liabilities | 58,238 | |
Business Combination, Net | $ 679,816 |
Acquisitions and Divestitures_4
Acquisitions and Divestitures (Schedule of Results of Operations) (Table) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Devon Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Business Acquisition, Pro Forma Revenue | $ 1,086,742 | $ 753,474 | |
Business Acquisition, Pro Forma Net Income (Loss) | $ 384,639 | $ 78,118 | |
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ 4.21 | $ 0.94 | |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ 4.13 | $ 0.94 | |
Weighted Average Basic Shares Outstanding, Pro Forma | 91,444 | 82,921 | |
Pro Forma Weighted Average Shares Outstanding, Diluted | 93,077 | 83,493 | |
ExL Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Business Acquisition, Pro Forma Revenue | $ 781,378 | $ 454,913 | |
Business Acquisition, Pro Forma Net Income (Loss) | $ 91,931 | $ (688,180) | |
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ 1.25 | $ (9.11) | |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ 1.24 | $ (9.11) | |
Weighted Average Basic Shares Outstanding, Pro Forma | 73,421 | 75,532 | |
Pro Forma Weighted Average Shares Outstanding, Diluted | 73,993 | 75,532 |
Acquisitions and Divestitures_5
Acquisitions and Divestitures (Schedule of Revenue and Income Since Acquisition Date) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
ExL Acquisition [Member] | |||
Schedule of Revenue of Acquiree Since Acquisition Date [Line Items] | |||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | $ 225,135 | $ 53,548 | |
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | 176,881 | 44,304 | |
Sanchez Acquisition [Member] | |||
Schedule of Revenue of Acquiree Since Acquisition Date [Line Items] | |||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 57,780 | 37,780 | $ 1,459 |
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | $ 38,551 | $ 16,459 | $ 966 |
Property And Equipment, Net (Na
Property And Equipment, Net (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Internal costs capitalized, oil and gas producing activities | $ 17,000 | $ 14,800 | $ 10,500 |
Capitalized interest | 36,600 | 28,300 | 17,000 |
Unproved properties, not being amortized | 673,833 | 660,287 | |
Capitalized costs of unproved properties | 218,900 | 397,700 | 57,200 |
Impairment of proved oil and gas properties | $ 0 | $ 0 | $ 576,540 |
Property And Equipment, Net (Sc
Property And Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Property, Plant and Equipment [Abstract] | ||
Proved properties, net | $ 6,278,321 | $ 5,615,153 |
Accumulated DD&A and impairments | (3,944,851) | (3,649,806) |
Proved properties, net | 2,333,470 | 1,965,347 |
Unproved properties, not being amortized | ||
Unevaluated leasehold and seismic costs | 608,830 | 612,589 |
Capitalized interest | 65,003 | 47,698 |
Total unproved properties, not being amortized | 673,833 | 660,287 |
Other property and equipment | 29,191 | 25,625 |
Accumulated depreciation | (17,970) | (15,449) |
Other property and equipment, net | 11,221 | 10,176 |
Total property and equipment, net | $ 3,018,524 | $ 2,635,810 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 01, 2017 | |
Income Taxes [Line Items] | ||||
U.S. federal statutory corporate pretax rate | 21.00% | 35.00% | ||
Income Tax Rate Reconciliation, US Federal Rate Reduction | $ 0 | $ 211,724,000 | $ 0 | |
Valuation Allowance, Effect Of Tax Cuts And Jobs Act | 211,724,000 | |||
Tax Adjustments, Settlements, and Unusual Provisions | 15,700,000 | |||
Tax Adjustments, Settlements, and Unusual Provisions, Retained Earnings Effect | 0 | |||
Deferred Tax Assets, Valuation Allowance | $ 242,913,000 | $ 333,029,000 | $ 564,434,000 | $ 580,100,000 |
Ownership percentage change | 5.00% | |||
Change in beneficial ownership, percentage | 50.00% | |||
United States Of America [Member] | ||||
Income Taxes [Line Items] | ||||
Operating loss carry forwards subject to expiration | $ 1,062,500,000 |
Income Taxes (Schedule Of Compo
Income Taxes (Schedule Of Components Of Income Tax (Expense) Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current income tax expense | |||
U.S. Federal | $ 0 | $ 0 | $ 0 |
State | (792) | (395) | 0 |
Total current income tax expense | (792) | (395) | 0 |
Deferred income tax expense | |||
U.S. Federal | 0 | 0 | 0 |
State | (4,381) | (3,635) | 0 |
Total deferred income tax expense | (4,381) | (3,635) | 0 |
Income tax expense | $ (5,173) | $ (4,030) | $ 0 |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Income (loss) before income taxes | $ 409,600 | $ 91,140 | $ (675,474) |
Income tax (expense) benefit at the U.S. federal statutory rate | (86,016) | (31,899) | 236,416 |
State income tax (expense) benefit, net of U.S. federal income tax benefit | (5,173) | (4,030) | 3,894 |
Tax deficiencies related to stock-based compensation | (2,572) | (3,089) | 0 |
Provisional impact of Tax Cuts and Jobs Act | 0 | (211,724) | 0 |
Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act | 0 | 211,724 | 0 |
(Increase) decrease in valuation allowance due to current period activity | 90,116 | 35,376 | (240,864) |
Other | (1,528) | (388) | 554 |
Income tax expense | $ (5,173) | $ (4,030) | $ 0 |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 01, 2017 | Dec. 31, 2016 |
Deferred income tax liabilities | ||||
Oil and gas properties | $ (16,610) | $ (3,635) | ||
Derivative assets | (10,008) | (2,140) | ||
Deferred income tax liabilities | (26,618) | (5,775) | ||
Deferred income tax assets | ||||
Net operating loss carryforward - U.S. federal and state | 235,788 | 242,915 | ||
Oil and gas properties | 0 | 50,177 | ||
Asset retirement obligations | 3,927 | 4,996 | ||
Derivative liabilities | 20,165 | 35,585 | ||
Other | 1,634 | 1,496 | ||
Total deferred income tax assets | 261,514 | 335,169 | ||
Deferred income tax asset valuation allowance | (242,913) | (333,029) | $ (580,100) | $ (564,434) |
Net deferred income tax assets | 18,601 | 2,140 | ||
Net deferred income tax asset (liability) | $ (8,017) | $ (3,635) |
Debt (Narrative) (Details)
Debt (Narrative) (Details) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||||||
May 31, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Oct. 28, 2018 | Dec. 31, 2018USD ($)Rate | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Nov. 19, 2018USD ($) | Oct. 29, 2018USD ($) | May 04, 2018USD ($) | May 03, 2018 | Jan. 31, 2018USD ($) | Jul. 14, 2017USD ($) | Apr. 28, 2015 | |
Debt Instrument [Line Items] | ||||||||||||||||
Gains (Losses) on Extinguishment of Debt | $ 8,700 | $ (4,170) | $ (9,586) | $ (4,170) | $ 0 | |||||||||||
Change of control repurchase price percentage | 101.00% | 101.00% | 101.00% | |||||||||||||
Senior Secured Revolving Credit Facility [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Line of credit facility current borrowing base | $ 1,300,000 | $ 1,300,000 | 900,000 | $ 1,300,000 | 900,000 | $ 1,300,000 | $ 1,000,000 | $ 830,000 | ||||||||
Line of Credit Facility, Elected Borrowing Capacity | 1,100,000 | 1,100,000 | 1,100,000 | $ 1,100,000 | $ 900,000 | $ 800,000 | ||||||||||
Line of credit facility amount outstanding | $ 744,431 | $ 744,431 | 291,300 | $ 744,431 | 291,300 | |||||||||||
Debt, Weighted Average Interest Rate | 4.17% | 4.17% | 4.17% | |||||||||||||
Ratio of total debt to EBITDA | 2.41 | |||||||||||||||
Pre-Tax SEC PV10 Reserve Value Percentage | Rate | 90.00% | |||||||||||||||
Federal funds rate plus percentage | 0.50% | 0.50% | 0.50% | |||||||||||||
Adjusted LIBO rate plus percentage | 1.00% | 1.00% | 1.00% | |||||||||||||
Current Ratio | 1.51 | 1.51 | 1.51 | |||||||||||||
Increase To Margin For Eurodollar And Base Rate Loans | 0.25% | |||||||||||||||
Ratio Of Total Debt To EBITDA To Increase Interest Rate | 3 | |||||||||||||||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Current Ratio | 1 | 1 | 1 | |||||||||||||
Margin for eurodollar loans | 2.00% | 1.50% | ||||||||||||||
Margin for base rate loans | 1.00% | 0.50% | ||||||||||||||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Ratio of total debt to EBITDA | 4 | |||||||||||||||
Margin for eurodollar loans | 3.00% | 2.50% | ||||||||||||||
Margin for base rate loans | 2.00% | 1.50% | ||||||||||||||
8.25% Senior Notes [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Aggregate principal amount | $ 250,000 | |||||||||||||||
Debt instrument interest rate | 8.25% | |||||||||||||||
Long-term Debt, Gross | $ 250,000 | $ 250,000 | 250,000 | $ 250,000 | 250,000 | |||||||||||
Proceeds from Issuance of Debt | 245,400 | |||||||||||||||
7.50% Senior Notes [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt instrument interest rate | 7.50% | 7.50% | 7.50% | |||||||||||||
Long-term Debt, Gross | $ 0 | $ 0 | 450,000 | $ 0 | 450,000 | |||||||||||
Debt Instrument, Repurchased Face Amount | $ 320,000 | $ 150,000 | 150,000 | $ 130,000 | ||||||||||||
Redemption Premium | 6,000 | 2,800 | ||||||||||||||
Debt Instrument, Redemption, Cash Consideration | 468,600 | 156,000 | ||||||||||||||
Accrued interest paid associated with redemption of debt | 12,600 | 3,200 | ||||||||||||||
Gains (Losses) on Extinguishment of Debt | (9,586) | (4,170) | ||||||||||||||
Write off of Deferred Debt Issuance Cost | 3,600 | $ 1,400 | ||||||||||||||
Redemption price, percentage of principal amount | 101.875% | 101.875% | 101.875% | 100.00% | ||||||||||||
6.25% Senior Notes [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt instrument interest rate | 6.25% | |||||||||||||||
Long-term Debt, Gross | 650,000 | $ 650,000 | $ 650,000 | 650,000 | $ 650,000 | |||||||||||
6.25% Senior Notes [Member] | On and after April 15, 2018 [Member] | Minimum [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt Instrument, Redemption Price, Percentage | 100.00% | |||||||||||||||
6.25% Senior Notes [Member] | On and after April 15, 2018 [Member] | Maximum [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt Instrument, Redemption Price, Percentage | 104.688% | |||||||||||||||
Other Long Term Debt [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt instrument interest rate | 4.375% | |||||||||||||||
Long-term Debt, Gross | $ 0 | $ 0 | $ 4,425 | $ 0 | $ 4,425 | |||||||||||
Debt Instrument, Redemption, Cash Consideration | $ 4,500 | |||||||||||||||
Accrued interest paid associated with redemption of debt | $ 100 | |||||||||||||||
Redemption price, percentage of principal amount | 100.00% | |||||||||||||||
Prior to July 15, 2020 [Member] | 8.25% Senior Notes [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Redemption price, percentage of principal amount | 100.00% | |||||||||||||||
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Minimum [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Redemption price, percentage of principal amount | 100.00% | |||||||||||||||
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Maximum [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Redemption price, percentage of principal amount | 106.188% | |||||||||||||||
Less than 25 percent [Member] | Senior Secured Revolving Credit Facility [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Line of Credit Facility, Commitment Fee Percentage | 0.375% | |||||||||||||||
Margin for eurodollar loans | 1.25% | |||||||||||||||
Margin for base rate loans | 0.25% | |||||||||||||||
Greater than or equal to 90 percent [Member] | Senior Secured Revolving Credit Facility [Member] | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Line of Credit Facility, Commitment Fee Percentage | 0.50% | |||||||||||||||
Margin for eurodollar loans | 2.25% | |||||||||||||||
Margin for base rate loans | 1.25% |
Debt (Schedule Of Debt) (Detail
Debt (Schedule Of Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Long-term Debt, Excluding Current Maturities | $ 1,633,591 | $ 1,629,209 |
Senior Secured Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Line of credit facility amount outstanding | 744,431 | 291,300 |
7.50% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | 0 | 450,000 |
Debt Instrument, Unamortized Premium | 0 | 579 |
Unamortized Debt Issuance Expense | 0 | (4,492) |
6.25% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | 650,000 | 650,000 |
Unamortized Debt Issuance Expense | (6,878) | (8,208) |
8.25% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | 250,000 | 250,000 |
Unamortized Debt Issuance Expense | (3,962) | (4,395) |
Other Long Term Debt [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | $ 0 | $ 4,425 |
Debt (Interest and Commitment F
Debt (Interest and Commitment Fee Rates) (Details) - Senior Secured Revolving Credit Facility [Member] | 2 Months Ended |
Dec. 31, 2018 | |
Less than 25 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 0.25% |
Margin for eurodollar loans | 1.25% |
Line of Credit Facility, Commitment Fee Percentage | 0.375% |
Greater than or equal to 25 percent but less than 50 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 0.50% |
Margin for eurodollar loans | 1.50% |
Line of Credit Facility, Commitment Fee Percentage | 0.375% |
Greater than or equal to 50 percent but less than 75 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 0.75% |
Margin for eurodollar loans | 1.75% |
Line of Credit Facility, Commitment Fee Percentage | 0.50% |
Greater than or equal to 75 percent but less than 90 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 1.00% |
Margin for eurodollar loans | 2.00% |
Line of Credit Facility, Commitment Fee Percentage | 0.50% |
Greater than or equal to 90 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 1.25% |
Margin for eurodollar loans | 2.25% |
Line of Credit Facility, Commitment Fee Percentage | 0.50% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset retirement obligations, beginning of period | $ 23,792 | $ 21,240 |
Liabilities incurred | 1,676 | 3,920 |
Liabilities settled | 0 | (343) |
Reduction due to sales of oil and gas properties | (8,547) | (2,671) |
Accretion expense | 1,366 | 1,799 |
Revisions to estimated cash flows | 245 | (306) |
Asset retirement obligations, end of period | 18,702 | 23,792 |
Current asset retirement obligations (included in other current liabilities) | (342) | (295) |
Non-current asset retirement obligations | 18,360 | 23,497 |
Eagle Ford Shale Transaction [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities incurred | $ 153 | |
ExL Acquisition [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities incurred | $ 170 |
Commitments and Contingencies_2
Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Commitments [Line Items] | |||
Rent expense | $ 1.4 | $ 1.7 | $ 2 |
Commitments and Contingencies_3
Commitments and Contingencies (Schedule of Contractual Obligations) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Operating leases | |
Less than 1 year | $ 10,024 |
Due in second year | 9,154 |
Due in third year | 6,249 |
Due in fourth year | 3,639 |
Due in fifth year | 3,680 |
More than 5 years | 20,978 |
Total | 53,724 |
Drilling rig contracts | |
Less than 1 year | 37,077 |
Due in second year | 16,867 |
Due in third year | 813 |
Due in fourth year | 0 |
Due in fifth year | 0 |
More than 5 years | 0 |
Total | 54,757 |
Delivery commitments | |
Less than 1 year | 3,726 |
Due in second year | 2,807 |
Due in third year | 2,487 |
Due in fourth year | 30 |
Due in fifth year | 7 |
More than 5 years | 19 |
Total | 9,076 |
Produced water disposal commitments | |
Less than 1 year | 18,139 |
Due in second year | 20,894 |
Due in third year | 20,898 |
Due in fourth year | 20,954 |
Due in fifth year | 10,471 |
More than 5 years | 9,769 |
Total | 101,125 |
Other | |
Less than 1 year | 1,800 |
Due in second year | 1,050 |
Due in third year | 0 |
Due in fourth year | 0 |
Due in fifth year | 0 |
More than 5 years | 0 |
Total | 2,850 |
Total | |
Less than 1 year | 70,766 |
Due in second year | 50,772 |
Due in third year | 30,447 |
Due in fourth year | 24,623 |
Due in fifth year | 14,158 |
More than 5 years | 30,766 |
Total | $ 221,532 |
Preferred Stock (Narrative) (De
Preferred Stock (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Mar. 31, 2018 | Sep. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 24, 2018 | Aug. 10, 2017 | |
Preferred Stock Disclosure [Line Items] | |||||||
Temporary Equity, Par Value | $ 250,000,000 | ||||||
Temporary Equity, Shares Issued | 200,000 | 250,000 | 250,000 | ||||
Preferred Stock, Dividend Rate, Percentage | 8.875% | ||||||
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 | $ 0.01 | ||||
Issuance of warrants to purchase common stock | 2,750,000 | ||||||
Class of Warrant or Right Term | 10 years | ||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 16.08 | 16.08 | |||||
Cash Purchase Price Per Share of Preferred Stock | $ 970 | ||||||
Sale of preferred stock, net of issuance costs | $ 236,404,000 | $ 0 | $ 236,404,000 | $ 0 | |||
Maximum Preferred Stock Shares Redeemable Within the First Year | 50,000 | ||||||
Temporary Equity, Liquidation Preference Per Share | $ 1,000 | ||||||
Preferred Stock Shares Redeemed | 50,000 | ||||||
Preferred Stock, Percentage Redeemed | 20.00% | ||||||
Payments for Repurchase of Redeemable Preferred Stock | $ 50,500,000 | ||||||
Preferred Stock, Redemption Premium, Percentage | 104.4375% | ||||||
Preferred Stock, Percent of Ownership to be Able to Vote | 50.00% | ||||||
Preferred Stock, Prohibited Distributions | $ 15,000,000 | ||||||
Proceeds from Issuance of Preferred Stock and Preference Stock | 213,400,000 | ||||||
Proceeds from Issuance of Warrants | $ 23,000,000 | 23,003,000 | |||||
Dividends on preferred stock | (18,161,000) | (7,781,000) | 0 | ||||
Accretion on preferred stock | (3,057,000) | (862,000) | 0 | ||||
Redemption Price Of Preferred Stock | 50,030,000 | ||||||
Payments Of Accrued Dividends Upon Redemption Of Preferred Stock | 500,000 | ||||||
Gain (Loss) On Redemption Of Preferred Stock | $ 7,100,000 | (7,133,000) | 0 | $ 0 | |||
Redemption Of Preferred Stock | $ (42,897,000) | $ 0 | |||||
On or before the seventh anniversary of the Preferred Stock Issuance Date [Domain] | |||||||
Preferred Stock Disclosure [Line Items] | |||||||
Preferred Stock, Dividend Rate, Percentage | 12.00% | ||||||
After August 10, 2024 [Domain] | |||||||
Preferred Stock Disclosure [Line Items] | |||||||
Preferred Stock, Dividend Rate, Percentage | 12.00% | ||||||
Libor Rate to Calculate Preferred Stock Dividend Rate | 10.00% |
Preferred Stock (Warrants Valua
Preferred Stock (Warrants Valuation Assumptions) (Details) - $ / shares | 3 Months Ended | |
Sep. 30, 2017 | Aug. 10, 2017 | |
Temporary Equity Disclosure [Abstract] | ||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 16.08 | $ 16.08 |
Class of Warrant or Right, Expected Term | 10 years | |
Class of Warrant or Right, Expected Volatility Rate | 62.90% | |
Class of Warrant or Right, Risk Free Interest Rate | 2.20% | |
Class of Warrant or Right, Expected Dividend Rate | 0.00% |
Preferred Stock (Schedule of Pr
Preferred Stock (Schedule of Preferred Stock Activity) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Preferred Stock Activity [Abstract] | |||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | $ 174,422,000 | $ 214,262,000 | $ 0 |
Temporary Equity, Stock Issued During Period, Value, New Issues | 0 | 213,400,000 | |
Redemption Of Preferred Stock | (42,897,000) | 0 | |
Accretion on preferred stock | $ (3,057,000) | $ (862,000) | $ 0 |
Preferred Stock (Schedule of Di
Preferred Stock (Schedule of Dividends Paid in Common Stock) (Details) | Dec. 31, 2018Rate |
Preferred Stock Dividend Paid in Common Stock Second Year [Member] | |
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items] | |
Percent of Dividend Payable in Common Stock | 75.00% |
Preferred Stock Dividend Paid in Common Stock Third Year [Member] | |
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items] | |
Percent of Dividend Payable in Common Stock | 50.00% |
Preferred Stock (Schedule of _2
Preferred Stock (Schedule of Preferred Stock Redemption Premiums) (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Schedule of Preferred Stock Redemption Premiums [Line Items] | |
Preferred Stock, Redemption Premium, Percentage | 104.4375% |
Preferred Stock Redemption Fourth Year [Member] | |
Schedule of Preferred Stock Redemption Premiums [Line Items] | |
Preferred Stock, Redemption Premium, Percentage | 104.4375% |
Preferred Stock Redemption Fifth Year [Member] [Member] | |
Schedule of Preferred Stock Redemption Premiums [Line Items] | |
Preferred Stock, Redemption Premium, Percentage | 102.21875% |
Preferred Stock Redemption Sixth Year [Member] | |
Schedule of Preferred Stock Redemption Premiums [Line Items] | |
Preferred Stock, Redemption Premium, Percentage | 100.00% |
Shareholder's Equity (Details)
Shareholder's Equity (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 17, 2018 | Jul. 03, 2017 | Oct. 28, 2016 | |
Shareholder's Equity [Abstract] | ||||||
Common stock, shares authorized (in shares) | 180,000,000 | 180,000,000 | 90,000,000 | |||
Sale of common stock, shares | 9,500,000 | 15,600,000 | 6,000,000 | |||
Sale of Stock, Price Per Share | $ 22.55 | $ 14.28 | $ 37.32 | |||
Sale of common stock, net of offering costs | $ 213,746 | $ 222,378 | $ 223,739 |
Stock-based Compensation (Narra
Stock-based Compensation (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | May 16, 2017 | |
Employee Stock Option [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Ratio Of Stock Based Compensation Shares to Common Shares | 1 | |||||
Restricted Stock Awards And Units [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Ratio Of Stock Based Compensation Shares to Common Shares | 1.35 | |||||
Compensation cost not yet recognized | $ 23.2 | |||||
Compensation cost not yet recognized, period for recognition | 1 year 10 months 13 days | |||||
Aggregate Intrinsic Value, Vested | $ 10.2 | $ 20.3 | $ 26.3 | |||
Vested Shares/Units | (621,399) | (635,965) | (811,136) | |||
Cash Settled Stock Appreciation Rights Plan [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Vesting period, in years | 3 years | 2 years | 2 years | |||
Compensation cost not yet recognized | $ 2.4 | |||||
Compensation cost not yet recognized, period for recognition | 2 years 2 months 8 days | |||||
Expiration period, in years | 7 years | 5 years | 5 years | |||
Stock Issued During Period, Value, Gross | $ 4.9 | $ 4.1 | $ 3.7 | |||
Performance Shares [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Vesting period, in years | 3 years | |||||
Compensation cost not yet recognized | $ 2.1 | |||||
Compensation cost not yet recognized, period for recognition | 1 year 9 months 14 days | |||||
Aggregate Intrinsic Value, Vested | $ 0.8 | 2.6 | ||||
Stock Issued During Period, Value, Gross | $ 1.8 | $ 1.6 | $ 1.5 | |||
Vesting Percentage Of Target Performance Shares Granted | 88.00% | 164.00% | ||||
Share based Compensation Arrangements by Share Based Payment Award, Target Shares | 56,517 | 56,342 | ||||
Unearned Shares due to Market Condition | 7,059 | 7,059 | ||||
Vested Shares/Units | (49,458) | (92,200) | (49,458) | (56,342) | 0 | |
Minimum [Member] | Restricted Stock Awards And Units [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Vesting period, in years | 1 year | |||||
Maximum [Member] | Restricted Stock Awards And Units [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Vesting period, in years | 3 years | |||||
2017 Incentive Plan [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Maximum issuance of grant awards under Incentive Plan | 2,675,000 | |||||
Number of Shares Available for Grant | 258,785 | |||||
Other Current Liabilities [Member] | Cash Settled Stock Appreciation Rights Plan [Member] | ||||||
Share-based Compensation [Line Items] | ||||||
Liability for cash stock appreciation rights | $ 1.8 | $ 4.4 |
Stock-based Compensation (Summa
Stock-based Compensation (Summary Of Restricted Stock Award And Unit Activity) (Details) - Restricted Stock Awards And Units [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted Stock Awards and Units | |||
Unvested Shares/Units, Beginning of Period | 1,482,655 | 1,111,710 | 1,041,997 |
Granted Shares/Units | 1,458,421 | 1,020,465 | 887,254 |
Vested Shares/Units | (621,399) | (635,965) | (811,136) |
Forfeited Shares/Units | (53,010) | (13,555) | (6,405) |
Unvested Shares/Units, End of Period | 2,266,667 | 1,482,655 | 1,111,710 |
Weighted Average Grant Date Fair Value | |||
Grant-date Fair Value, Beginning of Period (USD per share) | $ 28.07 | $ 36.93 | $ 44.22 |
Granted, Grant-date Fair Value (USD per share) | 15.49 | 25.63 | 27.80 |
Vested, Grant-date Fair Value (USD per share) | 31.48 | 39.62 | 36.32 |
Forfeited, Grant-date Fair Value (USD per share) | 17.72 | 29.11 | 34.46 |
Grant-date Fair Value, End of Period (USD per share) | $ 19.28 | $ 28.07 | $ 36.93 |
Stock-based Compensation (Sum_2
Stock-based Compensation (Summary of SARs Activity) (Details) - Cash Settled Stock Appreciation Rights Plan [Member] - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |||
SARs, Outstanding, beginning of period | 714,238 | 722,638 | 700,453 |
SARs, Granted | 616,686 | 342,440 | 376,260 |
SARs, Exercised | 0 | (219,279) | (354,075) |
SARs, Forfeitures | 0 | 0 | 0 |
SARs, Expired | 0 | (131,561) | 0 |
SARs, Outstanding, end of period | 1,330,924 | 714,238 | 722,638 |
SARS, Vested, end of period | 543,018 | 185,899 | 350,840 |
SARs, Exercisable, end of period | 0 | 0 | 350,840 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Weighted Average Exercise Price [Roll Forward] | |||
Weighted Average Exercise Prices, Outstanding, Beginning of Period | $ 27.12 | $ 23.69 | $ 21.86 |
Weighted Average Exercise Prices, Granted | 14.67 | 26.94 | 27.30 |
Weighted Average Exercise Prices, Exercised | 0 | 17.28 | 23.89 |
Weighted Average Exercise Prices, Forfeitures | 0 | 0 | 0 |
Weighted Average Exercise Prices, Expired (USD per share) | 0 | 24.19 | 0 |
Weighted Average Exercise Prices, Outstanding, End of Period | 21.35 | 27.12 | 23.69 |
Weighted Average Exercise Prices, Vested, End of Period | 27.18 | 27.30 | 19.87 |
Weighted Average Exercise Prices, Exercisable, End of Period | $ 27.18 | $ 27.30 | $ 19.87 |
Cash paid at exercises, Stock Appreciation Rights | $ 0 | $ 2.1 | $ 5.2 |
Weighted Average Remaining Life, Outstanding, End of Period | 4 years 3 months 29 days | ||
Weighted Average Remaining Life, Exercisable, End of Period | 2 years 6 months 9 days | ||
Aggregate Intrinsic Value, Outstanding, End of Period | $ 0 | ||
Aggregate Intrinsic Value, Exercisable, End of Period | $ 0 |
Stock-based Compensation (Sum_3
Stock-based Compensation (Summary of Stock Appreciation Rights Fair Value Assumptions) (Details) - Cash Settled Stock Appreciation Rights Plan [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation [Line Items] | |||
Expected Term | 6 years | 4 years 2 months 6 days | 3 years 11 months 5 days |
Expected volatility | 54.30% | 54.30% | 45.10% |
Risk-free interest rate | 2.80% | 1.80% | 1.30% |
Dividend yield | 0.00% | 0.00% | 0.00% |
Grant date fair value per Cash SAR | $ 7.89 | $ 12 | $ 9.88 |
Stock-based Compensation (Sum_4
Stock-based Compensation (Summary of Performance Share Award Activity) (Details) - Performance Shares [Member] - $ / shares | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Target Performance Shares (1) | |||||
Unvested Shares/Units, Beginning of Period | 144,955 | 154,510 | 144,955 | 154,510 | 112,859 |
Granted Shares/Units | 93,771 | 46,787 | 41,651 | ||
Vested Shares/Units | (49,458) | (92,200) | (49,458) | (56,342) | 0 |
Unearned Shares due to Market Condition | (7,059) | (7,059) | |||
Forfeited Shares/Units | 0 | 0 | 0 | ||
Unvested Shares/Units, End of Period | 182,209 | 144,955 | 154,510 | ||
Weighted Average Grant Date Fair Value | |||||
Grant-date Fair Value, Beginning of Period (USD per share) | $ 47.14 | $ 58.44 | $ 47.14 | $ 58.44 | $ 66.83 |
Granted, Grant-date Fair Value (USD per share) | 19.09 | 35.14 | 35.71 | ||
Vested, Grant-date Fair Value (USD per share) | 65.51 | 68.15 | 0 | ||
Unearned Shares due to Market Condition, Weighted Average Grant Date Fair Value | 65.51 | ||||
Forfeited, Grant-date Fair Value (USD per share) | 0 | 0 | 0 | ||
Grant-date Fair Value, End of Period (USD per share) | $ 27.01 | $ 47.14 | $ 58.44 |
Stock-based Compensation (Sum_5
Stock-based Compensation (Summary of Performance Share Awards Fair Value Assumptions) (Details) - Performance Shares [Member] | 12 Months Ended | ||
Dec. 31, 2018$ / sharesRate | Dec. 31, 2017$ / sharesRate | Dec. 31, 2016$ / sharesRate | |
Number of simulations | 500,000 | 500,000 | 500,000 |
Expected Term | 3 years 6 days | 2 years 11 months 23 days | 3 years 2 days |
Expected volatility | 61.50% | 59.20% | 55.30% |
Risk-free interest rate | 2.40% | 1.50% | 1.20% |
Dividend yield | 0.00% | 0.00% | 0.00% |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | $ 19.09 | $ 35.14 | $ 35.71 |
Stock-based Compensation (Stock
Stock-based Compensation (Stock-Based Compensation Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | $ 17,648 | $ 18,791 | $ 40,677 |
Less: amounts capitalized | (4,124) | (4,482) | (4,591) |
Total stock-based compensation expense | 13,524 | 14,309 | 36,086 |
Restricted Stock Awards And Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | 18,434 | 21,372 | 28,196 |
Stock Appreciation Rights (SARs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | (2,571) | (5,023) | 9,675 |
Performance Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | $ 1,785 | $ 2,442 | $ 2,806 |
Derivative Instruments (Schedul
Derivative Instruments (Schedule of Crude Oil Derivative Positions) (Details) - Crude Oil [Member] | Dec. 31, 2018bbl / d$ / bbls |
Three-way Collars [Member] | 1Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 27,000 |
Derivative Average Sub Floor Price | 41.67 |
Weighted Average Floor Price ($/Bbl) | 50.96 |
Weighted Average Ceiling Price ($/Bbl) | 74.23 |
Three-way Collars [Member] | 2Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 27,000 |
Derivative Average Sub Floor Price | 41.67 |
Weighted Average Floor Price ($/Bbl) | 50.96 |
Weighted Average Ceiling Price ($/Bbl) | 74.23 |
Three-way Collars [Member] | 3Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 27,000 |
Derivative Average Sub Floor Price | 41.67 |
Weighted Average Floor Price ($/Bbl) | 50.96 |
Weighted Average Ceiling Price ($/Bbl) | 74.23 |
Three-way Collars [Member] | 4Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 27,000 |
Derivative Average Sub Floor Price | 41.67 |
Weighted Average Floor Price ($/Bbl) | 50.96 |
Weighted Average Ceiling Price ($/Bbl) | 74.23 |
Sold Call Options [Member] | 1Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 3,875 |
Weighted Average Ceiling Price ($/Bbl) | 81.07 |
Sold Call Options [Member] | 2Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 3,875 |
Weighted Average Ceiling Price ($/Bbl) | 81.07 |
Sold Call Options [Member] | 3Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 3,875 |
Weighted Average Ceiling Price ($/Bbl) | 81.07 |
Sold Call Options [Member] | 4Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 3,875 |
Weighted Average Ceiling Price ($/Bbl) | 81.07 |
Sold Call Options [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 4,575 |
Weighted Average Ceiling Price ($/Bbl) | 75.98 |
LLS-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 1Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 6,000 |
Weighted Average Fixed Price | (5.16) |
LLS-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 2Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 6,000 |
Weighted Average Fixed Price | (5.16) |
LLS-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 3Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 6,000 |
Weighted Average Fixed Price | (5.16) |
LLS-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 4Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 6,000 |
Weighted Average Fixed Price | (5.16) |
WTI Midland-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 1Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 5,500 |
Weighted Average Fixed Price | (5.24) |
WTI Midland-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 2Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 6,000 |
Weighted Average Fixed Price | (5.38) |
WTI Midland-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 3Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 7,000 |
Weighted Average Fixed Price | (5.56) |
WTI Midland-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 4Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 11,000 |
Weighted Average Fixed Price | (3.84) |
WTI Midland-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 13,000 |
Weighted Average Fixed Price | (1.27) |
WTI Midland-WTI Cushing Price Differential [Member] | Basis Swap [Member] | 2021 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | bbl / d | 6,000 |
Weighted Average Fixed Price | (0.03) |
Derivative Instruments (Sched_2
Derivative Instruments (Schedule of Natural Gas Derivative Positions) (Details) - Natural Gas [Member] - Call Option [Member] | Dec. 31, 2018MMBTU / d$ / MMBTU |
1Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.25 |
2Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.25 |
3Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.25 |
4Q 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.25 |
2020 [Member] | |
Derivative [Line Items] | |
Derivative, Volumes | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.50 |
Derivative Instruments (Sched_3
Derivative Instruments (Schedule of Contingent Consideration) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($)$ / bbls$ / MMBTU | |
ExL Acquisition [Member] | |
Embedded Derivative [Line Items] | |
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High | $ 125,000 |
Marcellus Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High | $ 7,500 |
2018 [Member] | ExL Acquisition [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls | 50 |
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition | $ (50,000) |
2018 [Member] | Niobrara Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls | 55 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 5,000 |
2018 [Member] | Marcellus Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU | 3.13 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 3,000 |
2018 [Member] | Utica Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls | 50 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 5,000 |
2019 [Member] | ExL Acquisition [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls | 50 |
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition | $ (50,000) |
2019 [Member] | Niobrara Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls | 55 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 5,000 |
2019 [Member] | Marcellus Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU | 3.18 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 3,000 |
2019 [Member] | Utica Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls | 53 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 5,000 |
2020 [Member] | ExL Acquisition [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls | 50 |
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition | $ (50,000) |
2020 [Member] | Niobrara Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls | 60 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 5,000 |
2020 [Member] | Marcellus Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU | 3.30 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 3,000 |
2020 [Member] | Utica Shale Divestiture [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls | 56 |
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture | $ 5,000 |
2021 [Member] | ExL Acquisition [Member] | |
Embedded Derivative [Line Items] | |
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls | 50 |
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition | $ (50,000) |
Derivative Instruments (Sched_4
Derivative Instruments (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Current | $ 39,904 | $ 0 |
Derivative Liability, Current | (55,205) | (57,121) |
Derivative Liability, Noncurrent | (40,817) | (112,332) |
Other Current Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 50,406 | 4,869 |
Derivative Asset, Fair Value, Gross Liability | (20,502) | (4,869) |
Derivative Assets (Liabilities), at Fair Value, Net | 29,904 | 0 |
Derivative Asset, Current | 39,904 | 0 |
Derivative Asset, Gross Asset | 60,406 | 4,869 |
Derivative Asset, Gross Liability | (20,502) | (4,869) |
Other Noncurrent Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 6,083 | 9,505 |
Derivative Asset, Fair Value, Gross Liability | (4,236) | (9,505) |
Derivative Assets (Liabilities), at Fair Value, Net | 1,847 | 0 |
Derivative Asset, Gross Asset | 11,988 | 19,695 |
Derivative Asset, Gross Liability | (4,236) | (9,505) |
Derivative Asset, Noncurrent | 7,752 | 10,190 |
Other Current Liabilities [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (5,205) | (57,121) |
Derivative Liability, Fair Value, Gross Liability | (15,345) | (52,671) |
Derivative Liability, Fair Value, Gross Asset | 10,140 | (4,450) |
Derivative Deferred Premium, Net | 0 | 0 |
Derivative Liability, Deferred Premiums, Gross Liability | (10,362) | (9,319) |
Derivative Liability, Deferred Premiums, Gross Asset | 10,362 | 9,319 |
Derivative Liability, Gross Liability | (75,707) | (61,990) |
Derivative Liability, Gross Asset | 20,502 | 4,869 |
Derivative Liability, Current | (55,205) | (57,121) |
Other Noncurrent Liabilities [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (10,233) | (26,707) |
Derivative Liability, Fair Value, Gross Liability | (10,751) | (24,609) |
Derivative Liability, Fair Value, Gross Asset | 518 | (2,098) |
Derivative Deferred Premium, Net | 0 | 0 |
Derivative Liability, Deferred Premiums, Gross Liability | (3,718) | (11,603) |
Derivative Liability, Deferred Premiums, Gross Asset | 3,718 | 11,603 |
Derivative Liability, Gross Liability | (45,053) | (121,837) |
Derivative Liability, Gross Asset | 4,236 | 9,505 |
Derivative Liability, Noncurrent | (40,817) | (112,332) |
Niobrara Divestiture [Member] | Other Current Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Contingent Payment, Gross Asset | 5,000 | |
Derivative Asset, Contingent Payment, Gross Liability | 0 | |
Business Combination, Contingent Consideration, Asset, Current | 5,000 | |
Niobrara Divestiture [Member] | Other Noncurrent Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Contingent Payment, Gross Asset | 2,035 | |
Derivative Asset, Contingent Payment, Gross Liability | 0 | |
Business Combination, Contingent Consideration, Asset, Noncurrent | 2,035 | |
Marcellus Shale Divestiture [Member] | Other Noncurrent Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Contingent Payment, Gross Asset | 1,369 | 2,205 |
Derivative Asset, Contingent Payment, Gross Liability | 0 | 0 |
Business Combination, Contingent Consideration, Asset, Noncurrent | 1,369 | 2,205 |
Utica Shale Divestiture [Member] | Other Current Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Contingent Payment, Gross Asset | 5,000 | |
Derivative Asset, Contingent Payment, Gross Liability | 0 | |
Business Combination, Contingent Consideration, Asset, Current | 5,000 | |
Utica Shale Divestiture [Member] | Other Noncurrent Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Contingent Payment, Gross Asset | 2,501 | 7,985 |
Derivative Asset, Contingent Payment, Gross Liability | 0 | 0 |
Business Combination, Contingent Consideration, Asset, Noncurrent | 2,501 | 7,985 |
ExL Acquisition [Member] | Other Current Liabilities [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability, Contingent Payment, Gross Liability | (50,000) | |
Derivative Liability, Contingent Payment, Gross Asset | 0 | |
Business Combination, Contingent Consideration, Liability, Current | (50,000) | |
ExL Acquisition [Member] | Other Noncurrent Liabilities [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability, Contingent Payment, Gross Liability | (30,584) | (85,625) |
Derivative Liability, Contingent Payment, Gross Asset | 0 | 0 |
Business Combination, Contingent Consideration, Liability, Noncurrent | $ (30,584) | $ (85,625) |
Derivative Instruments (Sched_5
Derivative Instruments (Schedule of (Gain) Loss on Derivative Instruments) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
(Gain) loss on derivatives, net | $ (159,407) | $ 55,388 | $ 67,714 | $ 29,596 | $ 86,107 | $ 24,377 | $ (26,065) | $ (25,316) | $ (6,709) | $ 59,103 | $ 49,073 |
Crude Oil [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
(Gain) loss on derivatives, net | (9,726) | 22,839 | 23,609 | ||||||||
Natural Gas Liquids | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
(Gain) loss on derivatives, net | 4,439 | 1,322 | 0 | ||||||||
Natural Gas [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
(Gain) loss on derivatives, net | (421) | (15,399) | 19,584 | ||||||||
Deferred Premiums On Derivative Instruments [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
(Gain) loss on derivatives, net | 1,875 | 18,401 | 5,880 | ||||||||
ExL Acquisition [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net | (5,041) | 33,325 | 0 | ||||||||
Niobrara Divestiture [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net | 845 | 0 | 0 | ||||||||
Marcellus Shale Divestiture [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net | 836 | 455 | 0 | ||||||||
Utica Shale Divestiture [Member] | |||||||||||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||||||||||
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net | $ 484 | $ (1,840) | $ 0 |
Derivative Instruments (Sched_6
Derivative Instruments (Schedule of Cash Received for Derivative Settlements) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule Of Cash Received For Derivatives [Line Items] | |||
Net Cash Received Paid For Derivative Settlements | $ (96,307) | $ 7,773 | $ 119,369 |
Crude Oil [Member] | |||
Schedule Of Cash Received For Derivatives [Line Items] | |||
Net Cash Received Paid For Derivative Settlements | (78,570) | 9,883 | 125,098 |
Natural Gas Liquids | |||
Schedule Of Cash Received For Derivatives [Line Items] | |||
Net Cash Received Paid For Derivative Settlements | (6,378) | 0 | 0 |
Natural Gas [Member] | |||
Schedule Of Cash Received For Derivatives [Line Items] | |||
Net Cash Received Paid For Derivative Settlements | (1,710) | (54) | 0 |
Deferred Premiums On Derivative Instruments [Member] | |||
Schedule Of Cash Received For Derivatives [Line Items] | |||
Net Cash Received Paid For Derivative Settlements | $ (9,649) | $ (2,056) | $ (5,729) |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 0 | $ 0 |
Derivative Liability | 0 | 0 |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 31,751 | 0 |
Derivative Liability | (15,438) | (83,828) |
Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Niobrara Divestiture [Member] | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Niobrara Divestiture [Member] | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 7,035 | 0 |
Niobrara Divestiture [Member] | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Marcellus Shale Divestiture [Member] | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Marcellus Shale Divestiture [Member] | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 1,369 | 0 |
Marcellus Shale Divestiture [Member] | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 2,205 |
Utica Shale Divestiture [Member] | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Utica Shale Divestiture [Member] | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 7,501 | 0 |
Utica Shale Divestiture [Member] | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 7,985 |
ExL Acquisition [Member] | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 0 | 0 |
ExL Acquisition [Member] | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | (80,584) | 0 |
ExL Acquisition [Member] | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | $ 0 | $ (85,625) |
Fair Value Measurements (Sche_2
Fair Value Measurements (Schedule of Assets and Liabilities, Level 3 Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |||
Contingent Consideration, Fair Value, Asset Value | $ 0 | $ 10,190 | $ 0 |
Fair Value, Asset, Issuances | 7,880 | 8,805 | |
Fair Value, Asset, Gain (Loss) Included in Earnings | (2,165) | 1,385 | |
Fair Value, Asset Transfers out of Level 3 | (15,905) | ||
Fair Value, Asset Transfers Into Level 3 | 0 | ||
Contingent Consideration, Fair Value, Liability Value | 0 | (85,625) | $ 0 |
Fair Value, Liability, Issuances | 0 | (52,300) | |
Fair Value, Liability, Gain (Loss) Included in Earnings | 5,041 | (33,325) | |
Fair Value, Liability Transfers out of Level 3 | $ 80,584 | ||
Fair Value, Liability, Transfers Into Level 3 | $ 0 |
Fair Value Measurements (Sche_3
Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
7.50% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | $ 0 | $ 450,000 |
8.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 250,000 | 250,000 |
Other Long Term Debt [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 0 | 4,425 |
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 7.50% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 0 | 450,000 |
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 6.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 650,000 | 650,000 |
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 8.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 250,000 | 250,000 |
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Other Long Term Debt [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 0 | 4,425 |
Estimate of Fair Value Measurement [Member] | 7.50% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 0 | 459,518 |
Estimate of Fair Value Measurement [Member] | 6.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 599,625 | 674,375 |
Estimate of Fair Value Measurement [Member] | 8.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 244,375 | 274,375 |
Estimate of Fair Value Measurement [Member] | Other Long Term Debt [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | $ 0 | $ 4,445 |
Condensed Consolidating Finan_3
Condensed Consolidating Financial Information (Narrative) (Details) | Dec. 31, 2018 |
Condensed Consolidating Financial Information [Abstract] | |
Voting interest of the subsidiary owned by the registrant | 100.00% |
Condensed Consolidating Finan_4
Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Total current assets | $ 150,369,000 | $ 122,878,000 | ||
Total property and equipment, net | 3,018,524,000 | 2,635,810,000 | ||
Investment in subsidiaries | 0 | 0 | ||
Other long-term assets | 16,207,000 | 19,616,000 | ||
Total Assets | 3,185,100,000 | 2,778,304,000 | ||
Current Liabilities | 322,009,000 | 372,822,000 | ||
Long-term liabilities | 1,707,765,000 | 1,820,323,000 | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | 174,422,000 | 214,262,000 | $ 0 | |
Total shareholders’ equity | 980,904,000 | 370,897,000 | $ 23,458,000 | $ 444,054,000 |
Total Liabilities and Shareholders’ Equity | 3,185,100,000 | 2,778,304,000 | ||
Reportable Legal Entities [Member] | Parent Company [Member] | ||||
Total current assets | 3,341,680,000 | 3,441,633,000 | ||
Total property and equipment, net | 7,951,000 | 5,953,000 | ||
Investment in subsidiaries | (419,159,000) | (999,793,000) | ||
Other long-term assets | 28,124,000 | 9,270,000 | ||
Total Assets | 2,958,596,000 | 2,457,063,000 | ||
Current Liabilities | 135,980,000 | 165,701,000 | ||
Long-term liabilities | 1,650,589,000 | 1,689,466,000 | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | 174,422,000 | 214,262,000 | ||
Total shareholders’ equity | 997,605,000 | 387,634,000 | ||
Total Liabilities and Shareholders’ Equity | 2,958,596,000 | 2,457,063,000 | ||
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member] | ||||
Total current assets | 114,005,000 | 105,533,000 | ||
Total property and equipment, net | 3,011,387,000 | 2,630,707,000 | ||
Investment in subsidiaries | 0 | 0 | ||
Other long-term assets | 5,906,000 | 10,346,000 | ||
Total Assets | 3,131,298,000 | 2,746,586,000 | ||
Current Liabilities | 3,491,337,000 | 3,631,401,000 | ||
Long-term liabilities | 59,120,000 | 114,978,000 | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | 0 | 0 | ||
Total shareholders’ equity | (419,159,000) | (999,793,000) | ||
Total Liabilities and Shareholders’ Equity | 3,131,298,000 | 2,746,586,000 | ||
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member] | ||||
Total current assets | 0 | 0 | ||
Total property and equipment, net | 3,028,000 | 3,028,000 | ||
Investment in subsidiaries | 0 | 0 | ||
Other long-term assets | 0 | 0 | ||
Total Assets | 3,028,000 | 3,028,000 | ||
Current Liabilities | 3,028,000 | 3,028,000 | ||
Long-term liabilities | 0 | 0 | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | 0 | 0 | ||
Total shareholders’ equity | 0 | 0 | ||
Total Liabilities and Shareholders’ Equity | 3,028,000 | 3,028,000 | ||
Consolidation, Eliminations [Member] | ||||
Total current assets | (3,305,316,000) | (3,424,288,000) | ||
Total property and equipment, net | (3,842,000) | (3,878,000) | ||
Investment in subsidiaries | 419,159,000 | 999,793,000 | ||
Other long-term assets | (17,823,000) | 0 | ||
Total Assets | (2,907,822,000) | (2,428,373,000) | ||
Current Liabilities | (3,308,336,000) | (3,427,308,000) | ||
Long-term liabilities | (1,944,000) | 15,879,000 | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of December 31, 2018 and 250,000 issued and outstanding as of December 31, 2017 | 0 | 0 | ||
Total shareholders’ equity | 402,458,000 | 983,056,000 | ||
Total Liabilities and Shareholders’ Equity | $ (2,907,822,000) | $ (2,428,373,000) |
Condensed Consolidating Finan_5
Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Total revenues | $ 273,314,000 | $ 303,375,000 | $ 263,973,000 | $ 225,280,000 | $ 246,771,000 | $ 181,279,000 | $ 166,483,000 | $ 151,355,000 | $ 1,065,942,000 | $ 745,888,000 | $ 443,594,000 |
Total costs and expenses | 656,342,000 | 654,748,000 | 1,119,068,000 | ||||||||
Income (loss) from continuing operations before income taxes | 409,600,000 | 91,140,000 | (675,474,000) | ||||||||
Operating income (loss) | 129,405,000 | 165,141,000 | 140,265,000 | 108,992,000 | 113,205,000 | 69,364,000 | 63,147,000 | 57,953,000 | |||
Income tax expense | (5,173,000) | (4,030,000) | 0 | ||||||||
Equity in income of subsidiaries | 0 | 0 | 0 | ||||||||
Net Income (Loss) | 260,280,000 | 81,346,000 | 35,309,000 | 27,492,000 | (17,040,000) | 7,823,000 | 56,306,000 | 40,021,000 | 404,427,000 | 87,110,000 | (675,474,000) |
Dividends on preferred stock | (18,161,000) | (7,781,000) | 0 | ||||||||
Accretion on preferred stock | (3,057,000) | (862,000) | 0 | ||||||||
Gain (Loss) On Redemption Of Preferred Stock | 7,100,000 | (7,133,000) | 0 | 0 | |||||||
Net Income (Loss) Attributable to Common Shareholders | $ 255,120,000 | $ 76,118,000 | $ 30,095,000 | $ 14,743,000 | $ (23,434,000) | $ 5,574,000 | $ 56,306,000 | $ 40,021,000 | 376,076,000 | 78,467,000 | (675,474,000) |
Reportable Legal Entities [Member] | Parent Company [Member] | |||||||||||
Total revenues | 162,000 | 302,000 | 482,000 | ||||||||
Costs and Expenses | 176,406,000 | 195,728,000 | 208,054,000 | ||||||||
Income (loss) from continuing operations before income taxes | (176,244,000) | (195,426,000) | (207,572,000) | ||||||||
Income tax expense | 0 | 0 | 0 | ||||||||
Equity in income of subsidiaries | 580,634,000 | 282,499,000 | (467,410,000) | ||||||||
Net Income (Loss) | 404,390,000 | 87,073,000 | (674,982,000) | ||||||||
Dividends on preferred stock | (18,161,000) | (7,781,000) | 0 | ||||||||
Accretion on preferred stock | (3,057,000) | (862,000) | 0 | ||||||||
Gain (Loss) On Redemption Of Preferred Stock | (7,133,000) | 0 | 0 | ||||||||
Net Income (Loss) Attributable to Common Shareholders | 376,039,000 | 78,430,000 | (674,982,000) | ||||||||
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member] | |||||||||||
Total revenues | 1,065,780,000 | 745,586,000 | 443,112,000 | ||||||||
Costs and Expenses | 479,973,000 | 459,057,000 | 910,522,000 | ||||||||
Income (loss) from continuing operations before income taxes | 585,807,000 | 286,529,000 | (467,410,000) | ||||||||
Income tax expense | (5,173,000) | (4,030,000) | 0 | ||||||||
Equity in income of subsidiaries | 0 | 0 | 0 | ||||||||
Net Income (Loss) | 580,634,000 | 282,499,000 | (467,410,000) | ||||||||
Dividends on preferred stock | 0 | 0 | 0 | ||||||||
Accretion on preferred stock | 0 | 0 | 0 | ||||||||
Gain (Loss) On Redemption Of Preferred Stock | 0 | 0 | 0 | ||||||||
Net Income (Loss) Attributable to Common Shareholders | 580,634,000 | 282,499,000 | (467,410,000) | ||||||||
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
Costs and Expenses | 0 | 0 | 0 | ||||||||
Income (loss) from continuing operations before income taxes | 0 | 0 | 0 | ||||||||
Income tax expense | 0 | 0 | 0 | ||||||||
Equity in income of subsidiaries | 0 | 0 | 0 | ||||||||
Net Income (Loss) | 0 | 0 | 0 | ||||||||
Dividends on preferred stock | 0 | 0 | 0 | ||||||||
Accretion on preferred stock | 0 | 0 | 0 | ||||||||
Gain (Loss) On Redemption Of Preferred Stock | 0 | 0 | 0 | ||||||||
Net Income (Loss) Attributable to Common Shareholders | 0 | 0 | 0 | ||||||||
Consolidation, Eliminations [Member] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
Costs and Expenses | (37,000) | (37,000) | 492,000 | ||||||||
Income (loss) from continuing operations before income taxes | 37,000 | 37,000 | (492,000) | ||||||||
Income tax expense | 0 | 0 | 0 | ||||||||
Equity in income of subsidiaries | (580,634,000) | (282,499,000) | 467,410,000 | ||||||||
Net Income (Loss) | (580,597,000) | (282,462,000) | 466,918,000 | ||||||||
Dividends on preferred stock | 0 | 0 | 0 | ||||||||
Accretion on preferred stock | 0 | 0 | 0 | ||||||||
Gain (Loss) On Redemption Of Preferred Stock | 0 | 0 | 0 | ||||||||
Net Income (Loss) Attributable to Common Shareholders | $ (580,597,000) | $ (282,462,000) | $ 466,918,000 |
Condensed Consolidating Finan_6
Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Net Cash Provided by (Used in) Operating Activities | $ 653,555 | $ 422,981 | $ 272,768 | |
Net Cash Provided by (Used in) Investing Activities | (795,968) | (1,159,452) | (619,832) | |
Net Cash Provided by (Used in) Financing Activities | 135,155 | 741,817 | 308,340 | |
Net decrease in cash and cash equivalents | (7,258) | 5,346 | (38,724) | |
Cash and cash equivalents, beginning of year | 9,540 | 4,194 | 42,918 | |
Cash and cash equivalents, end of year | 2,282 | 9,540 | 4,194 | |
Cash and cash equivalents | 2,282 | 9,540 | 4,194 | $ 42,918 |
Reportable Legal Entities [Member] | Parent Company [Member] | ||||
Net Cash Provided by (Used in) Operating Activities | (269,318) | (121,107) | (34,773) | |
Net Cash Provided by (Used in) Investing Activities | 126,905 | (615,364) | (312,291) | |
Net Cash Provided by (Used in) Financing Activities | 135,155 | 741,817 | 308,340 | |
Net decrease in cash and cash equivalents | (7,258) | 5,346 | (38,724) | |
Cash and cash equivalents, beginning of year | 9,540 | 4,194 | 42,918 | |
Cash and cash equivalents, end of year | 2,282 | 9,540 | 4,194 | |
Cash and cash equivalents | 9,540 | 4,194 | ||
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member] | ||||
Net Cash Provided by (Used in) Operating Activities | 922,873 | 544,088 | 307,541 | |
Net Cash Provided by (Used in) Investing Activities | (792,383) | (1,155,340) | (575,824) | |
Net Cash Provided by (Used in) Financing Activities | (130,490) | 611,252 | 268,283 | |
Net decrease in cash and cash equivalents | 0 | 0 | 0 | |
Cash and cash equivalents, beginning of year | 0 | 0 | 0 | |
Cash and cash equivalents, end of year | 0 | 0 | 0 | |
Cash and cash equivalents | 0 | 0 | ||
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member] | ||||
Net Cash Provided by (Used in) Operating Activities | 0 | 0 | 0 | |
Net Cash Provided by (Used in) Investing Activities | 0 | 0 | (740) | |
Net Cash Provided by (Used in) Financing Activities | 0 | 0 | 740 | |
Net decrease in cash and cash equivalents | 0 | 0 | 0 | |
Cash and cash equivalents, beginning of year | 0 | 0 | 0 | |
Cash and cash equivalents, end of year | 0 | 0 | 0 | |
Cash and cash equivalents | 0 | 0 | ||
Consolidation, Eliminations [Member] | ||||
Net Cash Provided by (Used in) Operating Activities | 0 | 0 | 0 | |
Net Cash Provided by (Used in) Investing Activities | (130,490) | 611,252 | 269,023 | |
Net Cash Provided by (Used in) Financing Activities | 130,490 | (611,252) | (269,023) | |
Net decrease in cash and cash equivalents | 0 | 0 | 0 | |
Cash and cash equivalents, beginning of year | 0 | 0 | 0 | |
Cash and cash equivalents, end of year | $ 0 | 0 | 0 | |
Cash and cash equivalents | $ 0 | $ 0 |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Cash Flow Information [Line Items] | |||
Cash paid for interest, net of amounts capitalized | $ 59,846 | $ 77,213 | $ 75,231 |
Cash paid for income taxes | 0 | 0 | 0 |
Change in capital expenditure payables and accruals | (53,722) | 102,272 | (21,492) |
Contingent Consideration, Liability, Acquisition Date Fair Value | (7,880) | (8,805) | 0 |
Contingent Consideration, Asset, Divestiture Date Fair Value | 0 | 52,300 | 0 |
Share-based Compensation, Capitalized Amount | 4,124 | 4,482 | 4,591 |
Asset retirement obligation additions | 2,132 | 3,726 | 1,927 |
Non cash (Gain) Loss on Extinguishment of Debt | 3,586 | 1,357 | 0 |
Sanchez Acquisition [Member] | |||
Supplemental Cash Flow Information [Line Items] | |||
Business Combination, Liabilities | $ 0 | $ 0 | $ 4,880 |
Subsequent Events (Unaudited)_2
Subsequent Events (Unaudited) (Narrative) (Details) - Subsequent Event $ in Millions | 3 Months Ended |
Mar. 31, 2019USD ($) | |
Subsequent Event [Line Items] | |
Payment for Contingent Consideration Liability, Financing Activities | $ (50) |
Receipt for Contingent Consideration Asset, Financing Activities | $ 10 |
Subsequent Events (Unaudited)_3
Subsequent Events (Unaudited) (Schedule of Crude Oil Derivative Instruments) (Details) - Subsequent Event [Member] - 2020 [Member] - Crude Oil [Member] | Feb. 15, 2019bbl / d$ / bbls | Jan. 31, 2019bbl / d$ / bbls |
Three-way Collars [Member] | ||
Derivative [Line Items] | ||
Derivative, Volumes | bbl / d | 6,000 | |
Derivative Average Sub Floor Price | 45 | |
Weighted Average Floor Price ($/Bbl) | 55 | |
Weighted Average Ceiling Price ($/Bbl) | 64.69 | |
Basis Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Volumes | bbl / d | 3,000 | |
Derivative, Swap Type, Average Fixed Price | 55.06 |
Supplemental Disclosures Abou_3
Supplemental Disclosures About Oil and Gas Producing Activities (Narrative) (Details) MBoe in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($)MBoe | Dec. 31, 2017USD ($)MBoe | Dec. 31, 2016USD ($)MBoe | |
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Capitalized interest | $ | $ 36,600 | $ 28,300 | $ 17,000 |
Asset retirement obligation additions | $ | 2,132 | 3,726 | 1,927 |
Internal costs capitalized, oil and gas producing activities | $ | $ 17,000 | $ 14,800 | $ 10,500 |
Reserves discount factor | 10.00% | ||
Proved Developed Reserves [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Extensions and discoveries, MBoe | 12,687 | 6,473 | 6,525 |
Purchases of reserves in place, MBoe | 4,498 | 26,009 | 4,978 |
Sale of Mineral in Place, MBoe | (13,465) | (22,249) | |
Proved Undeveloped Reserves [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Extensions and discoveries, MBoe | 118,320 | 74,281 | 52,047 |
Purchases of reserves in place, MBoe | 20,094 | 1,167 | |
Sale of Mineral in Place, MBoe | (1,996) | (7,297) | |
Barrel of Oil Equivalent (Boe) [Domain] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Extensions and discoveries, MBoe | 131,007 | 80,754 | 58,572 |
Revisions of previous estimates, MBoe | (30,352) | (16,118) | (19,713) |
Purchases of reserves in place, MBoe | 4,498 | 46,103 | 6,145 |
Sale of Mineral in Place, MBoe | (15,461) | (29,546) | |
Price Reserve Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | 3,764 | 2,684 | (6,705) |
Removed Reserves Of Uneconomic Wells [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | (3,228) | ||
Revisions Due To Reduced Tail Reserves [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | (3,477) | ||
Performance Reserve Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | (12,363) | (4,500) | (6,083) |
Development Plan Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | (21,753) | (14,302) | (6,925) |
Eagle Ford Shale [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Percentage of reserve additions | 30.00% | 51.00% | 79.00% |
Eagle Ford Shale [Member] | Performance Reserve Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | (14,907) | ||
Delaware Basin [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Percentage of reserve additions | 70.00% | 48.00% | 20.00% |
Delaware Basin [Member] | Performance Reserve Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, MBoe | 2,544 | ||
Property Acquisition Costs [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Asset retirement obligation additions | $ | $ 200 | $ 100 | $ 2,037 |
Exploration and Development Costs [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Asset retirement obligation additions | $ | $ 1,913 | $ 3,527 |
Supplemental Disclosures Abou_4
Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved property acquisition costs | $ 47,370 | $ 303,307 | $ 90,661 |
Unproved properties | 182,220 | 525,061 | 113,535 |
Total property acquisition costs | 229,590 | 828,368 | 204,196 |
Exploration costs | 48,570 | 91,098 | 37,508 |
Development costs | 809,637 | 569,982 | 374,134 |
Total costs incurred | $ 1,087,797 | $ 1,489,448 | $ 615,838 |
Supplemental Disclosures Abou_5
Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas Reserves) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands | 12 Months Ended | |||
Dec. 31, 2018MBoeMBblsMMcf | Dec. 31, 2017MBoeMBblsMMcf | Dec. 31, 2016MBoeMBblsMMcf | Dec. 31, 2015MBoeMBblsMMcf | |
Crude Oil [Member] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year | 167,374 | 128,318 | 109,588 | |
Extensions and discoveries | 65,352 | 50,476 | 40,074 | |
Revisions of previous estimates | (31,287) | (19,838) | (16,731) | |
Purchases of reserves in place | 2,205 | 21,634 | 4,810 | |
Sales of Minerals in Place | (9,676) | (650) | ||
Production | (14,232) | (12,566) | (9,423) | |
Proved developed and undeveloped reserves end of year | 179,736 | 167,374 | 128,318 | |
Proved developed reserves (volume) | 75,267 | 69,632 | 51,062 | 42,311 |
Proved undeveloped reserve (volume) | 104,469 | 97,742 | 77,256 | 67,277 |
Natural Gas Liquids (Bbls) [Member] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year | 42,598 | 23,937 | 20,221 | |
Extensions and discoveries | 30,195 | 13,781 | 8,612 | |
Revisions of previous estimates | 1,936 | (909) | (3,230) | |
Purchases of reserves in place | 967 | 8,642 | 122 | |
Sales of Minerals in Place | (2,872) | (526) | ||
Production | (3,701) | (2,327) | (1,788) | |
Proved developed and undeveloped reserves end of year | 69,123 | 42,598 | 23,937 | |
Proved developed reserves (volume) | 25,809 | 17,447 | 9,387 | 7,933 |
Proved undeveloped reserve (volume) | 43,314 | 25,151 | 14,550 | 12,288 |
Natural Gas [Member] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year | MMcf | 310,470 | 287,445 | 244,938 | |
Extensions and discoveries | MMcf | 212,758 | 98,980 | 59,318 | |
Revisions of previous estimates | MMcf | (6,006) | 27,774 | 1,481 | |
Purchases of reserves in place | MMcf | 7,953 | 94,962 | 7,282 | |
Sales of Minerals in Place | MMcf | (17,475) | (170,219) | ||
Production | MMcf | (24,639) | (28,472) | (25,574) | |
Proved developed and undeveloped reserves end of year | MMcf | 483,061 | 310,470 | 287,445 | |
Proved developed reserves (volume) | MMcf | 178,941 | 131,355 | 187,054 | 154,725 |
Proved undeveloped reserve (volume) | MMcf | 304,120 | 179,115 | 100,391 | 90,213 |
Barrel of Oil Equivalent (Boe) [Domain] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year, Boe | MBoe | 261,717 | 200,163 | 170,632 | |
Extensions and discoveries, MBoe | MBoe | 131,007 | 80,754 | 58,572 | |
Revisions of previous estimates, MBoe | MBoe | (30,352) | (16,118) | (19,713) | |
Purchases of reserves in place, MBoe | MBoe | 4,498 | 46,103 | 6,145 | |
Sale of Mineral in Place, MBoe | MBoe | (15,461) | (29,546) | ||
Production, Boe | MBoe | (22,040) | (19,639) | (15,473) | |
Proved developed and undeveloped reserves end of year, Boe | MBoe | 329,369 | 261,717 | 200,163 | |
Proved developed reserves (energy) | MBoe | 130,899 | 108,972 | 91,625 | 76,032 |
Proved undeveloped reserves (energy) | MBoe | 198,470 | 152,745 | 108,538 | 94,600 |
Supplemental Disclosures Abou_6
Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 14,461,143 | $ 10,109,752 | $ 5,903,629 | |
Future production costs | (4,572,397) | (3,202,201) | (2,241,928) | |
Future development costs | (1,964,450) | (1,699,909) | (1,264,493) | |
Future income taxes (1) | (1,005,837) | (445,056) | 0 | |
Future net cash flows | 6,918,459 | 4,762,586 | 2,397,208 | |
Less 10% annual discount to reflect timing of cash flows | (3,282,901) | (2,297,544) | (1,093,779) | |
Standardized measure of discounted future net cash flows | $ 3,635,558 | $ 2,465,042 | $ 1,303,429 | $ 1,365,224 |
Supplemental Disclosures Abou_7
Supplemental Disclosures About Oil And Gas Producing Activities (Schedule of Average Price of Reserve Estimates) (Details) | 12 Months Ended | ||
Dec. 31, 2018$ / bbls$ / MMcf | Dec. 31, 2017$ / bbls$ / MMcf | Dec. 31, 2016$ / bbls$ / MMcf | |
Crude Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Reserves Estimates Average Sales Price | 63.80 | 49.87 | 39.60 |
Natural Gas Liquids (Bbls) [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Reserves Estimates Average Sales Price | 26.15 | 19.78 | 11.66 |
Natural Gas (Mcf) [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Reserves Estimates Average Sales Price | $ / MMcf | 2.46 | 2.96 | 1.89 |
Supplemental Disclosures Abou_8
Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure — beginning of period | $ 2,465,042 | $ 1,303,429 | $ 1,365,224 |
Net change in sales prices and production costs related to future production | 809,182 | 710,773 | (346,763) |
Net change in estimated future development costs | (9,627) | (51,854) | 74,407 |
Net change due to revisions in quantity estimates | (250,817) | (42,214) | (150,245) |
Accretion of discount | 263,837 | 130,343 | 136,522 |
Changes in production rates (timing) and other | (19,539) | (116,056) | (111,137) |
Total revisions to reserves proved in prior years | 793,036 | 630,992 | (397,216) |
Net change due to extensions and discoveries, net of estimated future development and production costs | 1,127,748 | 597,502 | 313,201 |
Net change due to purchases of reserves in place | 60,264 | 452,932 | 43,426 |
Net change due to divestitures of reserves in place | (181,308) | (106,608) | 0 |
Sales of crude oil, NGLs and natural gas produced, net of production costs | (843,333) | (566,258) | (320,272) |
Previously estimated development costs incurred | 496,600 | 326,383 | 299,066 |
Net change in income taxes | (282,491) | (173,330) | 0 |
Net change in standardized measure of discounted future net cash flows | 1,170,516 | 1,161,613 | (61,795) |
Standardized measure — end of period | $ 3,635,558 | $ 2,465,042 | $ 1,303,429 |
Selected Quarterly Financial _3
Selected Quarterly Financial Data (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Nov. 19, 2018 | Jan. 24, 2018 | |
Quarterly Financial Information [Line Items] | |||||||||||||
Gain (Loss) on Derivative Instruments, Net, Pretax | $ 159,407,000 | $ (55,388,000) | $ (67,714,000) | $ (29,596,000) | $ (86,107,000) | $ (24,377,000) | $ 26,065,000 | $ 25,316,000 | $ 6,709,000 | $ (59,103,000) | $ (49,073,000) | ||
Dividends on preferred stock | 18,161,000 | 7,781,000 | 0 | ||||||||||
Gain (Loss) On Redemption Of Preferred Stock | 7,100,000 | (7,133,000) | 0 | 0 | |||||||||
Preferred Stock Shares Redeemed | 50,000 | ||||||||||||
Loss on extinguishment of debt | (8,700,000) | 4,170,000 | 9,586,000 | 4,170,000 | 0 | ||||||||
Impairment of proved oil and gas properties | 0 | 0 | $ 576,540,000 | ||||||||||
7.50% Senior Notes [Member] | |||||||||||||
Quarterly Financial Information [Line Items] | |||||||||||||
Loss on extinguishment of debt | $ 9,586,000 | 4,170,000 | |||||||||||
Debt Instrument, Repurchased Face Amount | $ 320,000,000 | $ 150,000,000 | $ 150,000,000 | $ 130,000,000 | |||||||||
Debt instrument interest rate | 7.50% | 7.50% |
Selected Quarterly Financial _4
Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total revenues | $ 273,314 | $ 303,375 | $ 263,973 | $ 225,280 | $ 246,771 | $ 181,279 | $ 166,483 | $ 151,355 | $ 1,065,942 | $ 745,888 | $ 443,594 |
Operating profit (loss) | 129,405 | 165,141 | 140,265 | 108,992 | 113,205 | 69,364 | 63,147 | 57,953 | |||
Net income (loss) | 260,280 | 81,346 | 35,309 | 27,492 | (17,040) | 7,823 | 56,306 | 40,021 | 404,427 | 87,110 | (675,474) |
Net Income (Loss) Attributable to Common Shareholders | $ 255,120 | $ 76,118 | $ 30,095 | $ 14,743 | $ (23,434) | $ 5,574 | $ 56,306 | $ 40,021 | $ 376,076 | $ 78,467 | $ (675,474) |
Net Income (Loss) Attributable to Common Shareholders, Per Basic Share | $ 2.79 | $ 0.88 | $ 0.37 | $ 0.18 | $ (0.29) | $ 0.07 | $ 0.86 | $ 0.61 | $ 4.40 | $ 1.07 | $ (11.27) |
Net Income (Loss) Attributable to Common Shareholders, Per Diluted Share | $ 2.75 | $ 0.85 | $ 0.36 | $ 0.18 | $ (0.29) | $ 0.07 | $ 0.85 | $ 0.61 | $ 4.32 | $ 1.06 | $ (11.27) |