Document And Entity Information
Document And Entity Information - USD ($) $ / shares in Units, $ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 24, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
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 | 65,140,971 | ||
Share Price | $ 35.85 | ||
Entity Public Float | $ 2 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets | ||
Cash and cash equivalents | $ 4,194 | $ 42,918 |
Accounts receivable, net | 64,208 | 54,721 |
Derivative assets | 1,237 | 131,100 |
Other current assets | 3,349 | 3,443 |
Total current assets | 72,988 | 232,182 |
Oil and gas properties, full cost method | ||
Proved properties, net | 1,294,667 | 1,369,151 |
Unproved properties, not being amortized | 240,961 | 335,452 |
Other property and equipment, net | 10,132 | 12,258 |
Total property and equipment, net | 1,545,760 | 1,716,861 |
Deferred income taxes | 0 | 46,758 |
Derivative assets | 0 | 1,115 |
Other assets | 7,579 | 10,330 |
Total Assets | 1,626,327 | 2,007,246 |
Current liabilities | ||
Accounts payable | 55,631 | 74,065 |
Revenues and royalties payable | 38,107 | 67,808 |
Accrued capital expenditures | 36,594 | 39,225 |
Accrued interest | 22,016 | 21,981 |
Accrued lease operating expense | 12,377 | 11,588 |
Current liabilities of discontinued operations | 0 | 2,666 |
Deferred income taxes | 0 | 46,758 |
Derivative liabilities | 22,601 | 0 |
Other current liabilities | 24,633 | 21,393 |
Total current liabilities | 211,959 | 285,484 |
Long-term debt | 1,325,418 | 1,236,017 |
Liabilities of discontinued operations | 0 | 1,088 |
Asset retirement obligations | 20,848 | 16,183 |
Derivative liabilities | 27,528 | 12,648 |
Other liabilities | 17,116 | 11,772 |
Liabilities | 1,602,869 | 1,563,192 |
Commitments and contingencies | ||
Shareholders’ equity | ||
Common stock, $0.01 par value, 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016 and 58,332,993 issued and outstanding as of December 31, 2015 | 651 | 583 |
Additional paid-in capital | 1,665,891 | 1,411,081 |
Accumulated deficit | (1,643,084) | (967,610) |
Total shareholders’ equity | 23,458 | 444,054 |
Total Liabilities and Shareholders’ Equity | $ 1,626,327 | $ 2,007,246 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 90,000,000 | 90,000,000 |
Common stock, shares issued (in shares) | 65,132,499 | 58,332,993 |
Common stock, shares outstanding (in shares) | 65,132,499 | 58,332,993 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Statement [Abstract] | |||
Crude oil revenue | $ 378,073 | $ 376,094 | $ 610,483 |
Natural gas liquids revenue | 22,428 | 15,608 | 25,050 |
Natural gas revenue | 43,093 | 37,501 | 74,654 |
Total revenues | 443,594 | 429,203 | 710,187 |
Costs and Expenses | |||
Lease operating | 98,717 | 90,052 | 74,157 |
Production taxes | 19,046 | 17,683 | 29,544 |
Ad valorem taxes | 5,559 | 9,255 | 8,450 |
Depreciation, depletion and amortization | 213,962 | 300,035 | 317,383 |
General and administrative, net | 74,972 | 67,224 | 77,029 |
(Gain) loss on derivatives, net | 49,073 | (99,261) | (201,907) |
Interest expense, net | 79,403 | 69,195 | 53,171 |
Impairment of proved oil and gas properties | 576,540 | 1,224,367 | 0 |
Loss on extinguishment of debt | 0 | 38,137 | 0 |
Other expense, net | 1,796 | 11,276 | 2,150 |
Total costs and expenses | 1,119,068 | 1,727,963 | 359,977 |
OTHER INCOME AND EXPENSES | |||
Income (Loss) From Continuing Operations Before Income Taxes | (675,474) | (1,298,760) | 350,210 |
Income tax (expense) benefit | 0 | 140,875 | (127,927) |
Income (Loss) From Continuing Operations | (675,474) | (1,157,885) | 222,283 |
Income From Discontinued Operations, Net of Income Taxes | 0 | 2,731 | 4,060 |
Net Income (Loss) | $ (675,474) | $ (1,155,154) | $ 226,343 |
Net Income (Loss) Per Common Share - Basic | |||
Income (Loss) from Continuing Operations (in dollars per share) | $ (11.27) | $ (22.50) | $ 4.90 |
Net income from discontinued operations (in dollars per share) | 0 | 0.05 | 0.09 |
Net income (loss) per share basic (in dollars per share) | (11.27) | (22.45) | 4.99 |
Net Income (Loss) Per Common Share - Diluted | |||
Net income (loss) from continuing operations, diluted (in dollars per share) | (11.27) | (22.50) | 4.81 |
Net income from discontinued operations (in dollars per share) | 0 | 0.05 | 0.09 |
Net income per share, diluted (in dollars per share) | $ (11.27) | $ (22.45) | $ 4.90 |
Weighted Average Common Shares Outstanding | |||
Basic (in shares) | 59,932 | 51,457 | 45,372 |
Diluted (in shares) | 59,932 | 51,457 | 46,194 |
Consolidated Statements Of Shar
Consolidated Statements Of Shareholders' Equity - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Retained Earnings (Accumulated Deficit) [Member] |
Total shareholders' equity at Dec. 31, 2013 | $ 841,604 | $ 455 | $ 879,948 | $ (38,799) |
Total shareholders' equity, shares at Dec. 31, 2013 | 45,468,675 | |||
Stock options exercised for cash | $ 437 | $ 1 | 436 | |
Stock options exercised for cash, shares | 33,086 | 33,086 | ||
Stock-based compensation | $ 30,280 | 30,280 | ||
Restricted stock award issuances and restricted stock unit vestings, net of forfeitures | (91) | $ 5 | (96) | |
Restricted stock award issuances and restricted stock unit vestings, net of forfeitures, shares | 625,301 | |||
Other shareholders' equity | 4,868 | $ 0 | 4,868 | |
Other shareholders' equity, shares | 862 | |||
Net income (loss) | 226,343 | 226,343 | ||
Total shareholders' equity at Dec. 31, 2014 | 1,103,441 | $ 461 | 915,436 | 187,544 |
Total shareholders' equity, shares at Dec. 31, 2014 | 46,127,924 | |||
Stock options exercised for cash | $ 46 | $ 0 | 46 | |
Stock options exercised for cash, shares | 2,433 | 2,433 | ||
Stock-based compensation | $ 25,707 | 25,707 | ||
Restricted stock award issuances and restricted stock unit vestings, net of forfeitures | (144) | $ 6 | (150) | |
Restricted stock award issuances and restricted stock unit vestings, net of forfeitures, shares | 630,723 | |||
Sale of common stock, net of offering costs | 470,158 | $ 115 | 470,043 | |
Sale of common stock, net of offering costs, shares | 11,500,000 | |||
Other shareholders' equity | 0 | $ 1 | (1) | |
Other shareholders' equity, shares | 71,913 | |||
Net income (loss) | (1,155,154) | (1,155,154) | ||
Total shareholders' equity at Dec. 31, 2015 | 444,054 | $ 583 | 1,411,081 | (967,610) |
Total shareholders' equity, shares at Dec. 31, 2015 | 58,332,993 | |||
Stock-based compensation | 31,194 | 31,194 | ||
Restricted stock award issuances and restricted stock unit vestings, net of forfeitures | (55) | $ 8 | (63) | |
Restricted stock award issuances and restricted stock unit vestings, net of forfeitures, shares | 799,506 | |||
Sale of common stock, net of offering costs | 223,739 | $ 60 | 223,679 | |
Sale of common stock, net of offering costs, shares | 6,000,000 | |||
Net income (loss) | (675,474) | (675,474) | ||
Total shareholders' equity at Dec. 31, 2016 | $ 23,458 | $ 651 | $ 1,665,891 | $ (1,643,084) |
Total shareholders' equity, shares at Dec. 31, 2016 | 65,132,499 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Flows From Operating Activities | |||
Net income (loss) | $ (675,474) | $ (1,155,154) | $ 226,343 |
(Income) loss from discontinued operations, net of income taxes | 0 | (2,731) | (4,060) |
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities from continuing operations | |||
Depreciation, depletion and amortization | 213,962 | 300,035 | 317,383 |
Impairment of proved oil and gas properties | 576,540 | 1,224,367 | 0 |
(Gain) loss on derivatives, net | 49,073 | (99,261) | (201,907) |
Cash received (paid) for derivative settlements, net | 119,369 | 194,296 | (13,529) |
Loss on extinguishment of debt | 0 | 38,137 | 0 |
Stock-based compensation expense, net | 36,086 | 14,729 | 25,878 |
Deferred income taxes | 0 | (140,875) | 127,927 |
Non-cash interest expense, net | 4,172 | 4,289 | 4,272 |
Other, net | 3,753 | 5,709 | 2,379 |
Changes in components of working capital and other assets and liabilities- | |||
Accounts receivable | (12,836) | 29,781 | (1,334) |
Accounts payable | (30,130) | (12,617) | 27,238 |
Accrued liabilities | (7,938) | (17,517) | (3,096) |
Other assets and liabilities, net | (3,809) | (4,453) | (5,219) |
Net cash provided by operating activities from continuing operations | 272,768 | 378,735 | 502,275 |
Net cash used in operating activities from discontinued operations | 0 | (1,368) | (656) |
Net cash provided by operating activities | 272,768 | 377,367 | 501,619 |
Cash Flows From Investing Activities | |||
Capital expenditures - oil and gas properties | (480,929) | (675,952) | (861,354) |
Acquisitions of oil and gas properties | (153,521) | (1,817) | (92,961) |
Proceeds from sales of oil and gas properties, net | 15,564 | 8,047 | 12,576 |
Other, net | (946) | (3,654) | 1,063 |
Net cash used in investing activities from continuing operations | (619,832) | (673,376) | (940,676) |
Net cash used in investing activities from discontinued operations | 0 | (2,678) | (7,834) |
Net cash used in investing activities | (619,832) | (676,054) | (948,510) |
Cash Flows From Financing Activities | |||
Issuance of senior notes | 0 | 650,000 | 301,500 |
Tender and redemption of senior notes | 0 | (626,681) | 0 |
Payment of deferred purchase payment | 0 | (150,000) | 0 |
Borrowings under credit agreement | 770,291 | 1,126,860 | 986,041 |
Repayments of borrowings under credit agreement | (683,291) | (1,126,860) | (986,041) |
Payments of debt issuance costs | (1,330) | (12,420) | (6,510) |
Sale of common stock, net of offering costs | 223,739 | 470,158 | 0 |
Excess tax benefits from stock-based compensation | 0 | 0 | 4,863 |
Proceeds from stock options exercised | 0 | 46 | 437 |
Other, net | (1,069) | (336) | 0 |
Net cash provided by financing activities from continuing operations | 308,340 | 330,767 | 300,290 |
Net cash provided by financing activities from discontinued operations | 0 | 0 | 0 |
Net cash provided by financing activities | 308,340 | 330,767 | 300,290 |
Net Increase (Decrease) in Cash and Cash Equivalents | (38,724) | 32,080 | (146,601) |
Cash and Cash Equivalents, Beginning of Year | 42,918 | 10,838 | 157,439 |
Cash and Cash Equivalents, End of Year | $ 4,194 | $ 42,918 | $ 10,838 |
Nature Of Operations
Nature Of Operations | 12 Months Ended |
Dec. 31, 2016 | |
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 oil, NGLs, and gas primarily from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Niobrara Formation in Colorado, the Utica Shale in Ohio, and the Marcellus Shale in Pennsylvania. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
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. The Company evaluates subsequent events through the date the financial statements are issued. 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 costs and 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 derivative assets and liabilities, 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 $34.3 million and $49.1 million as of December 31, 2016 and 2015 , respectively. Accounts Receivable The Company establishes an allowance for doubtful accounts when it determines 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. As of December 31, 2016 and 2015 , the Company’s allowance for doubtful accounts was $0.8 million and $1.0 million , respectively. Concentration of Credit Risk The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in 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 generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners. Major Customers Shell Trading (US) Company accounted for approximately 56% , 65% , and 44% of the Company’s total revenues in 2016 , 2015 , and 2014 , respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 15% , 9% and 26% of the Company’s total revenues in 2016 , 2015 and 2014 , respectively. 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 and totaled $10.5 million , $15.8 million and $18.8 million for the years ended December 31, 2016, 2015 and 2014 , respectively. 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. Average DD&A per Boe of proved oil and gas properties was $13.50 , $22.05 and $26.20 for the years ended December 31, 2016, 2015 and 2014 , respectively. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost of exploratory wells in progress, and related capitalized interest. Exploratory wells in progress and 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 and completion 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. The Company capitalized interest costs associated with its unproved properties totaling $17.0 million , $32.1 million and $34.5 million for the years ended December 31, 2016, 2015 and 2014 , respectively. 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, natural gas liquids 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 derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million , respectively, due primarily to declines in the 12-Month Average Realized Price of crude oil. See “Note 4. Property and Equipment, Net” for further details of the impairments. 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, 2016 , 2015 and 2014 , 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 amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. See “—Recently Adopted Accounting Pronouncements” below for discussion of classification debt issuance costs in the consolidated balance sheets. Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities 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 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 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 12. Fair Value Measurements.” 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 from continuing operations 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 well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.” 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.” Revenue Recognition Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2016 and 2015 , the Company did not have any material production imbalances. Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. All derivative instruments are recorded on the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews derivative instruments, including volumes, types of instruments and counterparties. These policies require that 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 11. Derivative Instruments” for further discussion of the Company’s derivative instruments. Stock-Based Compensation The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. 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 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 SARs, stock-based compensation expense is initially based on the grant date fair value (using the Black-Scholes-Merton option pricing model) with the liability subsequently remeasured at each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. Each award includes a performance condition that must be met in order for that award to vest. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the value of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. Performance Share Awards. For performance share awards, 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 award includes a performance condition that must be met in order for that award to vest. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved. See “Note 9. Shareholders’ Equity and Stock Based Compensation Plans.” 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 bases of assets and liabilities and their reported amounts in the Company’s 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 whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether 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. Income (Loss) From Continuing Operations Per Common Share Basic income (loss) from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted income from continuing operations 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 share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and 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 share awards 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. When a loss from continuing operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. Supplemental income (loss) from continuing operations per common share information is provided below: Years Ended December 31, 2016 2015 2014 (In thousands, except per share amounts) Income (Loss) From Continuing Operations ($675,474 ) ($1,157,885 ) $222,283 Basic weighted average common shares outstanding 59,932 51,457 45,372 Effect of dilutive instruments: Restricted stock awards and units — — 684 Performance share awards — — 56 Stock options — — 13 Warrants — — 69 Diluted weighted average common shares outstanding 59,932 51,457 46,194 Income (Loss) From Continuing Operations Per Common Share Basic ($11.27 ) ($22.50 ) $4.90 Diluted ($11.27 ) ($22.50 ) $4.81 For the years ended December 31, 2016 and 2015 , the Company reported a loss from continuing operations and therefore the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 0.7 million and 0.6 million potentially dilutive common shares outstanding, respectively. For the year ended December 31, 2014 , the number of potentially dilutive common shares outstanding excluded from the calculation of diluted weighted average shares outstanding was not significant. Recently Adopted Accounting Pronouncements In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 requires that all deferred tax liabilities and assets, as well as any related valuation allowance, be classified in the balance sheet as noncurrent rather than presenting the deferred tax liabilities and assets as net current or net noncurrent. Effective January 1, 2016, the Company early adopted ASU 2015-17 which was applied prospectively and therefore the adoption had no impact on the consolidated balance sheet as of December 31, 2015. In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 simplifies the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt rather than as an asset. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“ASU 2015-15”), which allows debt issuance costs associated with line-of-credit agreements to be deferred and presented as an asset in the balance sheet, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. Effective January 1, 2016, the Company adopted ASU 2015-03 and ASU 2015-15 and reclassified $19.7 million of unamortized debt issuance costs related to the Company’s senior notes from long-term assets to long-term debt in the consolidated balance sheet as of December 31, 2015. Debt issuance costs associated with the Company’s revolving credit facility remain classified as a long-term asset in the consolidated balance sheets. Recently Issued Accounting Pronouncements In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (“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. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, provided that it is adopted in its entirety in the same period. The Company is evaluating ASU 2016-15 to determine what impact adoption of the new standard will have on its consolidated statements of cash flows. In March 2016, the FASB issued 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. The Company adopted ASU 2016-09 effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits is expected to result in a cumulative-effect adjustment of approximately $15.7 million , which would increase net deferred tax assets and increase the valuation allowance by the same amount as of the beginning of 2017, resulting in no impact to the consolidated statements of operations. The remaining provisions of this amendment are not expected to have a material effect on the Company’s consolidated financial statements and related disclosures. 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 asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. 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. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. The Company is evaluating ASU 2016-02 to determine what impact adoption of the new standard will have on its consolidated financial statements and related disclosures. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, timing, amount and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for interim and annual periods beginning after December 31, 2016. Companies are permitted to adopt ASU 2014-09 through the use of either the full retrospective approach or a modified retrospective approach. The Company is still in the process of assessing its contracts with customers and assessing their potential impact on the Company’s consolidated financial statements and related disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2016 | |
Acquisitions and Divestitures [Abstract] | |
Acquisitions Disclosures | 3. Acquisitions 2016 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 in the Eagle Ford Shale primarily in LaSalle, Frio and McMullen, Texas counties (the “Sanchez Acquisition”) for a purchase price of $181.0 million , subject to customary purchase price adjustments. The transaction had an effective date of June 1, 2016. The Company paid $10.0 million as a deposit upon signing the purchase and sale agreement and $143.5 million at the initial closing on December 14, 2016, which included purchase price adjustments primarily related to net cash flows from the acquired wells from the effective date to the closing date of $10.7 million and adjustments of $16.8 million for leases not conveyed to the Company at the initial closing. The Sanchez Acquisition was funded with of portion of the net proceeds from the October 2016 common stock offering described in “Note 9. Shareholders’ Equity and Stock Based Compensation Plans.” The Sanchez Acquisition was accounted for under the acquisition method of accounting whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on currently available information. A combination of a discounted cash flow model and market data was used 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 purchase price allocation for the Sanchez Acquisition is preliminary and subject to change based on subsequent closings related to the leases that were not conveyed to the Company at the initial closing on December 14, 2016 and updates to purchase price adjustments. The following presents the purchase price and the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. These amounts will be finalized as soon as possible, but no later than December 14, 2017. December 14, 2016 (In thousands) Assets Other current assets $477 Oil and gas properties Proved properties 90,661 Unproved properties 67,263 Total oil and gas properties 157,924 Total assets acquired $158,401 Liabilities Revenues and royalties payable $1,442 Other current liabilities 323 Asset retirement obligations 2,037 Other liabilities 1,078 Total liabilities assumed $4,880 Net Assets Acquired $153,521 Included in the consolidated statement of operations for the year ended December 31, 2016 are revenues of $1.5 million and income from continuing operations before income taxes of $1.0 million from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction. 2014 EFM Acquisition On October 24, 2014, the Company completed the acquisition of interests in oil and gas properties (the “Properties”) from Eagle Ford Minerals, LLC (“EFM”) primarily in LaSalle, Atascosa and McMullen counties, Texas in the Eagle Ford (the “Eagle Ford Shale Acquisition”). The Eagle Ford Shale Acquisition had an effective date of October 1, 2014, with an agreed upon purchase price of $250.0 million , of which the Company paid a total of $241.8 million , net of post-closing and working capital adjustments, which consisted of approximately $93.0 million at closing and $148.8 million on February 13, 2015. Prior to the Eagle Ford Shale Acquisition, the Company and EFM were joint working interest owners in the Properties, for which the Company acted as the operator and owned an approximate 75% working interest in all of such Properties. After giving effect to the Eagle Ford Shale Acquisition, the Company holds an approximate 100% working interest in the Properties. The deferred purchase payment was discounted by $2.6 million to an acquisition date fair value of $147.4 million . For the further discussion of the accounting for the deferred purchase payment, see “Note 6. Long-Term Debt.” The Eagle Ford Shale Acquisition was accounted for under the acquisition method of accounting whereby the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values. Purchase price adjustments of $3.2 million relate to the net operating cash flows and capital expenditures associated with the acquired interests in oil and gas properties for the period from the October 1, 2014 effective date to the October 24, 2014 closing date. The following presents the purchase price and the allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date: October 24, 2014 (In thousands) Assets Other current assets $485 Proved and unproved oil and gas properties 244,124 Total assets acquired $244,609 Liabilities Asset retirement obligations $423 Total liabilities assumed $423 Net Assets Acquired $244,186 Included in the consolidated statements of operations for the year ended December 31, 2014 are revenues of $13.1 million and income from continuing operations before income taxes of $11.0 million from the Properties, representing activity subsequent to the closing of the transaction. 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, 2014, and December 31, 2013, assuming the Eagle Ford Shale Acquisition had been completed as of January 1, 2013, including adjustments to reflect the 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 Eagle Ford Shale Acquisition. Year Ended December 31, 2014 (In thousands, except per share data) (Unaudited) Total revenues $761,199 Income From Continuing Operations $264,714 Income From Continuing Operations Per Common Share Basic $5.83 Diluted $5.73 Weighted Average Common Shares Outstanding Basic 45,372 Diluted 46,194 |
Property And Equipment, Net
Property And Equipment, Net | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property And Equipment, Net | 4. Property and Equipment, Net As of December 31, 2016 and 2015 , total property and equipment, net consisted of the following: December 31, 2016 2015 Oil and gas properties, full cost method (In thousands) Proved properties $4,687,416 $3,976,511 Accumulated DD&A and impairments (3,392,749 ) (2,607,360 ) Proved properties, net 1,294,667 1,369,151 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 211,067 280,263 Exploratory wells in progress — 9,432 Capitalized interest 29,894 45,757 Total unproved properties, not being amortized 240,961 335,452 Other property and equipment 23,127 22,677 Accumulated depreciation (12,995 ) (10,419 ) Other property and equipment, net 10,132 12,258 Total property and equipment, net $1,545,760 $1,716,861 Costs not subject to amortization totaling $241.0 million at December 31, 2016 were incurred in the following periods: $120.5 million in 2016 , $20.7 million in 2015 and $99.8 million in 2014 . Impairment of Proved Oil and Gas Properties Primarily due to declines in the 12-Month Average Realized Price of crude oil beginning in the third quarter of 2015, the Company recognized impairments of proved oil and gas properties for the years ended December 31, 2016 and 2015 as summarized in the table below: Years Ended December 31, 2016 2015 Impairment of proved oil and gas properties (in thousands) $576,540 $1,224,367 Beginning of period 12-Month Average Realized Price ($/Bbl) $47.24 $92.24 End of period 12-Month Average Realized Price ($/Bbl) $39.60 $47.24 Percent decrease in 12-Month Average Realized Price (16 %) (49 %) The Company estimates that the March 31, 2017 cost center ceiling will exceed the net book value of oil and gas properties, less related deferred income taxes and accordingly does not expect an impairment of proved oil and gas properties for the three months ended March 31, 2017. The estimated first quarter of 2017 cost center ceiling is based on the estimated 12-Month Average Realized Price of crude oil of $44.39 per barrel as of March 31, 2017 , which is calculated using the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters would result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of proved oil and gas properties. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 5. Income Taxes The components of income tax expense (benefit) from continuing operations were as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Current income tax (expense) benefit U.S. Federal $— $— $— State — — — Total current income tax (expense) benefit — — — Deferred income tax (expense) benefit U.S. Federal — 131,502 (122,342 ) State — 9,373 (5,585 ) Total deferred income tax (expense) benefit — 140,875 (127,927 ) Total income tax (expense) benefit from continuing operations $— $140,875 ($127,927 ) The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Income (loss) from continuing operations before income taxes ($675,474 ) ($1,298,760 ) $350,210 Income tax (expense) benefit at the statutory rate 236,416 454,566 (122,574 ) State income tax (expense) benefit, net of U.S. Federal income taxes 3,894 9,373 (5,585 ) Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense — 1,671 — Deferred tax asset valuation allowance (240,864 ) (323,586 ) — Other 554 (1,149 ) 232 Total income tax (expense) benefit from continuing operations $— $140,875 ($127,927 ) Deferred Income Taxes Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. As of December 31, 2016 and 2015 , deferred tax assets and liabilities are comprised of the following: December 31, 2016 2015 (In thousands) Deferred income tax assets Net operating loss carryforward - U.S. Federal and State $221,063 $119,783 Oil and gas properties 309,848 232,786 Asset retirement obligations 7,434 5,779 Stock-based compensation 5,238 4,741 Derivative liabilities 17,545 4,433 Other 3,739 3,435 Deferred income tax assets 564,867 370,957 Deferred tax asset valuation allowance (564,434 ) (324,681 ) Net deferred income tax assets 433 46,276 Deferred income tax liabilities Derivative assets (433 ) (46,276 ) Net deferred income tax asset (liability) $— $— All deferred income tax assets, net of related valuation allowances, and liabilities for 2016 are classified as noncurrent in the accompanying consolidated balance sheet upon the Company’s early adoption of ASU 2015-17 on a prospective basis. Prior year amounts have not been restated. See “Recently Adopted Accounting Pronouncements” in “Note 2. Summary of Significant Accounting Policies” for additional discussion. At December 31, 2016 and 2015 , the net deferred income tax asset (liability) is classified as follows: December 31, 2016 2015 (In thousands) Net current deferred income tax liability $— ($46,758 ) Net noncurrent deferred income tax asset — 46,758 Net deferred income tax asset (liability) $— $— Deferred tax asset valuation allowance. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated 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. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2016, driven primarily by the recording of impairments of proved oil and gas properties beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the third quarter of 2015, the Company concluded in each subsequent quarterly evaluation that it was more likely than not the deferred tax assets will not be realized and based on evaluation of evidence available as of December 31, 2016, the Company’s previous conclusion remains unchanged. As a result, the net deferred tax assets at the end of each quarter, including December 31, 2016 were reduced to zero . The valuation allowance at December 31, 2015 of $324.7 million was increased during the year ended December 31, 2016 by $240.8 million , less a $1.1 million reclassification to a stock based compensation deferred tax asset, bringing the valuation allowance against the net deferred tax assets to $564.4 million at December 31, 2016. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company may have additional valuation allowance increases with no significant deferred income tax expense or benefit. Net Operating Loss Carryforwards and Other Net Operating Loss Carryforwards. As of December 31, 2016 , the Company had U.S. federal net operating loss carryforwards of approximately $648.7 million . If not utilized in earlier periods, the U.S. federal net operating loss will expire between 2026 and 2036 . 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 (a) the fair market value of the equity of the Company multiplied by (b) 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. As of December 31, 2016, the Company does not believe it has a Section 382 limitation on the ability to utilize its U.S. 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. loss carryforwards. The Company receives a tax deduction during the period performance share units, restricted stock awards, and restricted stock units vest, generally equal to the fair value of the awards and units on the vesting date. The Company also receives a tax deduction during the period stock options and SARs are exercised, generally for the excess of the exercise date stock price over the exercise price of the option or SAR. Because these stock-based compensation tax deductions did not reduce current taxes payable as a result of U.S. loss carryforwards, the benefit of these tax deductions has not been reflected in the U.S. loss carryforward deferred tax asset. Stock-based compensation tax deductions included in the U.S. loss carryforwards of $648.7 million but not reflected in the associated deferred tax asset were $44.7 million as of December 31, 2016 . The Company expects to recognize the $15.7 million deferred tax asset associated with these stock-based compensation tax deductions under the tax law ordering approach which looks to the provision within the tax law for determining the sequence in which the U.S. loss carryforwards and other tax attributes are utilized. When the stock-based compensation tax deduction related U.S. loss carryforward deferred tax asset is realized, the tax benefit of reducing current taxes payable will be credited directly to additional paid-in capital. Other. The Company files income tax returns in the U.S. Federal jurisdiction, in various states and previously filed in one foreign jurisdiction, each with varying statutes of limitations. The 1999 through 2016 tax years generally remain subject to examination by federal and state tax authorities. The foreign jurisdiction generally remains subject to examination by the relevant taxing authority for the 2015 and 2016 tax years through 2017 and 2018, respectively. The Company received notice in January 2015 from the Large Business and International Division of the Internal Revenue Service (the “Service”) that the Company’s 2012 Federal Tax Return was selected for examination. The examination commenced in February 2015, and the Service concluded the examination of the Company’s 2012 Federal Tax Return records in November 2015. The exam concluded with no material adjustments made to the Company’s 2012 Federal Tax Return and no open items pending further action between the Company and the Service. As of December 31, 2016 , 2015 and 2014 , the Company had no uncertain tax positions. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt | 6. Long-Term Debt Long-term debt consisted of the following as of December 31, 2016 and 2015 : December 31, 2016 2015 (In thousands) Senior Secured Revolving Credit Facility $87,000 $— 7.50% Senior Notes due 2020 600,000 600,000 Unamortized premium for 7.50% Senior Notes 1,020 1,251 Unamortized debt issuance costs for 7.50% Senior Notes (7,573 ) (9,048 ) 6.25% Senior Notes due 2023 650,000 650,000 Unamortized debt issuance costs for 6.25% Senior Notes (9,454 ) (10,611 ) Other long-term debt due 2028 4,425 4,425 Long-term debt $1,325,418 $1,236,017 Senior Secured Revolving Credit Facility The Company has a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2016 , had a borrowing base of $600.0 million , with $87.0 million of borrowings outstanding at a weighted average interest rate of 2.72% . As of December 31, 2016 , the Company also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest-only payments until July 2, 2018, 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, in each case which 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. The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic 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 as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net. Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments Applicable Margin for Base Rate Loans Applicable Margin for Eurodollar Loans Commitment Fee Less than 25% 1.00% 2.00% 0.500% Greater than or equal to 25% but less than 50% 1.25% 2.25% 0.500% Greater than or equal to 50% but less than 75% 1.50% 2.50% 0.500% Greater than or equal to 75% but less than 90% 1.75% 2.75% 0.500% Greater than or equal to 90% 2.00% 3.00% 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 Secured Debt to EBITDA of not more than 2.00 to 1.00; and (2) a Current Ratio of not less than 1.00 to 1.00; and (3) a ratio of EBITDA to Interest Expense of not less than 2.50 to 1.00. As of December 31, 2016 , the ratio of Total Secured Debt to EBITDA was 0.21 to 1.00, the Current Ratio was 3.27 to 1.00 and the ratio of EBITDA to Interest Expense was 4.58 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 borrowing outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and dispositions 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, mergers, asset dispositions, 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). 7.50% Senior Notes due 2020 and 6.25% Senior Notes due 2023 Since September 15, 2016, the Company has had the right to redeem all or a portion of the 7.50% Senior Notes at redemption prices decreasing from 103.75% to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest. Before April 15, 2018, the Company may, at its option, redeem all or a portion of the 6.25% 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 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 7.50% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 7.50% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount, plus any accrued and unpaid interest. The indentures governing the 7.50% 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, 2016 , the 7.50% Senior Notes and the 6.25% Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility. 8.625% Senior Notes due 2018 On April 14, 2015, the Company settled a cash tender offer for any or all of the outstanding $600.0 million aggregate principal amount of its 8.625% Senior Notes, which expired on April 23, 2015. On April 28, 2015, the Company made an aggregate cash payment of $276.4 million for the $264.2 million aggregate principal amount of 8.625% Senior Notes validly tendered in the tender offer. This represented a tender offer premium totaling $12.2 million , equal to $1,046.13 for each $1,000 principal amount of 8.625% Senior Notes validly tendered and accepted for payment pursuant to the tender offer. In addition, all 8.625% Senior Notes accepted for payment received accrued and unpaid interest of $0.8 million from the last interest payment date up to, but not including, the settlement date. In connection with the cash tender offer, the Company also sent a notice of redemption to the trustee for its 8.625% Senior Notes to conditionally call for redemption on May 14, 2015 all of the 8.625% Senior Notes then outstanding, conditioned upon and subject to the Company receiving specified net proceeds from one or more securities offerings, which conditions were satisfied. On May 14, 2015, the Company paid an aggregate redemption price of $352.6 million , including a redemption premium of $14.5 million , which represented 104.313% of the principal amount of the then outstanding 8.625% Senior Notes (or $1,043.13 for each $1,000 principal amount of the 8.625% Senior Notes) plus accrued and unpaid interest of $2.3 million from the last interest payment date up to, but not including, the redemption date, to redeem the then outstanding $335.8 million aggregate principal amount of 8.625% Senior Notes. As a result of the cash tender offer and the redemption of the 8.625% Senior Notes, the Company recorded a loss on extinguishment of debt of $38.1 million during the second quarter of 2015, which includes the premium paid to repurchase the 8.625% Senior Notes of $26.7 million and non-cash charges of $11.4 million attributable to the write-off of unamortized debt issuance costs and the remaining discount associated with the 8.625% Senior Notes. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 7. Asset Retirement Obligations The following table sets forth asset retirement obligations for the years ended December 31, 2016 and 2015 : Years Ended December 31, 2016 2015 (In thousands) Beginning of year asset retirement obligations $16,511 $12,512 Liabilities incurred 2,137 3,227 Increase due to acquisition of oil and gas properties 2,037 — Liabilities settled (599 ) (1,966 ) Accretion expense 1,364 1,112 Revisions to estimated cash flows (210 ) 1,626 End of year asset retirement obligations 21,240 16,511 Current asset retirement obligations (included in other current liabilities) (392 ) (328 ) Non-current asset retirement obligations $20,848 $16,183 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
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. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. The results of operations and financial position 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, natural gas regulation, tax increases, 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 for the years ended December 31, 2016 , 2015 and 2014 was $2.0 million , $2.2 million , and $1.9 million , respectively, and includes rent expense for the Company’s corporate office and field offices. At December 31, 2016 , total minimum commitments from long-term, non-cancelable operating and capital leases, drilling rigs and minimum delivery commitments are as shown in the table below. The total minimum commitments related to the drilling rigs represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. The delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation throughput commitments. The Company may incur volume deficiency fees from time to time if it elects to voluntarily curtail production due to market or operational considerations. 2017 2018 2019 2020 2021 2022 and Thereafter Total (In thousands) Operating leases $4,438 $4,430 $4,412 $4,463 $4,450 $1,854 $24,047 Capital leases 1,856 1,823 1,800 1,050 — — 6,529 Drilling rig contracts 23,753 3,957 — — — — 27,710 Delivery commitments 8,134 8,611 7,298 4,826 3,680 291 32,840 Total $38,181 $18,821 $13,510 $10,339 $8,130 $2,145 $91,126 |
Shareholders' Equity And Stock
Shareholders' Equity And Stock Incentive Plan | 12 Months Ended |
Dec. 31, 2016 | |
Shareholders' Equity And Stock Incentive Plan [Abstract] | |
Shareholders' Equity And Stock Incentive Plan | 9. Shareholders’ Equity and Stock Based Compensation Plans Common Stock Offerings On October 28, 2016, the Company completed a public offering of 6.0 million shares of its common stock at a price of $37.32 per share, for proceeds of $223.7 million , net of offering costs. The Company used the net proceeds from the common stock offering to fund the Sanchez Acquisition and to repay borrowings under the revolving credit facility. On October 21, 2015, the Company completed a public offering of 6.3 million shares of its common stock at a price of $37.80 per share, for proceeds of $238.8 million , net of offering costs. The Company used the net proceeds from the common stock offering to repay borrowings under the Company’s revolving credit facility and for general corporate purposes. On March 20, 2015, the Company completed a public offering of 5.2 million shares of its common stock at a price of $44.75 per share, for proceeds of $231.3 million , net of offering costs. The Company used the net proceeds from the common stock offering to repay a portion of the borrowings under the Company’s revolving credit facility and for general corporate purposes. Exercise of Warrants On November 24, 2009, the Company entered into an agreement with an unrelated third party and its affiliate under which the Company issued 118,200 warrants to purchase shares of the Company’s common stock. In May 2015, the holders of the warrants exercised all warrants outstanding on a “cashless” basis at an exercise price of $22.09 resulting in the issuance of 71,913 shares of the Company’s common stock. Stock-Based Compensation Plans The Company has established the Incentive Plan of Carrizo Oil & Gas, Inc., as amended (the “Incentive Plan”), which authorizes the granting of stock options, SARs that may be settled in cash or common stock at the option of the Company, restricted stock awards, restricted stock units and performance share awards to employees and independent contractors. The Incentive Plan also authorizes the granting of stock options, restricted stock awards and restricted stock units to non-employee directors. On May 15, 2014, the Incentive Plan was amended and restated, to increase the number of shares available for issuance under the Incentive Plan. The Company may grant awards covering up to 10,822,500 shares (subject to certain limitations) under the Incentive Plan, and at December 31, 2016 , there were 2,938,889 common shares remaining available for grant under the Incentive Plan. The Company has also established the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The Cash SAR Plan authorizes the granting of SARs to employees and independent contractors that may only be settled in cash. Restricted Stock Awards and Units. The Company grants restricted stock awards and units to employees and independent contractors and grants restricted stock units to non-employee directors. Restricted stock awards are treated as issued and outstanding as of the grant date because the shares of common stock are issued in the name of employees, but held by the Company until the restrictions are satisfied. Rights to dividends or dividend equivalents may be extended to restricted stock awards discretion of the Compensation Committee of the Board of Directors, but are held by the Company during the vesting period and paid, without interest, within 10 days following the vesting. If restricted stock awards are forfeited, any dividends or dividend equivalents paid with respect to those restricted stock awards are also forfeited. Restricted stock units are not considered issued and outstanding until the shares of common stock are issued to the employee upon vesting. Restricted stock units are payable, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock on the vesting date. Most restricted stock awards and units contain a service condition, and certain restricted stock units also contain performance conditions. The performance conditions have been met for all outstanding restricted stock units. The table below summarizes restricted stock award and unit activity for the years ended December 31, 2016 , 2015 and 2014 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2014 Unvested restricted stock awards and units, beginning of period 1,444,867 $28.03 Granted 576,812 $48.64 Vested (647,306 ) $32.64 Forfeited (38,691 ) $32.89 Unvested restricted stock awards and units, end of period 1,335,682 $34.55 For the Year Ended December 31, 2015 Unvested restricted stock awards and units, beginning of period 1,335,682 $34.55 Granted 401,421 $51.45 Vested (671,417 ) $32.96 Forfeited (23,689 ) $43.36 Unvested restricted stock awards and units, end of period 1,041,997 $44.22 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 The aggregate fair value of restricted stock awards and units that vested during the years ended December 31, 2016 , 2015 and 2014 was $26.3 million , $32.0 million and $37.3 million , respectively. As of December 31, 2016 , unrecognized compensation costs related to unvested restricted stock awards and units was $17.3 million and will be recognized over a weighted average period of 1.8 years. Stock Appreciation Rights. SARs can be granted to employees and independent contractors under the Incentive Plan or the Cash SAR Plan. SARs granted under the Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. The settlement amount upon exercise is calculated as the difference between the fair market value of common stock on the date of exercise and the fair market value of common stock on the grant date price multiplied by the number of SARs exercised. All SARs contain service and performance conditions. The performance conditions have been met for all outstanding SARs. The table below summarizes the activity for SARs for the years ended December 31, 2016 , 2015 and 2014 : 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, 2014 Outstanding, beginning of period 1,086,231 $24.78 Granted — — Exercised (321,033 ) $30.24 $7.8 Forfeited — — Outstanding, end of period 765,198 $22.49 Exercisable, end of period 587,481 $20.78 For the Year Ended December 31, 2015 Outstanding, beginning of period 765,198 $22.49 Granted — — Exercised (64,745 ) $29.40 $1.5 Forfeited — — Outstanding, end of period 700,453 $21.86 Exercisable, end of period 626,661 $21.05 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 — — Outstanding, end of period 722,638 $23.69 2.4 $10.1 Exercisable, end of period 350,840 $19.87 0.5 $6.2 As of December 31, 2016 , the liability for SARs was $11.5 million , of which, $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2015 , the liability for SARs outstanding was $7.0 million , which was classified as “Other current liabilities.” As of December 31, 2016 , unrecognized compensation costs related to unvested SARs was $3.0 million and will be recognized over a weighted average period of 1.2 years. The grant date fair value of the SARs was calculated using the Black-Scholes-Merton option pricing model that used the assumptions described below: • Expected term - The expected term represents the period of time that SARs are expected to be outstanding, which is the grant date to the date of expected exercise. The expected term is based on historical exercises for various groups of employees and independent contractors. • Expected volatility - The expected volatility represents the extent to which the market price of the Company’s common stock price is expected to fluctuate between the grant date and the expected term of the SAR. The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date. • Risk-free interest rate - The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant. • Dividend yield - The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future. No SARs were granted during the years ended December 31, 2015 and 2014. The following table summarizes the assumptions used to calculate the fair value of SARs granted during the year ended December 31, 2016 : Year Ended December 31, 2016 Expected term (in years) 3.93 Expected volatility 45.1 % Risk-free interest rate 1.3 % Dividend yield — % Grant date fair value $9.88 Performance Share Awards. The Company grants performance share awards to employees and independent contractors, where each performance share represents the value of one share of common stock. Performance share awards are payable, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock on the vesting date. The number of performance shares that will vest ranges from zero to 200% of the 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. The performance share awards also contain service and performance conditions. The performance conditions have been met for all performance share awards. The table below summarizes performance share award activity for the years ended December 31, 2016 , 2015 and 2014 : Performance Share Awards Weighted Average Grant Date Fair Value For the Year Ended December 31, 2014 Unvested performance share awards, beginning of period — — Granted 56,342 $68.15 Vested — — Forfeited — — Unvested performance share awards, end of period 56,342 $68.15 For the Year Ended December 31, 2015 Unvested performance share awards, beginning of period 56,342 $68.15 Granted 56,517 $65.51 Vested — — Forfeited — — Unvested performance share awards, end of period 112,859 $66.83 For the Year Ended December 31, 2016 Unvested performance share awards, beginning of period 112,859 $66.83 Granted 41,651 $35.71 Vested — — Forfeited — — Unvested performance share awards, end of period 154,510 $58.44 As of December 31, 2016 , unrecognized compensation costs related to unvested performance share awards was $2.9 million and will be recognized over a weighted average period of 1.5 years. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the Company’s TSR relative to the TSR achieved by the specified industry peer group over the performance period results in the vesting of zero performance share awards. The grant date fair value of the performance share awards was determined using the Monte Carlo simulation. The Monte Carlo simulation is based on random projections of stock price paths that are repeated numerous times to achieve a probabilistic assessment. The assumptions used in the Monte Carlo simulation are described below: • Expected term - The expected term represents the period of time that the performance share awards will be outstanding, which is the grant date to the end of the performance period. • Expected volatility - The expected volatility represents the extent to which the market price of the Company’s common stock price is expected to fluctuate between the grant date and the end of the performance period. The volatility of the Company’s common stock and the industry peer group is based on daily, historical volatility of the market price each company’s common stock over a period of time equal to the expected term and ending on the grant date. • Risk-free interest rate - The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant. • Dividend yield - The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future. The following table summarizes the assumptions used to calculate the fair value of the performance share awards granted during the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, 2016 2015 2014 Number of simulations 500,000 500,000 500,000 Expected term (in years) 3.01 2.89 2.97 Expected volatility 55.3 % 45.3 % 49.9 % Risk-free interest rate 1.2 % 0.9 % 0.9 % Dividend yield — % — % — % Grant date fair value $35.71 $53.58 $53.96 Stock Options. The Company may grant stock options to employees, independent contractors and non-employee directors. Stock options can be settled, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock on the exercise date. The fair market value of common stock on the date of exercise must not be less than the fair market value of the common stock on the date of grant. The table below summarizes the activity for stock options for the years ended December 31, 2016 , 2015 and 2014 : Stock Options Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Cash Received from Exercises (In millions) Tax Benefit Realized from Exercises (In millions) For the Year Ended December 31, 2014 Outstanding, beginning of period 36,353 $13.91 Granted — — Exercised (33,086 ) $13.20 $1.3 $0.4 $0.4 Forfeited — — Expired (834 ) $27.25 Outstanding, end of period 2,433 $19.02 0.5 $0.1 Exercisable, end of period 2,433 $19.02 0.5 $0.1 For the Year Ended December 31, 2015 Outstanding, beginning of period 2,433 $19.02 Granted — — Exercised (2,433 ) $19.02 $0.1 — $0.1 Forfeited — — Outstanding, end of period — — 0 — Exercisable, end of period — — 0 — The Company last granted stock options in 2005 and the final exercise of outstanding stock options occurred during 2015. Stock-Based Compensation Expense, Net The Company recognized the following stock-based compensation expense, net for the periods indicated: Years Ended December 31, 2016 2015 2014 (In thousands) Restricted stock awards and units $28,196 $23,668 $29,597 Stock appreciation rights 9,675 (6,326 ) 1,985 Performance share awards 2,806 1,961 1,395 40,677 19,303 32,977 Less: amounts capitalized to oil and gas properties (4,591 ) (4,574 ) (7,099 ) Total stock-based compensation expense, net $36,086 $14,729 $25,878 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 10. Related Party Transactions Avista Joint Ventures . Effective August 2008, the Company’s wholly owned subsidiary Carrizo (Marcellus) LLC entered into a joint venture arrangement with ACP II Marcellus LLC (“ACP II”), an affiliate of Avista Capital Partners, LP, a private equity fund. Effective September 2011, the Company’s wholly-owned subsidiary, Carrizo (Utica) LLC, entered into a joint venture in the Utica with ACP II and ACP III Utica LLC (“ACP III”), an affiliate of ACP II and Avista Capital Partners, LP. (collectively with ACP II and ACP III, “Avista”). During the term of the Avista joint ventures, the joint venture partners acquired and sold acreage and the Company exercised options under the applicable Avista joint venture agreements to acquire acreage from Avista. The Avista Utica joint venture agreements were terminated on October 31, 2013 in connection with the Company’s purchase of certain ACP III assets. After giving effect to such transaction, the Company and Avista remain working interest partners in Utica with the Company acting as the operator of the jointly owned properties which are now subject to standard joint operating agreements. The joint operating agreements with Avista provide for limited areas of mutual interest around properties jointly owned by the Company and Avista. Carrizo Relationship with Avista. Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which entity has the ability to control Avista and its affiliates. As previously disclosed, the Company has been and is a party to prior arrangements with affiliates of Avista Capital Holdings, LP. The terms of the joint ventures with Avista in the Utica and the Marcellus and a related prior acquisition transaction were each separately approved by a special committee of the Company’s independent, non-employee directors. In determining whether to approve or disapprove a transaction, such special committee has determined whether the transaction is desirable and in the best interest of the Company and has evaluated such transaction is fair to the Company and its shareholders on the same basis as comparable arm’s length transactions. The committee has applied, and may in other transactions also apply, standards under relevant debt agreements if required. Amounts due from Avista and Affiliates . As of December 31, 2016 and 2015 , related party receivable on the consolidated balance sheets included $0.9 million and $2.4 million , respectively, representing the net amounts ACP II and ACP III owes the Company related to activity within the Avista Marcellus and Avista Utica joint ventures. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | 11. Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments may consist of fixed price swaps, costless collars, three-way collars and purchased and sold call options, which are described below. Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes. Costless Collars: A collar is a combination of options including a purchased put option (fixed floor price) and a sold call option (fixed ceiling price) and allows the Company to benefit from increases in commodity prices up to the fixed ceiling price and protect the Company from decreases in commodity prices below the fixed floor price. At settlement, if the market price is below the fixed floor price or is above the fixed ceiling price, the Company receives the fixed price or pays the market price, respectively. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. These contracts are executed contemporaneously with the same counterparties and are premium neutral such that no premiums are paid to or received from the counterparties. Three-Way Collars: A three-way collar is a combination of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the market price is between the fixed floor price and the fixed sub-floor price or is above the fixed ceiling price, the Company receives the fixed price or pays the market price, respectively. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. These contracts are executed contemporaneously with the same counterparties and are premium neutral such that no premiums are paid to or received from the counterparties. Sold Call Options : These contracts give the counterparties the right, but not the obligation, to buy contracted volumes from the Company over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the counterparties to pay premiums to the Company that represent the fair value of the call option as of the date of purchase. In lieu of receiving payments for premiums from the counterparties, the Company uses the associated premium value to obtain a higher fixed price on fixed price swaps which are executed contemporaneously with the sold call options. Purchased Call Options : These contracts give the Company the right, but not the obligation, to buy contracted volumes from the counterparties over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the counterparties pay the Company the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the Company to pay premiums to the counterparties that represent the fair value of the call option as of the date of purchase. The payments of the premiums are deferred until the purchased call option contracts settle on a monthly basis. The Company purchases call options contemporaneously with sales of call options to increase the fixed price of existing sold call options and therefore are presented on a net basis in the summary of open crude oil derivative positions below. The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of December 31, 2016 : Period Type of Contract Crude Oil Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1 2017 Fixed Price Swaps 12,000 $50.13 Q2 2017 Fixed Price Swaps 12,000 $50.13 Q3 2017 Fixed Price Swaps 6,000 $54.15 Q4 2017 Fixed Price Swaps 3,000 $55.01 FY 2018 Sold Call Options 2,488 $60.00 FY 2018 Net Sold Call Options 900 $75.00 FY 2019 Sold Call Options 2,975 $62.50 FY 2019 Net Sold Call Options 900 $77.50 FY 2020 Sold Call Options 3,675 $65.00 FY 2020 Net Sold Call Options 900 $80.00 The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of December 31, 2016 : Period Type of Contract Natural Gas Volumes Weighted Weighted FY 2017 Fixed Price Swaps 20,000 $3.30 FY 2017 Sold Call Options 33,000 $3.00 FY 2018 Sold Call Options 33,000 $3.25 FY 2019 Sold Call Options 33,000 $3.25 FY 2020 Sold Call Options 33,000 $3.50 The Company typically has numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period, including the deferred premiums associated with its hedge positions. The Company nets its derivative instrument fair values executed with the same counterparty pursuant to ISDA master agreements, 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 derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds our unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral. Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’ investment grade parent company, 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 derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties or its counterparty parent company. Derivative Assets and Liabilities All derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. The combined derivative instrument fair value assets and liabilities recorded in the Company’s consolidated balance sheets as of December 31, 2016 and 2015 is summarized below: December 31, 2016 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $6,507 ($5,270 ) $1,237 Derivative assets-non current 1,313 (1,313 ) — Derivative liabilities Derivative liabilities-current (27,871 ) 5,270 (22,601 ) Derivative liabilities-non current (28,841 ) 1,313 (27,528 ) Total ($48,892 ) $— ($48,892 ) December 31, 2015 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $159,447 ($28,347 ) $131,100 Derivative assets-non current 10,780 (9,665 ) 1,115 Derivative liabilities Other current liabilities (28,364 ) 28,347 (17 ) Derivative liabilities-non current (22,313 ) 9,665 (12,648 ) Total $119,550 $— $119,550 See “Note 12. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative positions. (Gain) Loss on Derivatives, Net The Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of derivative instruments are recognized as (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the changes occur. The effect of derivative instruments on the Company’s consolidated statements of operations for the years ended December 31, 2016 , 2015 , and 2014 by commodity is summarized below: Years Ended December 31, 2016 2015 2014 (In thousands) (Gain) Loss on Derivatives, Net Crude oil $29,391 ($95,199 ) ($191,351 ) Natural gas 19,682 (4,062 ) (10,556 ) Total (Gain) Loss on Derivatives, Net $49,073 ($99,261 ) ($201,907 ) |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 12. 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 assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015 : December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Derivative assets $— $1,237 $— Derivative liabilities $— ($45,552 ) $— December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Derivative assets $— $132,215 $— Derivative liabilities $— ($8,239 ) $— The Company uses Level 2 inputs to measure the fair value of the Company’s commodity derivative instruments 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 and volatility factors. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities. The derivative 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. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the years ended December 31, 2016 and 2015 . Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate. See “Note 3. Acquisitions” for further discussion of the Company’s acquisitions. The fair value measurements of asset retirement obligations are measured on a nonrecurring basis when a well is drilled or acquired or when production equipment and facilities are installed or acquired using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. 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 details regarding the Company's asset retirement obligations for the years ended December 31, 2016 and 2015 . Fair Value of Other Financial Instruments The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt, which are classified as Level 1 under the fair value hierarchy. 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 carrying amounts of the Company’s senior notes and other long-term debt, net of debt premiums and debt issuance costs, with the fair values measured using Level 1 inputs based on quoted secondary market trading prices. December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) 7.50% Senior Notes due 2020 $593,447 $624,750 $592,203 $528,000 6.25% Senior Notes due 2023 $640,546 $672,750 $639,389 $533,000 Other long-term debt due 2028 $4,425 $4,419 $4,425 $4,182 |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Consolidating Financial Information [Abstract] | |
Condensed Consolidating Financial Information | 13. 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, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,735,830 $63,513 $— ($2,726,355 ) $72,988 Total property and equipment, net 42,181 1,503,695 3,800 (3,916 ) 1,545,760 Investment in subsidiaries (1,282,292 ) — — 1,282,292 — Other assets 7,423 156 — — 7,579 Total Assets $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 Liabilities and Shareholders’ Equity Current liabilities $114,805 $2,822,729 $3,800 ($2,729,375 ) $211,959 Long-term liabilities 1,348,105 26,927 — 15,878 1,390,910 Total shareholders’ equity 40,232 (1,282,292 ) — 1,265,518 23,458 Total Liabilities and Shareholders’ Equity $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,578,034 $52,067 $— ($2,397,919 ) $232,182 Total property and equipment, net 44,499 1,671,774 3,059 (2,471 ) 1,716,861 Investment in subsidiaries (815,836 ) — — 815,836 — Other assets 74,679 156 — (16,632 ) 58,203 Total Assets $1,881,376 $1,723,997 $3,059 ($1,601,186 ) $2,007,246 Liabilities and Shareholders’ Equity Current liabilities $161,792 $2,521,572 $3,059 ($2,400,939 ) $285,484 Long-term liabilities 1,260,200 18,261 — (753 ) 1,277,708 Total shareholders’ equity 459,384 (815,836 ) — 800,506 444,054 Total Liabilities and Shareholders’ Equity $1,881,376 $1,723,997 $3,059 ($1,601,186 ) $2,007,246 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) 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 from continuing operations before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax benefit — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Loss from continuing operations ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Income from discontinued operations, net of income taxes — — — — — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $1,708 $427,495 $— $— $429,203 Total costs and expenses 95,464 1,603,515 — 28,984 1,727,963 Loss from continuing operations before income taxes (93,756 ) (1,176,020 ) — (28,984 ) (1,298,760 ) Income tax benefit 10,125 127,010 — 3,740 140,875 Equity in loss of subsidiaries (1,049,010 ) — — 1,049,010 — Loss from continuing operations ($1,132,641 ) ($1,049,010 ) $— $1,023,766 ($1,157,885 ) Income from discontinued operations, net of income taxes 2,731 — — — 2,731 Net loss ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $3,938 $706,121 $128 $— $710,187 Total costs and expenses (76,531 ) 442,343 30 (5,865 ) 359,977 Income from continuing operations before income taxes 80,469 263,778 98 5,865 350,210 Income tax expense (28,164 ) (92,322 ) — (7,441 ) (127,927 ) Equity in income of subsidiaries 171,554 — — (171,554 ) — Income from continuing operations $223,859 $171,456 $98 ($173,130 ) $222,283 Income from discontinued operations, net of income taxes 4,060 — — — 4,060 Net income $227,919 $171,456 $98 ($173,130 ) $226,343 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities from continuing operations (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities from continuing operations 308,340 268,283 740 (269,023 ) 308,340 Net cash used in discontinued operations — — — — — 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 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities from continuing operations $2,655 $376,080 $— $— $378,735 Net cash used in investing activities from continuing operations (447,296 ) (674,758 ) — 448,678 (673,376 ) Net cash provided by financing activities from continuing operations 480,767 298,678 — (448,678 ) 330,767 Net cash used in discontinued operations (4,046 ) — — — (4,046 ) Net increase in cash and cash equivalents 32,080 — — — 32,080 Cash and cash equivalents, beginning of year 10,838 — — — 10,838 Cash and cash equivalents, end of year $42,918 $— $— $— $42,918 Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($132,683 ) $634,970 ($12 ) $— $502,275 Net cash used in investing activities from continuing operations (305,718 ) (906,509 ) (37,609 ) 309,160 (940,676 ) Net cash provided by financing activities from continuing operations 300,290 271,539 37,621 (309,160 ) 300,290 Net cash used in discontinued operations (8,490 ) — — — (8,490 ) Net decrease in cash and cash equivalents (146,601 ) — — — (146,601 ) Cash and cash equivalents, beginning of year 157,439 — — — 157,439 Cash and cash equivalents, end of year $10,838 $— $— $— $10,838 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Disclosures | 14. Supplemental Cash Flow Information Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Years Ended December 31, 2016 2015 2014 (In thousands) Supplemental cash flow disclosures: Cash paid for interest, net of amounts capitalized $75,231 $64,692 $49,379 Cash paid for income taxes — — — Non-cash investing and financing activities: Increase (decrease) in capital expenditure payables and accruals ($21,492 ) ($86,878 ) $45,716 Liabilities assumed in connection with the Sanchez Acquisition 4,880 — — Stock-based compensation expense capitalized to oil and gas properties 4,591 4,574 7,099 Asset retirement obligations capitalized to oil and gas properties 1,927 4,853 4,545 Purchase price adjustments related to the Eagle Ford Shale Acquisition — — 3,197 EFM deferred purchase payment — — 148,900 Other non-cash investing activities (1) 10,068 22,562 2,244 (1) Other non-cash investing activities primarily includes property exchanges and capital lease transactions. |
Supplemental Disclosures About
Supplemental Disclosures About Oil And Gas Producing Activities | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental Disclosures About Oil And Gas Producing Activities | 15. 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, 2016 2015 2014 (In thousands) Property acquisition costs Proved properties $90,661 $— $183,633 Unproved properties 113,535 63,446 215,021 Total property acquisition costs 204,196 63,446 398,654 Exploration costs 37,508 117,227 194,956 Development costs 374,134 389,396 530,268 Total costs incurred $615,838 $570,069 $1,123,878 Costs incurred exclude capitalized interest on unproved properties of $17.0 million , $32.1 million , and $34.5 million for the years ended December 31, 2016 , 2015 and 2014 , 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 , $4.9 million and $4.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Non-cash additions related to the estimated future asset retirement obligations associated with the Sanchez Acquisition of $2.0 million are included in acquisition costs of proved properties for the year ended December 31, 2016 . The internal cost of employee compensation and benefits, including stock-based compensation, capitalized to proved or unproved oil and gas properties of $10.5 million , $15.8 million and $18.8 million for the years ended December 31, 2016 , 2015 and 2014 , 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, 2016 , 2015 , and 2014 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, 2014 62,041 8,152 187,957 101,519 Extensions and discoveries 29,793 3,681 30,343 38,531 Revisions of previous estimates 3,046 1,270 18,913 7,469 Purchases of reserves in place 12,730 1,335 8,681 15,512 Production (6,906 ) (925 ) (24,877 ) (11,978 ) December 31, 2014 100,704 13,513 221,017 151,053 Extensions and discoveries 26,358 5,292 33,925 37,304 Revisions of previous estimates (9,059 ) 2,768 11,808 (4,323 ) Production (8,415 ) (1,352 ) (21,812 ) (13,402 ) December 31, 2015 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 Proved developed reserves: December 31, 2013 18,321 2,779 106,976 38,929 December 31, 2014 35,238 5,294 149,697 65,482 December 31, 2015 42,311 7,933 154,725 76,032 December 31, 2016 51,062 9,387 187,054 91,625 Proved undeveloped reserves: December 31, 2013 43,720 5,373 80,981 62,590 December 31, 2014 65,466 8,219 71,320 85,571 December 31, 2015 67,277 12,288 90,213 94,600 December 31, 2016 77,256 14,550 100,391 108,538 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 our drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20% , respectively, of the total extensions and discoveries. For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through our drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries. For the year ended December 31, 2014, the Company added 5,483 MBoe of proved developed reserves and 33,048 MBoe of proved undeveloped reserves through our drilling program and associated offset locations. Eagle Ford comprised 92% of the total extensions and discoveries. Revisions of previous estimates 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 due to performance 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 our 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 our 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. For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives; • Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus. For the year ended December 31, 2014, revisions of previous estimates increased the Company’s proved reserves by 7,469 MBoe. Included in revisions of previous estimates were positive revisions due to price primarily in Marcellus. Purchases of reserves in place 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. There were no purchases of reserves in place for the year ended December 31, 2015. For the year ended December 31, 2014, purchases of reserves in place included 4,144 MBoe of proved developed reserves and 11,369 MBoe of proved undeveloped reserves associated with the Eagle Ford Shale Acquisition. Standardized Measure The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2016 2015 2014 (In thousands) Future cash inflows $5,903,629 $5,878,348 $10,380,951 Future production costs (2,241,928 ) (2,124,059 ) (2,532,106 ) Future development costs (1,264,493 ) (1,178,773 ) (1,680,795 ) Future income taxes (1) — — (1,354,524 ) Future net cash flows 2,397,208 2,575,516 4,813,526 Less 10% annual discount to reflect timing of cash flows (1,093,779 ) (1,210,292 ) (2,258,444 ) Standard measure of discounted future net cash flows $1,303,429 $1,365,224 $2,555,082 (1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, 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 our proved oil and gas reserves as of December 31, 2016 and 2015. 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 average realized prices used for 2016 , 2015 and 2014 were $39.60 , $47.24 , and $92.24 per Bbl, respectively, for crude oil, $11.66 , $12.00 and $27.80 per Bbl, respectively, for NGLs, and $1.89 , $1.87 and $3.24 per Mcf, respectively, for natural gas. 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 are based on year-end 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, 2016 2015 2014 (In thousands) Standardized measure at beginning of year $1,365,224 $2,555,082 $1,621,411 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ($346,763 ) ($2,547,213 ) ($240,533 ) Net change in estimated future development costs 74,407 342,238 89,401 Net change due to revisions in quantity estimates (150,245 ) (157,271 ) 205,166 Accretion of discount 136,522 326,074 202,672 Changes in production rates (timing) and other (111,137 ) (139,533 ) (61,099 ) Total revisions to reserves proved in prior years (397,216 ) (2,175,705 ) 195,607 Net change due to extensions and discoveries, net of estimated future development and production costs 313,201 252,155 867,615 Net change due to purchases of reserves in place 43,426 — 352,867 Sales of crude oil, NGLs and natural gas produced, net of production costs (320,272 ) (312,213 ) (598,036 ) Previously estimated development costs incurred 299,066 340,247 415,963 Net change in income taxes (1) — 705,658 (300,345 ) Net change in standardized measure of discounted future net cash flows (61,795 ) (1,189,858 ) 933,671 Standardized measure at end of year $1,303,429 $1,365,224 $2,555,082 (1) Net change in income taxes in the calculation of changes in standardized measure of discounted future net cash flows was zero as of December 31, 2016 as the future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015. See discussion in the note above as to why future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015. |
Selected Quarterly Financial Da
Selected Quarterly Financial Data | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data | 16. Quarterly Financial Data (Unaudited) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2016 and 2015 : Year Ended December 31, 2016 First Quarter (2) Second Quarter (2) Third Quarter (2) Fourth Quarter (In thousands, except per share data) Total revenues $81,262 $107,324 $111,177 $143,831 Operating profit (loss) (1) ($7,491 ) $27,167 $31,634 $55,000 Loss from continuing operations ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss per common share - basic Loss from continuing operations (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Net loss (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Net loss per common share - diluted Loss from continuing operations (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Net loss (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Year Ended December 31, 2015 First Quarter Second Quarter (3) Third Quarter (4) Fourth Quarter (4) (In thousands, except per share data) Total revenues $100,050 $123,494 $106,237 $99,422 Operating profit (loss) (1) ($2,588 ) $14,034 ($3,752 ) $4,484 Loss from continuing operations ($21,476 ) ($46,970 ) ($708,768 ) ($380,671 ) Net loss ($21,210 ) ($46,132 ) ($707,647 ) ($380,165 ) Net loss per common share - basic Loss from continuing operations (5) ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss (5) ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) Net loss per common share - diluted Loss from continuing operations (5) ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss (5) ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) (1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A. (2) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million , $197.1 million , and $105.1 million , respectively. (3) In the second quarter of 2015, the Company recognized a loss on extinguishment of debt of $38.1 million as a result of the cash tender offer and redemption of the 8.625% Senior Notes. (4) In the third quarter and fourth quarter of 2015, the Company recognized impairments of proved oil and gas properties of $812.8 million and $411.6 million , respectively. Primarily as a result of the impairments of proved oil and gas properties, since the third quarter of 2015, the Company recorded a valuation allowance against its net deferred tax assets reducing them to zero . (5) The sum of quarterly net loss per common share does not agree with the total year net loss per common share as each computation is based on the weighted average of common shares outstanding during the period. |
Summary Of Significant Accoun23
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
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. The Company evaluates subsequent events through the date the financial statements are issued. 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 costs and 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 derivative assets and liabilities, 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 $34.3 million and $49.1 million as of December 31, 2016 and 2015 , respectively. |
Accounts Receivable | Accounts Receivable The Company establishes an allowance for doubtful accounts when it determines 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. As of December 31, 2016 and 2015 , the Company’s allowance for doubtful accounts was $0.8 million and $1.0 million , respectively. |
Concentration of Credit Risk | Concentration of Credit Risk The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in 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 generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners. |
Major Customers | Major Customers Shell Trading (US) Company accounted for approximately 56% , 65% , and 44% of the Company’s total revenues in 2016 , 2015 , and 2014 , respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 15% , 9% and 26% of the Company’s total revenues in 2016 , 2015 and 2014 , respectively. |
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 and totaled $10.5 million , $15.8 million and $18.8 million for the years ended December 31, 2016, 2015 and 2014 , respectively. 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. Average DD&A per Boe of proved oil and gas properties was $13.50 , $22.05 and $26.20 for the years ended December 31, 2016, 2015 and 2014 , respectively. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost of exploratory wells in progress, and related capitalized interest. Exploratory wells in progress and 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 and completion 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. The Company capitalized interest costs associated with its unproved properties totaling $17.0 million , $32.1 million and $34.5 million for the years ended December 31, 2016, 2015 and 2014 , respectively. 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, natural gas liquids 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 derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million , respectively, due primarily to declines in the 12-Month Average Realized Price of crude oil. See “Note 4. Property and Equipment, Net” for further details of the impairments. 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, 2016 , 2015 and 2014 , 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 amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. See “—Recently Adopted Accounting Pronouncements” below for discussion of classification debt issuance costs in the consolidated balance sheets. |
Financial Instruments | Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities 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 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 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 12. Fair Value Measurements.” |
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 from continuing operations 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 well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.” |
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.” |
Revenue Recognition | Revenue Recognition Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2016 and 2015 , the Company did not have any material production imbalances. |
Derivative Instruments | Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. All derivative instruments are recorded on the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews derivative instruments, including volumes, types of instruments and counterparties. These policies require that 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 11. Derivative Instruments” for further discussion of the Company’s derivative instruments. |
Stock-Based Compensation | Stock-Based Compensation The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. 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 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 SARs, stock-based compensation expense is initially based on the grant date fair value (using the Black-Scholes-Merton option pricing model) with the liability subsequently remeasured at each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. Each award includes a performance condition that must be met in order for that award to vest. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the value of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. Performance Share Awards. For performance share awards, 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 award includes a performance condition that must be met in order for that award to vest. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved. See “Note 9. Shareholders’ Equity and Stock Based Compensation Plans.” |
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 bases of assets and liabilities and their reported amounts in the Company’s 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 whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether 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 | Income (Loss) From Continuing Operations Per Common Share Basic income (loss) from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted income from continuing operations 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 share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and 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 share awards 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. When a loss from continuing operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. Supplemental income (loss) from continuing operations per common share information is provided below: Years Ended December 31, 2016 2015 2014 (In thousands, except per share amounts) Income (Loss) From Continuing Operations ($675,474 ) ($1,157,885 ) $222,283 Basic weighted average common shares outstanding 59,932 51,457 45,372 Effect of dilutive instruments: Restricted stock awards and units — — 684 Performance share awards — — 56 Stock options — — 13 Warrants — — 69 Diluted weighted average common shares outstanding 59,932 51,457 46,194 Income (Loss) From Continuing Operations Per Common Share Basic ($11.27 ) ($22.50 ) $4.90 Diluted ($11.27 ) ($22.50 ) $4.81 For the years ended December 31, 2016 and 2015 , the Company reported a loss from continuing operations and therefore the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 0.7 million and 0.6 million potentially dilutive common shares outstanding, respectively. For the year ended December 31, 2014 , the number of potentially dilutive common shares outstanding excluded from the calculation of diluted weighted average shares outstanding was not significant. |
Recently Adopted Accounting Pronouncements | Recently Adopted Accounting Pronouncements In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 requires that all deferred tax liabilities and assets, as well as any related valuation allowance, be classified in the balance sheet as noncurrent rather than presenting the deferred tax liabilities and assets as net current or net noncurrent. Effective January 1, 2016, the Company early adopted ASU 2015-17 which was applied prospectively and therefore the adoption had no impact on the consolidated balance sheet as of December 31, 2015. In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 simplifies the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt rather than as an asset. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“ASU 2015-15”), which allows debt issuance costs associated with line-of-credit agreements to be deferred and presented as an asset in the balance sheet, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. Effective January 1, 2016, the Company adopted ASU 2015-03 and ASU 2015-15 and reclassified $19.7 million of unamortized debt issuance costs related to the Company’s senior notes from long-term assets to long-term debt in the consolidated balance sheet as of December 31, 2015. Debt issuance costs associated with the Company’s revolving credit facility remain classified as a long-term asset in the consolidated balance sheets. |
Recently Issued Accounting Pronouncements | Recently Issued Accounting Pronouncements In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (“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. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, provided that it is adopted in its entirety in the same period. The Company is evaluating ASU 2016-15 to determine what impact adoption of the new standard will have on its consolidated statements of cash flows. In March 2016, the FASB issued 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. The Company adopted ASU 2016-09 effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits is expected to result in a cumulative-effect adjustment of approximately $15.7 million , which would increase net deferred tax assets and increase the valuation allowance by the same amount as of the beginning of 2017, resulting in no impact to the consolidated statements of operations. The remaining provisions of this amendment are not expected to have a material effect on the Company’s consolidated financial statements and related disclosures. 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 asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. 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. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. The Company is evaluating ASU 2016-02 to determine what impact adoption of the new standard will have on its consolidated financial statements and related disclosures. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, timing, amount and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for interim and annual periods beginning after December 31, 2016. Companies are permitted to adopt ASU 2014-09 through the use of either the full retrospective approach or a modified retrospective approach. The Company is still in the process of assessing its contracts with customers and assessing their potential impact on the Company’s consolidated financial statements and related disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018. |
Summary Of Significant Accoun24
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | Supplemental income (loss) from continuing operations per common share information is provided below: Years Ended December 31, 2016 2015 2014 (In thousands, except per share amounts) Income (Loss) From Continuing Operations ($675,474 ) ($1,157,885 ) $222,283 Basic weighted average common shares outstanding 59,932 51,457 45,372 Effect of dilutive instruments: Restricted stock awards and units — — 684 Performance share awards — — 56 Stock options — — 13 Warrants — — 69 Diluted weighted average common shares outstanding 59,932 51,457 46,194 Income (Loss) From Continuing Operations Per Common Share Basic ($11.27 ) ($22.50 ) $4.90 Diluted ($11.27 ) ($22.50 ) $4.81 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The following presents the purchase price and the allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date: October 24, 2014 (In thousands) Assets Other current assets $485 Proved and unproved oil and gas properties 244,124 Total assets acquired $244,609 Liabilities Asset retirement obligations $423 Total liabilities assumed $423 Net Assets Acquired $244,186 The following presents the purchase price and the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. These amounts will be finalized as soon as possible, but no later than December 14, 2017. December 14, 2016 (In thousands) Assets Other current assets $477 Oil and gas properties Proved properties 90,661 Unproved properties 67,263 Total oil and gas properties 157,924 Total assets acquired $158,401 Liabilities Revenues and royalties payable $1,442 Other current liabilities 323 Asset retirement obligations 2,037 Other liabilities 1,078 Total liabilities assumed $4,880 Net Assets Acquired $153,521 |
Business Acquisition, Pro Forma Information [Table Text Block] | The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2014, and December 31, 2013, assuming the Eagle Ford Shale Acquisition had been completed as of January 1, 2013, including adjustments to reflect the 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 Eagle Ford Shale Acquisition. Year Ended December 31, 2014 (In thousands, except per share data) (Unaudited) Total revenues $761,199 Income From Continuing Operations $264,714 Income From Continuing Operations Per Common Share Basic $5.83 Diluted $5.73 Weighted Average Common Shares Outstanding Basic 45,372 Diluted 46,194 |
Property And Equipment, Net (Ta
Property And Equipment, Net (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Property and Equipment | As of December 31, 2016 and 2015 , total property and equipment, net consisted of the following: December 31, 2016 2015 Oil and gas properties, full cost method (In thousands) Proved properties $4,687,416 $3,976,511 Accumulated DD&A and impairments (3,392,749 ) (2,607,360 ) Proved properties, net 1,294,667 1,369,151 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 211,067 280,263 Exploratory wells in progress — 9,432 Capitalized interest 29,894 45,757 Total unproved properties, not being amortized 240,961 335,452 Other property and equipment 23,127 22,677 Accumulated depreciation (12,995 ) (10,419 ) Other property and equipment, net 10,132 12,258 Total property and equipment, net $1,545,760 $1,716,861 |
Schedule of Impairment of Oil and Gas Properties | Primarily due to declines in the 12-Month Average Realized Price of crude oil beginning in the third quarter of 2015, the Company recognized impairments of proved oil and gas properties for the years ended December 31, 2016 and 2015 as summarized in the table below: Years Ended December 31, 2016 2015 Impairment of proved oil and gas properties (in thousands) $576,540 $1,224,367 Beginning of period 12-Month Average Realized Price ($/Bbl) $47.24 $92.24 End of period 12-Month Average Realized Price ($/Bbl) $39.60 $47.24 Percent decrease in 12-Month Average Realized Price (16 %) (49 %) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule Of Components Of Income Tax (Expense) Benefit | The components of income tax expense (benefit) from continuing operations were as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Current income tax (expense) benefit U.S. Federal $— $— $— State — — — Total current income tax (expense) benefit — — — Deferred income tax (expense) benefit U.S. Federal — 131,502 (122,342 ) State — 9,373 (5,585 ) Total deferred income tax (expense) benefit — 140,875 (127,927 ) Total income tax (expense) benefit from continuing operations $— $140,875 ($127,927 ) |
Schedule Of Effective Income Tax Rate Reconciliation | The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Income (loss) from continuing operations before income taxes ($675,474 ) ($1,298,760 ) $350,210 Income tax (expense) benefit at the statutory rate 236,416 454,566 (122,574 ) State income tax (expense) benefit, net of U.S. Federal income taxes 3,894 9,373 (5,585 ) Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense — 1,671 — Deferred tax asset valuation allowance (240,864 ) (323,586 ) — Other 554 (1,149 ) 232 Total income tax (expense) benefit from continuing operations $— $140,875 ($127,927 ) |
Schedule Of Deferred Tax Assets And Liabilities | As of December 31, 2016 and 2015 , deferred tax assets and liabilities are comprised of the following: December 31, 2016 2015 (In thousands) Deferred income tax assets Net operating loss carryforward - U.S. Federal and State $221,063 $119,783 Oil and gas properties 309,848 232,786 Asset retirement obligations 7,434 5,779 Stock-based compensation 5,238 4,741 Derivative liabilities 17,545 4,433 Other 3,739 3,435 Deferred income tax assets 564,867 370,957 Deferred tax asset valuation allowance (564,434 ) (324,681 ) Net deferred income tax assets 433 46,276 Deferred income tax liabilities Derivative assets (433 ) (46,276 ) Net deferred income tax asset (liability) $— $— |
Schedule Of Net Deferred Income Assets And Liabilities | At December 31, 2016 and 2015 , the net deferred income tax asset (liability) is classified as follows: December 31, 2016 2015 (In thousands) Net current deferred income tax liability $— ($46,758 ) Net noncurrent deferred income tax asset — 46,758 Net deferred income tax asset (liability) $— $— |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule Of Debt | Long-term debt consisted of the following as of December 31, 2016 and 2015 : December 31, 2016 2015 (In thousands) Senior Secured Revolving Credit Facility $87,000 $— 7.50% Senior Notes due 2020 600,000 600,000 Unamortized premium for 7.50% Senior Notes 1,020 1,251 Unamortized debt issuance costs for 7.50% Senior Notes (7,573 ) (9,048 ) 6.25% Senior Notes due 2023 650,000 650,000 Unamortized debt issuance costs for 6.25% Senior Notes (9,454 ) (10,611 ) Other long-term debt due 2028 4,425 4,425 Long-term debt $1,325,418 $1,236,017 |
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 as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net. Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments Applicable Margin for Base Rate Loans Applicable Margin for Eurodollar Loans Commitment Fee Less than 25% 1.00% 2.00% 0.500% Greater than or equal to 25% but less than 50% 1.25% 2.25% 0.500% Greater than or equal to 50% but less than 75% 1.50% 2.50% 0.500% Greater than or equal to 75% but less than 90% 1.75% 2.75% 0.500% Greater than or equal to 90% 2.00% 3.00% 0.500% |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Roll Forward Of Asset Retirement Obligations | The following table sets forth asset retirement obligations for the years ended December 31, 2016 and 2015 : Years Ended December 31, 2016 2015 (In thousands) Beginning of year asset retirement obligations $16,511 $12,512 Liabilities incurred 2,137 3,227 Increase due to acquisition of oil and gas properties 2,037 — Liabilities settled (599 ) (1,966 ) Accretion expense 1,364 1,112 Revisions to estimated cash flows (210 ) 1,626 End of year asset retirement obligations 21,240 16,511 Current asset retirement obligations (included in other current liabilities) (392 ) (328 ) Non-current asset retirement obligations $20,848 $16,183 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Total Minimum Commitments From Long-Term Non-Cancelable Operating Leases, Drilling Rig, Seismic And Pipeline Volume Commitments | At December 31, 2016 , total minimum commitments from long-term, non-cancelable operating and capital leases, drilling rigs and minimum delivery commitments are as shown in the table below. The total minimum commitments related to the drilling rigs represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. The delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation throughput commitments. The Company may incur volume deficiency fees from time to time if it elects to voluntarily curtail production due to market or operational considerations. 2017 2018 2019 2020 2021 2022 and Thereafter Total (In thousands) Operating leases $4,438 $4,430 $4,412 $4,463 $4,450 $1,854 $24,047 Capital leases 1,856 1,823 1,800 1,050 — — 6,529 Drilling rig contracts 23,753 3,957 — — — — 27,710 Delivery commitments 8,134 8,611 7,298 4,826 3,680 291 32,840 Total $38,181 $18,821 $13,510 $10,339 $8,130 $2,145 $91,126 |
Shareholders' Equity And Stoc31
Shareholders' Equity And Stock Incentive Plan (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 , 2015 and 2014 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2014 Unvested restricted stock awards and units, beginning of period 1,444,867 $28.03 Granted 576,812 $48.64 Vested (647,306 ) $32.64 Forfeited (38,691 ) $32.89 Unvested restricted stock awards and units, end of period 1,335,682 $34.55 For the Year Ended December 31, 2015 Unvested restricted stock awards and units, beginning of period 1,335,682 $34.55 Granted 401,421 $51.45 Vested (671,417 ) $32.96 Forfeited (23,689 ) $43.36 Unvested restricted stock awards and units, end of period 1,041,997 $44.22 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 |
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity | The table below summarizes the activity for SARs for the years ended December 31, 2016 , 2015 and 2014 : 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, 2014 Outstanding, beginning of period 1,086,231 $24.78 Granted — — Exercised (321,033 ) $30.24 $7.8 Forfeited — — Outstanding, end of period 765,198 $22.49 Exercisable, end of period 587,481 $20.78 For the Year Ended December 31, 2015 Outstanding, beginning of period 765,198 $22.49 Granted — — Exercised (64,745 ) $29.40 $1.5 Forfeited — — Outstanding, end of period 700,453 $21.86 Exercisable, end of period 626,661 $21.05 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 — — Outstanding, end of period 722,638 $23.69 2.4 $10.1 Exercisable, end of period 350,840 $19.87 0.5 $6.2 |
Schedule of Share-based Payment Award, Non-Options, Valuation Assumptions | The following table summarizes the assumptions used to calculate the fair value of SARs granted during the year ended December 31, 2016 : Year Ended December 31, 2016 Expected term (in years) 3.93 Expected volatility 45.1 % Risk-free interest rate 1.3 % Dividend yield — % Grant date fair value $9.88 |
Schedule of Share-based Compensation, Performance Shares Award Activity | The table below summarizes performance share award activity for the years ended December 31, 2016 , 2015 and 2014 : Performance Share Awards Weighted Average Grant Date Fair Value For the Year Ended December 31, 2014 Unvested performance share awards, beginning of period — — Granted 56,342 $68.15 Vested — — Forfeited — — Unvested performance share awards, end of period 56,342 $68.15 For the Year Ended December 31, 2015 Unvested performance share awards, beginning of period 56,342 $68.15 Granted 56,517 $65.51 Vested — — Forfeited — — Unvested performance share awards, end of period 112,859 $66.83 For the Year Ended December 31, 2016 Unvested performance share awards, beginning of period 112,859 $66.83 Granted 41,651 $35.71 Vested — — Forfeited — — Unvested performance share awards, end of period 154,510 $58.44 |
Schedule of Share-based Payment Award, Performance Share Award, Valuation Assumptions | The following table summarizes the assumptions used to calculate the fair value of the performance share awards granted during the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, 2016 2015 2014 Number of simulations 500,000 500,000 500,000 Expected term (in years) 3.01 2.89 2.97 Expected volatility 55.3 % 45.3 % 49.9 % Risk-free interest rate 1.2 % 0.9 % 0.9 % Dividend yield — % — % — % Grant date fair value $35.71 $53.58 $53.96 |
Summary Of Stock Options Activity | The table below summarizes the activity for stock options for the years ended December 31, 2016 , 2015 and 2014 : Stock Options Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Cash Received from Exercises (In millions) Tax Benefit Realized from Exercises (In millions) For the Year Ended December 31, 2014 Outstanding, beginning of period 36,353 $13.91 Granted — — Exercised (33,086 ) $13.20 $1.3 $0.4 $0.4 Forfeited — — Expired (834 ) $27.25 Outstanding, end of period 2,433 $19.02 0.5 $0.1 Exercisable, end of period 2,433 $19.02 0.5 $0.1 For the Year Ended December 31, 2015 Outstanding, beginning of period 2,433 $19.02 Granted — — Exercised (2,433 ) $19.02 $0.1 — $0.1 Forfeited — — Outstanding, end of period — — 0 — Exercisable, end of period — — 0 — |
Schedule of Compensation Cost, Allocation of Share-based Compensation Costs by Plan | The Company recognized the following stock-based compensation expense, net for the periods indicated: Years Ended December 31, 2016 2015 2014 (In thousands) Restricted stock awards and units $28,196 $23,668 $29,597 Stock appreciation rights 9,675 (6,326 ) 1,985 Performance share awards 2,806 1,961 1,395 40,677 19,303 32,977 Less: amounts capitalized to oil and gas properties (4,591 ) (4,574 ) (7,099 ) Total stock-based compensation expense, net $36,086 $14,729 $25,878 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Positions | The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of December 31, 2016 : Period Type of Contract Crude Oil Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1 2017 Fixed Price Swaps 12,000 $50.13 Q2 2017 Fixed Price Swaps 12,000 $50.13 Q3 2017 Fixed Price Swaps 6,000 $54.15 Q4 2017 Fixed Price Swaps 3,000 $55.01 FY 2018 Sold Call Options 2,488 $60.00 FY 2018 Net Sold Call Options 900 $75.00 FY 2019 Sold Call Options 2,975 $62.50 FY 2019 Net Sold Call Options 900 $77.50 FY 2020 Sold Call Options 3,675 $65.00 FY 2020 Net Sold Call Options 900 $80.00 The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of December 31, 2016 : Period Type of Contract Natural Gas Volumes Weighted Weighted FY 2017 Fixed Price Swaps 20,000 $3.30 FY 2017 Sold Call Options 33,000 $3.00 FY 2018 Sold Call Options 33,000 $3.25 FY 2019 Sold Call Options 33,000 $3.25 FY 2020 Sold Call Options 33,000 $3.50 |
Schedule of Derivative Instrument Fair Value Assets and Liabilities | The combined derivative instrument fair value assets and liabilities recorded in the Company’s consolidated balance sheets as of December 31, 2016 and 2015 is summarized below: December 31, 2016 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $6,507 ($5,270 ) $1,237 Derivative assets-non current 1,313 (1,313 ) — Derivative liabilities Derivative liabilities-current (27,871 ) 5,270 (22,601 ) Derivative liabilities-non current (28,841 ) 1,313 (27,528 ) Total ($48,892 ) $— ($48,892 ) December 31, 2015 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $159,447 ($28,347 ) $131,100 Derivative assets-non current 10,780 (9,665 ) 1,115 Derivative liabilities Other current liabilities (28,364 ) 28,347 (17 ) Derivative liabilities-non current (22,313 ) 9,665 (12,648 ) Total $119,550 $— $119,550 The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015 : December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Derivative assets $— $1,237 $— Derivative liabilities $— ($45,552 ) $— December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Derivative assets $— $132,215 $— Derivative liabilities $— ($8,239 ) $— |
Derivative Instruments, (Gain) Loss | The effect of derivative instruments on the Company’s consolidated statements of operations for the years ended December 31, 2016 , 2015 , and 2014 by commodity is summarized below: Years Ended December 31, 2016 2015 2014 (In thousands) (Gain) Loss on Derivatives, Net Crude oil $29,391 ($95,199 ) ($191,351 ) Natural gas 19,682 (4,062 ) (10,556 ) Total (Gain) Loss on Derivatives, Net $49,073 ($99,261 ) ($201,907 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | The combined derivative instrument fair value assets and liabilities recorded in the Company’s consolidated balance sheets as of December 31, 2016 and 2015 is summarized below: December 31, 2016 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $6,507 ($5,270 ) $1,237 Derivative assets-non current 1,313 (1,313 ) — Derivative liabilities Derivative liabilities-current (27,871 ) 5,270 (22,601 ) Derivative liabilities-non current (28,841 ) 1,313 (27,528 ) Total ($48,892 ) $— ($48,892 ) December 31, 2015 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $159,447 ($28,347 ) $131,100 Derivative assets-non current 10,780 (9,665 ) 1,115 Derivative liabilities Other current liabilities (28,364 ) 28,347 (17 ) Derivative liabilities-non current (22,313 ) 9,665 (12,648 ) Total $119,550 $— $119,550 The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015 : December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Derivative assets $— $1,237 $— Derivative liabilities $— ($45,552 ) $— December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Derivative assets $— $132,215 $— Derivative liabilities $— ($8,239 ) $— |
Schedule of Fair Value of Debt Instruments | The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of debt premiums and debt issuance costs, with the fair values measured using Level 1 inputs based on quoted secondary market trading prices. December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) 7.50% Senior Notes due 2020 $593,447 $624,750 $592,203 $528,000 6.25% Senior Notes due 2023 $640,546 $672,750 $639,389 $533,000 Other long-term debt due 2028 $4,425 $4,419 $4,425 $4,182 |
Condensed Consolidating Finan34
Condensed Consolidating Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Consolidating Financial Information [Abstract] | |
Condensed Consolidating Financial Information | 13. 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, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,735,830 $63,513 $— ($2,726,355 ) $72,988 Total property and equipment, net 42,181 1,503,695 3,800 (3,916 ) 1,545,760 Investment in subsidiaries (1,282,292 ) — — 1,282,292 — Other assets 7,423 156 — — 7,579 Total Assets $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 Liabilities and Shareholders’ Equity Current liabilities $114,805 $2,822,729 $3,800 ($2,729,375 ) $211,959 Long-term liabilities 1,348,105 26,927 — 15,878 1,390,910 Total shareholders’ equity 40,232 (1,282,292 ) — 1,265,518 23,458 Total Liabilities and Shareholders’ Equity $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,578,034 $52,067 $— ($2,397,919 ) $232,182 Total property and equipment, net 44,499 1,671,774 3,059 (2,471 ) 1,716,861 Investment in subsidiaries (815,836 ) — — 815,836 — Other assets 74,679 156 — (16,632 ) 58,203 Total Assets $1,881,376 $1,723,997 $3,059 ($1,601,186 ) $2,007,246 Liabilities and Shareholders’ Equity Current liabilities $161,792 $2,521,572 $3,059 ($2,400,939 ) $285,484 Long-term liabilities 1,260,200 18,261 — (753 ) 1,277,708 Total shareholders’ equity 459,384 (815,836 ) — 800,506 444,054 Total Liabilities and Shareholders’ Equity $1,881,376 $1,723,997 $3,059 ($1,601,186 ) $2,007,246 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) 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 from continuing operations before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax benefit — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Loss from continuing operations ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Income from discontinued operations, net of income taxes — — — — — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $1,708 $427,495 $— $— $429,203 Total costs and expenses 95,464 1,603,515 — 28,984 1,727,963 Loss from continuing operations before income taxes (93,756 ) (1,176,020 ) — (28,984 ) (1,298,760 ) Income tax benefit 10,125 127,010 — 3,740 140,875 Equity in loss of subsidiaries (1,049,010 ) — — 1,049,010 — Loss from continuing operations ($1,132,641 ) ($1,049,010 ) $— $1,023,766 ($1,157,885 ) Income from discontinued operations, net of income taxes 2,731 — — — 2,731 Net loss ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $3,938 $706,121 $128 $— $710,187 Total costs and expenses (76,531 ) 442,343 30 (5,865 ) 359,977 Income from continuing operations before income taxes 80,469 263,778 98 5,865 350,210 Income tax expense (28,164 ) (92,322 ) — (7,441 ) (127,927 ) Equity in income of subsidiaries 171,554 — — (171,554 ) — Income from continuing operations $223,859 $171,456 $98 ($173,130 ) $222,283 Income from discontinued operations, net of income taxes 4,060 — — — 4,060 Net income $227,919 $171,456 $98 ($173,130 ) $226,343 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities from continuing operations (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities from continuing operations 308,340 268,283 740 (269,023 ) 308,340 Net cash used in discontinued operations — — — — — 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 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities from continuing operations $2,655 $376,080 $— $— $378,735 Net cash used in investing activities from continuing operations (447,296 ) (674,758 ) — 448,678 (673,376 ) Net cash provided by financing activities from continuing operations 480,767 298,678 — (448,678 ) 330,767 Net cash used in discontinued operations (4,046 ) — — — (4,046 ) Net increase in cash and cash equivalents 32,080 — — — 32,080 Cash and cash equivalents, beginning of year 10,838 — — — 10,838 Cash and cash equivalents, end of year $42,918 $— $— $— $42,918 Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($132,683 ) $634,970 ($12 ) $— $502,275 Net cash used in investing activities from continuing operations (305,718 ) (906,509 ) (37,609 ) 309,160 (940,676 ) Net cash provided by financing activities from continuing operations 300,290 271,539 37,621 (309,160 ) 300,290 Net cash used in discontinued operations (8,490 ) — — — (8,490 ) Net decrease in cash and cash equivalents (146,601 ) — — — (146,601 ) Cash and cash equivalents, beginning of year 157,439 — — — 157,439 Cash and cash equivalents, end of year $10,838 $— $— $— $10,838 |
Schedule Of Condensed Consolidating Balance Sheets | CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,735,830 $63,513 $— ($2,726,355 ) $72,988 Total property and equipment, net 42,181 1,503,695 3,800 (3,916 ) 1,545,760 Investment in subsidiaries (1,282,292 ) — — 1,282,292 — Other assets 7,423 156 — — 7,579 Total Assets $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 Liabilities and Shareholders’ Equity Current liabilities $114,805 $2,822,729 $3,800 ($2,729,375 ) $211,959 Long-term liabilities 1,348,105 26,927 — 15,878 1,390,910 Total shareholders’ equity 40,232 (1,282,292 ) — 1,265,518 23,458 Total Liabilities and Shareholders’ Equity $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,578,034 $52,067 $— ($2,397,919 ) $232,182 Total property and equipment, net 44,499 1,671,774 3,059 (2,471 ) 1,716,861 Investment in subsidiaries (815,836 ) — — 815,836 — Other assets 74,679 156 — (16,632 ) 58,203 Total Assets $1,881,376 $1,723,997 $3,059 ($1,601,186 ) $2,007,246 Liabilities and Shareholders’ Equity Current liabilities $161,792 $2,521,572 $3,059 ($2,400,939 ) $285,484 Long-term liabilities 1,260,200 18,261 — (753 ) 1,277,708 Total shareholders’ equity 459,384 (815,836 ) — 800,506 444,054 Total Liabilities and Shareholders’ Equity $1,881,376 $1,723,997 $3,059 ($1,601,186 ) $2,007,246 |
Schedule Of Condensed Consolidating Statements Of Operations | CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) 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 from continuing operations before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax benefit — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Loss from continuing operations ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Income from discontinued operations, net of income taxes — — — — — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $1,708 $427,495 $— $— $429,203 Total costs and expenses 95,464 1,603,515 — 28,984 1,727,963 Loss from continuing operations before income taxes (93,756 ) (1,176,020 ) — (28,984 ) (1,298,760 ) Income tax benefit 10,125 127,010 — 3,740 140,875 Equity in loss of subsidiaries (1,049,010 ) — — 1,049,010 — Loss from continuing operations ($1,132,641 ) ($1,049,010 ) $— $1,023,766 ($1,157,885 ) Income from discontinued operations, net of income taxes 2,731 — — — 2,731 Net loss ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $3,938 $706,121 $128 $— $710,187 Total costs and expenses (76,531 ) 442,343 30 (5,865 ) 359,977 Income from continuing operations before income taxes 80,469 263,778 98 5,865 350,210 Income tax expense (28,164 ) (92,322 ) — (7,441 ) (127,927 ) Equity in income of subsidiaries 171,554 — — (171,554 ) — Income from continuing operations $223,859 $171,456 $98 ($173,130 ) $222,283 Income from discontinued operations, net of income taxes 4,060 — — — 4,060 Net income $227,919 $171,456 $98 ($173,130 ) $226,343 |
Schedule Of Condensed Consolidating Statements Of Cash Flows | CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities from continuing operations (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities from continuing operations 308,340 268,283 740 (269,023 ) 308,340 Net cash used in discontinued operations — — — — — 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 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities from continuing operations $2,655 $376,080 $— $— $378,735 Net cash used in investing activities from continuing operations (447,296 ) (674,758 ) — 448,678 (673,376 ) Net cash provided by financing activities from continuing operations 480,767 298,678 — (448,678 ) 330,767 Net cash used in discontinued operations (4,046 ) — — — (4,046 ) Net increase in cash and cash equivalents 32,080 — — — 32,080 Cash and cash equivalents, beginning of year 10,838 — — — 10,838 Cash and cash equivalents, end of year $42,918 $— $— $— $42,918 Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($132,683 ) $634,970 ($12 ) $— $502,275 Net cash used in investing activities from continuing operations (305,718 ) (906,509 ) (37,609 ) 309,160 (940,676 ) Net cash provided by financing activities from continuing operations 300,290 271,539 37,621 (309,160 ) 300,290 Net cash used in discontinued operations (8,490 ) — — — (8,490 ) Net decrease in cash and cash equivalents (146,601 ) — — — (146,601 ) Cash and cash equivalents, beginning of year 157,439 — — — 157,439 Cash and cash equivalents, end of year $10,838 $— $— $— $10,838 |
Supplemental Cash Flow Inform35
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Years Ended December 31, 2016 2015 2014 (In thousands) Supplemental cash flow disclosures: Cash paid for interest, net of amounts capitalized $75,231 $64,692 $49,379 Cash paid for income taxes — — — Non-cash investing and financing activities: Increase (decrease) in capital expenditure payables and accruals ($21,492 ) ($86,878 ) $45,716 Liabilities assumed in connection with the Sanchez Acquisition 4,880 — — Stock-based compensation expense capitalized to oil and gas properties 4,591 4,574 7,099 Asset retirement obligations capitalized to oil and gas properties 1,927 4,853 4,545 Purchase price adjustments related to the Eagle Ford Shale Acquisition — — 3,197 EFM deferred purchase payment — — 148,900 Other non-cash investing activities (1) 10,068 22,562 2,244 |
Supplemental Disclosures Abou36
Supplemental Disclosures About Oil And Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities | Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Years Ended December 31, 2016 2015 2014 (In thousands) Property acquisition costs Proved properties $90,661 $— $183,633 Unproved properties 113,535 63,446 215,021 Total property acquisition costs 204,196 63,446 398,654 Exploration costs 37,508 117,227 194,956 Development costs 374,134 389,396 530,268 Total costs incurred $615,838 $570,069 $1,123,878 |
Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas 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, 2014 62,041 8,152 187,957 101,519 Extensions and discoveries 29,793 3,681 30,343 38,531 Revisions of previous estimates 3,046 1,270 18,913 7,469 Purchases of reserves in place 12,730 1,335 8,681 15,512 Production (6,906 ) (925 ) (24,877 ) (11,978 ) December 31, 2014 100,704 13,513 221,017 151,053 Extensions and discoveries 26,358 5,292 33,925 37,304 Revisions of previous estimates (9,059 ) 2,768 11,808 (4,323 ) Production (8,415 ) (1,352 ) (21,812 ) (13,402 ) December 31, 2015 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 Proved developed reserves: December 31, 2013 18,321 2,779 106,976 38,929 December 31, 2014 35,238 5,294 149,697 65,482 December 31, 2015 42,311 7,933 154,725 76,032 December 31, 2016 51,062 9,387 187,054 91,625 Proved undeveloped reserves: December 31, 2013 43,720 5,373 80,981 62,590 December 31, 2014 65,466 8,219 71,320 85,571 December 31, 2015 67,277 12,288 90,213 94,600 December 31, 2016 77,256 14,550 100,391 108,538 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 our drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20% , respectively, of the total extensions and discoveries. For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through our drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries. For the year ended December 31, 2014, the Company added 5,483 MBoe of proved developed reserves and 33,048 MBoe of proved undeveloped reserves through our drilling program and associated offset locations. Eagle Ford comprised 92% of the total extensions and discoveries. Revisions of previous estimates 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 due to performance 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 our 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 our 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. For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives; • Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus. For the year ended December 31, 2014, revisions of previous estimates increased the Company’s proved reserves by 7,469 MBoe. Included in revisions of previous estimates were positive revisions due to price primarily in Marcellus. Purchases of reserves in place 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. There were no purchases of reserves in place for the year ended December 31, 2015. For the year ended December 31, 2014, purchases of reserves in place included 4,144 MBoe of proved developed reserves and 11,369 MBoe of proved undeveloped reserves associated with the Eagle Ford Shale Acquisition. |
Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves | The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2016 2015 2014 (In thousands) Future cash inflows $5,903,629 $5,878,348 $10,380,951 Future production costs (2,241,928 ) (2,124,059 ) (2,532,106 ) Future development costs (1,264,493 ) (1,178,773 ) (1,680,795 ) Future income taxes (1) — — (1,354,524 ) Future net cash flows 2,397,208 2,575,516 4,813,526 Less 10% annual discount to reflect timing of cash flows (1,093,779 ) (1,210,292 ) (2,258,444 ) Standard measure of discounted future net cash flows $1,303,429 $1,365,224 $2,555,082 (1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, 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 our proved oil and gas reserves as of December 31, 2016 and 2015. |
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves | Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below: Years Ended December 31, 2016 2015 2014 (In thousands) Standardized measure at beginning of year $1,365,224 $2,555,082 $1,621,411 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ($346,763 ) ($2,547,213 ) ($240,533 ) Net change in estimated future development costs 74,407 342,238 89,401 Net change due to revisions in quantity estimates (150,245 ) (157,271 ) 205,166 Accretion of discount 136,522 326,074 202,672 Changes in production rates (timing) and other (111,137 ) (139,533 ) (61,099 ) Total revisions to reserves proved in prior years (397,216 ) (2,175,705 ) 195,607 Net change due to extensions and discoveries, net of estimated future development and production costs 313,201 252,155 867,615 Net change due to purchases of reserves in place 43,426 — 352,867 Sales of crude oil, NGLs and natural gas produced, net of production costs (320,272 ) (312,213 ) (598,036 ) Previously estimated development costs incurred 299,066 340,247 415,963 Net change in income taxes (1) — 705,658 (300,345 ) Net change in standardized measure of discounted future net cash flows (61,795 ) (1,189,858 ) 933,671 Standardized measure at end of year $1,303,429 $1,365,224 $2,555,082 (1) Net change in income taxes in the calculation of changes in standardized measure of discounted future net cash flows was zero as of December 31, 2016 as the future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015. See discussion in the note above as to why future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015. |
Selected Quarterly Financial 37
Selected Quarterly Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 and 2015 : Year Ended December 31, 2016 First Quarter (2) Second Quarter (2) Third Quarter (2) Fourth Quarter (In thousands, except per share data) Total revenues $81,262 $107,324 $111,177 $143,831 Operating profit (loss) (1) ($7,491 ) $27,167 $31,634 $55,000 Loss from continuing operations ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss per common share - basic Loss from continuing operations (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Net loss (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Net loss per common share - diluted Loss from continuing operations (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Net loss (5) ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Year Ended December 31, 2015 First Quarter Second Quarter (3) Third Quarter (4) Fourth Quarter (4) (In thousands, except per share data) Total revenues $100,050 $123,494 $106,237 $99,422 Operating profit (loss) (1) ($2,588 ) $14,034 ($3,752 ) $4,484 Loss from continuing operations ($21,476 ) ($46,970 ) ($708,768 ) ($380,671 ) Net loss ($21,210 ) ($46,132 ) ($707,647 ) ($380,165 ) Net loss per common share - basic Loss from continuing operations (5) ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss (5) ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) Net loss per common share - diluted Loss from continuing operations (5) ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss (5) ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) (1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A. (2) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million , $197.1 million , and $105.1 million , respectively. (3) In the second quarter of 2015, the Company recognized a loss on extinguishment of debt of $38.1 million as a result of the cash tender offer and redemption of the 8.625% Senior Notes. (4) In the third quarter and fourth quarter of 2015, the Company recognized impairments of proved oil and gas properties of $812.8 million and $411.6 million , respectively. Primarily as a result of the impairments of proved oil and gas properties, since the third quarter of 2015, the Company recorded a valuation allowance against its net deferred tax assets reducing them to zero . (5) The sum of quarterly net loss per common share does not agree with the total year net loss per common share as each computation is based on the weighted average of common shares outstanding during the period. |
Summary Of Significant Accoun38
Summary Of Significant Accounting Policies (Narrative) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2016USD ($)$ / Boeshares | Dec. 31, 2015USD ($)$ / Boeshares | Dec. 31, 2014USD ($)$ / Boe | Mar. 31, 2017USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Other Accounts Payable and Accrued Liabilities | $ 49,100 | $ 34,300 | $ 49,100 | ||||||
Allowance for doubtful accounts receivable | 1,000 | 800 | 1,000 | ||||||
Internal costs capitalized, oil and gas producing activities | $ 10,500 | $ 15,800 | $ 18,800 | ||||||
Average DD&A Per Boe (in USD per BOE) | $ / Boe | 13.50 | 22.05 | 26.20 | ||||||
Capitalized interest | $ 17,000 | $ 32,100 | $ 34,500 | ||||||
Reserves discount factor | 10.00% | ||||||||
Impairment of proved oil and gas properties | $ 105,100 | $ 197,100 | $ 274,400 | 411,600 | $ 812,800 | $ 576,540 | 1,224,367 | $ 0 | |
Deferred Tax Assets, Valuation Allowance | 324,681 | 564,434 | $ 324,681 | ||||||
Deferred Tax Assets, Net | $ 0 | ||||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares | 668,703 | 648,980 | |||||||
Unamortized Debt Issuance Expense | $ 19,700 | $ 19,700 | |||||||
Minimum [Member] | |||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Estimated useful life, minimum, years | 3 years | ||||||||
Maximum [Member] | |||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Estimated useful life, minimum, years | 10 years | ||||||||
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 | 4 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% | ||||||||
Customer One [Member] | |||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Customer percentage of total revenue | 56.00% | 65.00% | 44.00% | ||||||
Customer Two [Member] | |||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Customer percentage of total revenue | 15.00% | 9.00% | 26.00% | ||||||
Contractor [Member] | Restricted Stock Awards And Units [Member] | |||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Vesting period, in years | 3 years | ||||||||
Subsequent Event [Member] | |||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||
Unrecognized Tax Benefits | $ 15,700 |
Summary Of Significant Accoun39
Summary Of Significant Accounting Policies (Schedule of Earnings Per Share Reconciliation) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Income (Loss) From Continuing Operations | $ (675,474) | $ (1,157,885) | $ 222,283 | ||||||||
Weighted Average Number of Shares Outstanding, Basic | 59,932 | 51,457 | 45,372 | ||||||||
Effect of dilutive instruments | |||||||||||
Stock options | 0 | 0 | 13 | ||||||||
Warrants | 0 | 0 | 69 | ||||||||
Weighted Average Number of Shares Outstanding, Diluted | 59,932 | 51,457 | 46,194 | ||||||||
Income (Loss) from Continuing Operations Per Common Share | |||||||||||
Income (Loss) from Continuing Operations, Per Basic Share | $ (0.01) | $ (1.72) | $ (4.46) | $ (5.34) | $ (6.73) | $ (13.75) | $ (0.92) | $ (0.46) | $ (11.27) | $ (22.50) | $ 4.90 |
Income (Loss) from Continuing Operations, Per Diluted Share | $ (0.01) | $ (1.72) | $ (4.46) | $ (5.34) | $ (6.73) | $ (13.75) | $ (0.92) | $ (0.46) | $ (11.27) | $ (22.50) | $ 4.81 |
Restricted Stock Awards And Units [Member] | |||||||||||
Effect of dilutive instruments | |||||||||||
Nonvested Shares with Forfeitable Dividends | 0 | 0 | 684 | ||||||||
Performance Shares [Member] | |||||||||||
Effect of dilutive instruments | |||||||||||
Nonvested Shares with Forfeitable Dividends | 0 | 0 | 56 |
Acquisitions (Narrative) (Detai
Acquisitions (Narrative) (Details) - USD ($) $ in Thousands | Feb. 13, 2015 | Oct. 24, 2014 | Dec. 31, 2016 | Oct. 31, 2016 | Dec. 31, 2016 | Feb. 16, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 14, 2016 | Sep. 30, 2013 |
Business Acquisition [Line Items] | |||||||||||
Agreed Upon Purchase Price of Oil and Gas Property and Equipment | $ 181,000 | ||||||||||
Payments to Acquire Oil and Gas Property | $ 143,500 | $ 10,000 | $ 153,521 | $ 1,817 | $ 92,961 | ||||||
Purchase price adjustments | $ 10,700 | 0 | 0 | 3,197 | |||||||
Loss on sale of oil and gas properties | 0 | $ 0 | 0 | ||||||||
Deferred Purchase Price | $ 16,800 | ||||||||||
Sanchez Acquisition [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Revenue of Acquiree since Acquisition Date, Actual | 1,500 | ||||||||||
Earnings (Loss) of Acquiree since Acquisition Date, Actual | $ 1,000 | ||||||||||
Eagle Ford Shale Transaction [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to Acquire Oil and Gas Property | $ 148,800 | $ 93,000 | |||||||||
Adjusted Purchase Price for Acquisition of Oil and Gas Property | $ 241,800 | ||||||||||
Total Agreed Upon Purchase Price of Oil and Gas Property and Equipment | $ 250,000 | ||||||||||
Percentage of Working Interest Prior to Acquisition | 75.00% | ||||||||||
Percentage of Working Interest Subsequent to Acquisition | 100.00% | ||||||||||
Revenue of Acquiree since Acquisition Date, Actual | 13,100 | ||||||||||
Earnings (Loss) of Acquiree since Acquisition Date, Actual | $ 11,000 | ||||||||||
Purchase price adjustments | $ 3,197 | ||||||||||
Deferred purchase payment due to EFM [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Debt Instrument, Unamortized Discount | 2,600 | ||||||||||
Long-term Debt, Gross | $ 147,445 |
Acquisitions (Schedule of Consi
Acquisitions (Schedule of Consideration Paid for Assets Acquired and Liabilities Assumed) (Table) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 14, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Oct. 24, 2014 |
Acquisitions - Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract] | |||||
Business Combination, Current Assets | $ 477 | $ 485 | |||
Business Combination, Oil and Gas Properties, Net | 90,661 | 244,124 | |||
Business Combination, Recognized Assets Acquired and Liabilities Assumed, Unproved Oil and Gas Properties | 67,263 | ||||
Business Combination, Recognized Assets Acquired and Liabilities Assumed, Oil and Gas Properties | 157,924 | ||||
Business Combination, Total Assets | 158,401 | 244,609 | |||
Business Combination, Current Liabilities | 1,442 | ||||
Business Combination, Other Liabilities | 323 | ||||
Business Combination, Noncurrent Liabilities | 2,037 | ||||
Business Combination, Other Noncurrent Liabilities | 1,078 | ||||
Business Combination, Liabilities | $ 4,880 | 4,880 | $ 0 | $ 0 | 423 |
Business Combination, Net | $ 153,521 | $ 244,186 |
Acquisitions (Schedule of Resul
Acquisitions (Schedule of Results of Operations) (Table) (Details) - USD ($) $ / shares in Units, shares in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Acquisitions - Results of Operations [Abstract] | ||
Business Acquisition, Pro Forma Revenue | $ 761,199,000 | $ 575,721,000 |
Business Acquisition, Pro Forma Net Income (Loss) | $ 264,714,000 | $ 36,356,000 |
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ 5.83 | $ 0.89 |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ 5.73 | $ 0.88 |
Weighted Average Basic Shares Outstanding, Pro Forma | 45,372 | 40,781 |
Pro Forma Weighted Average Shares Outstanding, Diluted | 46,194 | 41,355 |
Property And Equipment, Net (Na
Property And Equipment, Net (Narrative) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($)$ / bbls | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2016USD ($)$ / bbls | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Mar. 31, 2017$ / bbls | |
Property, Plant and Equipment [Line Items] | |||||||||
Unproved properties, not being amortized | $ 335,452 | $ 240,961 | $ 335,452 | ||||||
Capitalized costs of unproved properties | 120,500 | 20,700 | $ 99,800 | ||||||
After-tax impairment of oil and gas properties | 0 | ||||||||
Impairment of proved oil and gas properties | $ 105,100 | $ 197,100 | $ 274,400 | $ 411,600 | $ 812,800 | 576,540 | 1,224,367 | 0 | |
Loss on sale of oil and gas properties | $ 0 | $ 0 | $ 0 | ||||||
Estimated Price to Calculated Forecasted Ceiling Test Impairment | $ / bbls | 46 | 50 | |||||||
Subsequent Event [Member] | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Estimated Price To Calculate Forecasted Ceiling Test | $ / bbls | 44.39 |
Property And Equipment, Net (Sc
Property And Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Property, Plant and Equipment [Abstract] | ||
Proved properties, net | $ 4,687,416 | $ 3,976,511 |
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities | 3,392,749 | 2,607,360 |
Proved properties, net | 1,294,667 | 1,369,151 |
Unproved properties, not being amortized | ||
Unevaluated leasehold and seismic costs | 211,067 | 280,263 |
Exploratory wells in progress | 0 | 9,432 |
Capitalized interest | 29,894 | 45,757 |
Total unproved properties, not being amortized | 240,961 | 335,452 |
Other property and equipment | 23,127 | 22,677 |
Accumulated depreciation | (12,995) | (10,419) |
Other property and equipment, net | 10,132 | 12,258 |
Total property and equipment, net | $ 1,545,760 | $ 1,716,861 |
Property and Equipment, Net (45
Property and Equipment, Net (Schedule of Impairment of Oil and Gas Properties) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($)$ / bbls | Sep. 30, 2015USD ($) | Dec. 31, 2016USD ($)$ / bbls | Dec. 31, 2015USD ($)$ / bbls | Dec. 31, 2014USD ($)$ / bbls | |
Impairment of Oil And Gas Properties [Line Items] | ||||||||
Impairment of proved oil and gas properties | $ | $ 105,100 | $ 197,100 | $ 274,400 | $ 411,600 | $ 812,800 | $ 576,540 | $ 1,224,367 | $ 0 |
Change In Price Used In Ceiling Test Calculation | (16.00%) | (49.00%) | ||||||
Crude Oil [Member] | ||||||||
Impairment of Oil And Gas Properties [Line Items] | ||||||||
Average Realized Price | $ / bbls | 47.24 | 39.60 | 47.24 | 92.24 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | ||
Deferred Tax Assets, Valuation Allowance | $ 564,434 | $ 324,681 |
Change In Valuation Allowance | 240,800 | |
Reduction In Valuation Allowance For Stock Based Compensation | 1,100 | |
Deferred Tax Assets, Net | $ 0 | |
U.S. federal statutory corporate pretax rate | 35.00% | |
Ownership percentage change | 5.00% | |
Change in beneficial ownership, percentage | 50.00% | |
Stock-based compensation deductions not reflected in deferred tax assets | $ 44,700 | |
Recognized deferred tax assets associated with stock based compensation tax deductions | 15,700 | |
United States Of America [Member] | ||
Income Taxes [Line Items] | ||
Operating loss carry forwards subject to expiration | $ 648,700 |
Income Taxes (Schedule Of Compo
Income Taxes (Schedule Of Components Of Income Tax (Expense) Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current income tax (expense) benefit | |||
U.S. Federal | $ 0 | $ 0 | $ 0 |
State | 0 | 0 | 0 |
Total current income tax (expense) benefit | 0 | 0 | 0 |
Deferred income tax (expense) benefit | |||
U.S. Federal | 0 | 131,502 | (122,342) |
State | 0 | 9,373 | (5,585) |
Total deferred income tax (expense) benefit | 0 | 140,875 | (127,927) |
Total income tax (expense) benefit from continuing operations | $ 0 | $ 140,875 | $ (127,927) |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||
Income (loss) from continuing operations before income taxes | $ (675,474) | $ (1,298,760) | $ 350,210 |
Income tax (expense) benefit at the statutory rate | (236,416) | (454,566) | 122,574 |
State income tax (expense) benefit, net of U.S. Federal income taxes | 3,894 | 9,373 | (5,585) |
State Franchise Tax (Expense) Benefit | 0 | (1,671) | |
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense | 0 | ||
Deferred tax asset valuation allowance | (240,864) | (323,586) | 0 |
Other | 554 | (1,149) | 232 |
Total income tax (expense) benefit from continuing operations | $ 0 | $ 140,875 | $ (127,927) |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred income tax assets | ||
Net operating loss carryforward - U.S. Federal and State | $ 221,063 | $ 119,783 |
Oil and gas properties | 309,848 | 232,786 |
Asset retirement obligations | 7,434 | 5,779 |
Stock-based compensation | 5,238 | 4,741 |
Derivative liabilities | 17,545 | 4,433 |
Other | 3,739 | 3,435 |
Deferred income tax assets | 564,867 | 370,957 |
Deferred tax asset valuation allowance | (564,434) | (324,681) |
Net deferred income tax assets | 433 | 46,276 |
Deferred income tax liabilities | ||
Oil and gas properties | 0 | 0 |
Derivative assets | (433) | (46,276) |
Deferred income tax liabilities | (433) | (46,276) |
Net deferred income tax asset (liability) | $ 0 | $ 0 |
Income Taxes (Schedule Of Net D
Income Taxes (Schedule Of Net Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Income Tax Disclosure [Abstract] | ||
Net current deferred income tax liability | $ 0 | $ (46,758) |
Net noncurrent deferred income tax asset | 0 | 46,758 |
Net deferred income tax asset (liability) | $ 0 | $ 0 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) | Apr. 28, 2015 | May 14, 2015 | Dec. 31, 2016 | Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Apr. 14, 2015 |
Debt Instrument [Line Items] | ||||||||
Gains (Losses) on Extinguishment of Debt | $ (38,137,000) | $ 0 | $ (38,137,000) | $ 0 | ||||
Senior Secured Revolving Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Line of credit facility current borrowing base | $ 600,000,000 | 600,000,000 | ||||||
Line of credit facility amount outstanding | $ 87,000,000 | $ 87,000,000 | 0 | |||||
Debt, Weighted Average Interest Rate | 2.72% | 2.72% | ||||||
Letters of credit outstanding amount | $ 415,000 | $ 415,000 | ||||||
Pre-Tax SEC PV10 Reserve Value Percentage | 90.00% | |||||||
Federal funds rate plus percentage | 0.50% | 0.50% | ||||||
Adjusted LIBO rate plus percentage | 1.00% | 1.00% | ||||||
Current Ratio | 3.27 | 3.27 | ||||||
Ratio Of EBITDA To Interest Expense | 4.58 | 4.58 | ||||||
Ratio Of Total Secured Debt To EBITDA | 0.21 | 0.21 | ||||||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Current Ratio | 1 | 1 | ||||||
Ratio Of EBITDA To Interest Expense | 2.50 | 2.50 | ||||||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Ratio Of Total Secured Debt To EBITDA | 2 | 2 | ||||||
7.50% Senior Notes [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument interest rate | 7.50% | 7.50% | ||||||
Long-term Debt, Gross | $ 600,000,000 | $ 600,000,000 | 600,000,000 | |||||
Change of control repurchase price percentage | 101.00% | 101.00% | ||||||
7.50% Senior Notes [Member] | On and after September 15, 2016 [Member] | Minimum [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price, percentage of principal amount | 100.00% | 100.00% | ||||||
7.50% Senior Notes [Member] | On and after September 15, 2016 [Member] | Maximum [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price, percentage of principal amount | 103.75% | 103.75% | ||||||
6.25% Senior Notes [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument interest rate | 6.25% | |||||||
Long-term Debt, Gross | $ 650,000,000 | $ 650,000,000 | 650,000,000 | |||||
6.25% Senior Notes [Member] | Prior to April 15, 2018 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Redemption Price, Percentage | 100.00% | |||||||
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% | |||||||
8.625% Senior Notes [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument interest rate | 8.625% | |||||||
Long-term Debt, Gross | $ 600,000,000 | |||||||
Debt Instrument, Cash Consideration for Tender Offer | $ 276,400,000 | |||||||
Debt Instrument, Repurchased Face Amount | 264,200,000 | $ 335,800,000 | ||||||
Redemption Premium | 12,200,000 | 14,500,000 | 26,700,000 | |||||
Tender Offer Consideration Rate | 1,046.13 | |||||||
Principal amount per note | 1,000 | |||||||
Accrued interest paid associated with tender offer | $ 822,879 | |||||||
Debt Instrument, Redemption, Cash Consideration | $ 352,600,000 | |||||||
Debt Instrument, Redemption Price, Percentage | 104.313% | |||||||
Debt Instrument, Redemption Price per Note | $ 1,043.13 | |||||||
Accrued interest paid associated with redemption of debt | $ 2,300,000 | |||||||
Write off of Deferred Debt Issuance Cost and Unamortized Discount | 11,400,000 | |||||||
Other Long Term Debt [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term Debt, Gross | $ 4,425,000 | $ 4,425,000 | $ 4,425,000 |
Debt (Schedule Of Debt) (Detail
Debt (Schedule Of Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Apr. 14, 2015 |
Debt Instrument [Line Items] | |||
Unamortized Debt Issuance Expense | $ 19,700 | ||
Long-term Debt, Excluding Current Maturities | $ 1,325,418 | 1,236,017 | |
Senior Secured Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of credit facility amount outstanding | 87,000 | 0 | |
8.625% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 600,000 | ||
7.50% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 600,000 | 600,000 | |
Debt Instrument, Unamortized Premium | 1,020 | 1,251 | |
Unamortized Debt Issuance Expense | 7,573 | 9,048 | |
6.25% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 650,000 | 650,000 | |
Unamortized Debt Issuance Expense | 9,454 | 10,611 | |
Other Long Term Debt [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 4,425 | $ 4,425 |
Debt (Interest and Commitment F
Debt (Interest and Commitment Fee Rates) (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Less than 25 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 1.00% |
Margin for eurodollar loans | 2.00% |
Debt Instrument, Unused Borrowing Capacity, Fee | 0.50% |
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 | 1.25% |
Margin for eurodollar loans | 2.25% |
Debt Instrument, Unused Borrowing Capacity, Fee | 0.50% |
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 | 1.50% |
Margin for eurodollar loans | 2.50% |
Debt Instrument, Unused Borrowing Capacity, Fee | 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 | 1.75% |
Margin for eurodollar loans | 2.75% |
Debt Instrument, Unused Borrowing Capacity, Fee | 0.50% |
Greater than or equal to 90 percent [Member] | |
Interest and Commitment Fee Rates [Line Items] | |
Margin for base rate loans | 2.00% |
Margin for eurodollar loans | 3.00% |
Debt Instrument, Unused Borrowing Capacity, Fee | 0.50% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning of year asset retirement obligations | $ 16,511 | $ 12,512 |
Liabilities incurred | 2,137 | 3,227 |
Liabilities settled | (599) | (1,966) |
Accretion expense | 1,364 | 1,112 |
Revisions to estimated cash flows | (210) | 1,626 |
End of year asset retirement obligations | 21,240 | 16,511 |
Current asset retirement obligations (included in other current liabilities) | (392) | (328) |
Non-current asset retirement obligations | 20,848 | 16,183 |
Sanchez Acquisition [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities incurred | $ 2,037 | |
Eagle Ford Shale Transaction [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities incurred | $ 0 |
Commitments and Contingencies55
Commitments and Contingencies (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Rent expense | $ 2,000 | $ 2,200 | $ 1,900 |
Operating leases | |||
2,017 | 4,438 | ||
2,018 | 4,430 | ||
2,019 | 4,412 | ||
2,020 | 4,463 | ||
2,021 | 4,450 | ||
2022 and Thereafter | 1,854 | ||
Total | 24,047 | ||
Capital leases | |||
2,017 | 1,856 | ||
2,018 | 1,823 | ||
2,019 | 1,800 | ||
2,020 | 1,050 | ||
2,021 | 0 | ||
2022 and Thereafter | 0 | ||
Total | 6,529 | ||
Drilling rig contracts | |||
2,017 | 23,753 | ||
2,018 | 3,957 | ||
2,019 | 0 | ||
2,020 | 0 | ||
2,021 | 0 | ||
2022 and Thereafter | 0 | ||
Total | 27,710 | ||
Delivery commitments | |||
2,017 | 8,134 | ||
2,018 | 8,611 | ||
2,019 | 7,298 | ||
2,020 | 4,826 | ||
2,021 | 3,680 | ||
2022 and Thereafter | 291 | ||
Total | 32,840 | ||
Total | |||
2,017 | 38,181 | ||
2,018 | 18,821 | ||
2,019 | 13,510 | ||
2,020 | 10,339 | ||
2,021 | 8,130 | ||
2022 and Thereafter | 2,145 | ||
Total | $ 91,126 |
Shareholders' Equity And Stoc56
Shareholders' Equity And Stock Incentive Plan (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Oct. 28, 2016 | Oct. 21, 2015 | Mar. 20, 2015 | Dec. 31, 2013 | Dec. 31, 2009 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested | $ 26,300 | $ 32,000 | $ 37,300 | ||||||||
Sale of common stock, net of offering costs, shares | 6,000,000 | 6,300,000 | 5,200,000 | ||||||||
Sale of Stock, Price Per Share | $ 37.32 | $ 37.80 | $ 44.75 | ||||||||
Sale of common stock, net of offering costs | $ 223,700 | $ 238,800 | $ 231,316 | $ 223,739 | $ 470,158 | $ 0 | |||||
Class of Warrant or Right, Outstanding | 118,200 | ||||||||||
Issuance of warrants to purchase of common stock | 0 | ||||||||||
Investment warrants, exercise price | $ 22.09 | ||||||||||
Conversion of Stock, Shares Issued | 71,913 | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 2,938,889 | 2,938,889 | |||||||||
Shares Granted, Options | 0 | 0 | |||||||||
Total intrinsic value, Options Exercised | $ 100 | $ 1,300 | |||||||||
Proceeds from stock options exercised | $ 0 | 46 | 437 | ||||||||
Tax Benefit Realized from Exercises | $ 100 | $ 400 | |||||||||
Grants in Period, Performance Shares | 887,254 | 401,421 | 576,812 | ||||||||
Grant Date Fair Value, Performance Shares | $ 36.93 | $ 44.22 | $ 36.93 | $ 44.22 | $ 34.55 | $ 28.03 | |||||
Stock Incentive Plans [Member] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Maximum issuance of grant awards under Incentive Plan | 10,822,500 | 10,822,500 | |||||||||
Restricted Stock Award And Units [Member] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Compensation cost not yet recognized | $ 17,300 | $ 17,300 | |||||||||
Compensation cost not yet recognized, period for recognition | 1 year 9 months | ||||||||||
Cash Settled Stock Appreciation Rights Plan [Member] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
SARs, Granted | 376,260 | 0 | 0 | ||||||||
Liability for cash stock appreciation rights | $ 11,500 | $ 7,000 | |||||||||
Liability for cash stock appreciation rights, classified as other accrued liabilities | 10,000 | ||||||||||
Liability for cash stock appreciation rights remainder, classified as other long term liabilities | 1,500 | ||||||||||
Cash paid at exercises, Stock Appreciation Rights | 5,200 | $ 1,500 | $ 7,800 | ||||||||
Compensation cost not yet recognized | 3,000 | $ 3,000 | |||||||||
Compensation cost not yet recognized, period for recognition | 1 year 73 days | ||||||||||
Performance Shares [Member] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Compensation cost not yet recognized | $ 2,900 | $ 2,900 | |||||||||
Compensation cost not yet recognized, period for recognition | 1 year 6 months | ||||||||||
Grants in Period, Performance Shares | 41,651 | 56,517 | 56,342 | ||||||||
Grant Date Fair Value, Performance Shares | $ 58.44 | $ 66.83 | $ 58.44 | $ 66.83 | $ 68.15 | $ 0 | |||||
Vesting period, in years | 3 years | ||||||||||
Minimum [Member] | Performance Shares [Member] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Range of Awards to Vest Based on Market Condition | 0.00% | ||||||||||
Maximum [Member] | Performance Shares [Member] | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Range of Awards to Vest Based on Market Condition | 200.00% |
Shareholders' Equity And Stoc57
Shareholders' Equity And Stock Incentive Plan (Summary Of Restricted Stock Award And Unit Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Restricted Stock Awards and Units | |||
Unvested Shares/Units, Beginning of Period | 1,041,997 | 1,335,682 | 1,444,867 |
Granted Shares/Units | 887,254 | 401,421 | 576,812 |
Vested Shares/Units | (811,136) | (671,417) | (647,306) |
Forfeited Shares/Units | (6,405) | (23,689) | (38,691) |
Unvested Shares/Units, End of Period | 1,111,710 | 1,041,997 | 1,335,682 |
Weighted Average Grant Date Fair Value | |||
Grant-date Fair Value, Beginning of Period (USD per share) | $ 44.22 | $ 34.55 | $ 28.03 |
Granted, Grant-date Fair Value (USD per share) | 27.80 | 51.45 | 48.64 |
Vested, Grant-date Fair Value (USD per share) | 36.32 | 32.96 | 32.64 |
Forfeited, Grant-date Fair Value (USD per share) | 34.46 | 43.36 | 32.89 |
Grant-date Fair Value, End of Period (USD per share) | $ 36.93 | $ 44.22 | $ 34.55 |
Shareholders' Equity And Stoc58
Shareholders' Equity And Stock Incentive Plan (Summary of SARs Activity) (Details) - Cash Settled Stock Appreciation Rights Plan [Member] - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |||
SARs, Outstanding, beginning of period | 700,453 | 765,198 | 1,086,231 |
SARs, Granted | 376,260 | 0 | 0 |
SARs, Exercised | (354,075) | (64,745) | (321,033) |
SARs, Forfeitures | 0 | 0 | 0 |
SARs, Outstanding, end of period | 722,638 | 700,453 | 765,198 |
SARs, Exercisable, End of Period | 350,840 | 626,661 | 587,481 |
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 | $ 21.86 | $ 22.49 | $ 24.78 |
Weighted Average Exercise Prices, Granted | 27.30 | 0 | 0 |
Weighted Average Exercise Prices, Exercised | 23.89 | 29.40 | 30.24 |
Weighted Average Exercise Prices, Forfeitures | 0 | 0 | 0 |
Weighted Average Exercise Prices, Outstanding, End of Period | $ 23.69 | $ 21.86 | $ 22.49 |
Cash paid at exercises, Stock Appreciation Rights | $ 5.2 | $ 1.5 | $ 7.8 |
Weighted Average Exercise Prices, Exercisable, End of Period | $ 19.87 | $ 21.05 | $ 20.78 |
Weighted Average Remaining Life, Outstanding, End of Period | 2 years 5 months | ||
Weighted Average Remaining Life, Exercisable, End of Period | 6 months | ||
Aggregate Intrinsic Value, Outstanding, End of Period | $ 10.1 | ||
Aggregate Intrinsic Value, Exercisable, End of Period | $ 6.2 |
Shareholders' Equity And Stoc59
Shareholders' Equity And Stock Incentive Plan (Summary of Stock Appreciation Rights Fair Value Assumptions) (Details) - Stock Appreciation Rights (SARs) [Member] | 12 Months Ended |
Dec. 31, 2016$ / sharesRate | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Expected volatility | 45.10% |
Dividend yield | 0.00% |
Risk-free interest rate | 1.30% |
Expected Term | 3 years 11 months 5 days |
Weighted Average Grant Date Price | $ / shares | $ 9.88 |
Shareholders' Equity And Stoc60
Shareholders' Equity And Stock Incentive Plan (Summary of Performance Share Award Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Performance Share Awards | |||
Unvested Shares/Units, Beginning of Period | 1,041,997 | 1,335,682 | 1,444,867 |
Granted Shares/Units | 887,254 | 401,421 | 576,812 |
Vested Shares/Units | (811,136) | (671,417) | (647,306) |
Forfeited Shares/Units | (6,405) | (23,689) | (38,691) |
Unvested Shares/Units, End of Period | 1,111,710 | 1,041,997 | 1,335,682 |
Weighted Average Grant Date Fair Value | |||
Grant-date Fair Value, Beginning of Period (USD per share) | $ 44.22 | $ 34.55 | $ 28.03 |
Vested, Grant-date Fair Value (USD per share) | 36.32 | 32.96 | 32.64 |
Granted, Grant-date Fair Value (USD per share) | 27.80 | 51.45 | 48.64 |
Forfeited, Grant-date Fair Value (USD per share) | 34.46 | 43.36 | 32.89 |
Grant-date Fair Value, End of Period (USD per share) | $ 36.93 | $ 44.22 | $ 34.55 |
Performance Shares [Member] | |||
Performance Share Awards | |||
Unvested Shares/Units, Beginning of Period | 112,859 | 56,342 | 0 |
Granted Shares/Units | 41,651 | 56,517 | 56,342 |
Vested Shares/Units | 0 | 0 | 0 |
Forfeited Shares/Units | 0 | 0 | 0 |
Unvested Shares/Units, End of Period | 154,510 | 112,859 | 56,342 |
Weighted Average Grant Date Fair Value | |||
Grant-date Fair Value, Beginning of Period (USD per share) | $ 66.83 | $ 68.15 | $ 0 |
Vested, Grant-date Fair Value (USD per share) | 0 | 0 | 0 |
Granted, Grant-date Fair Value (USD per share) | 35.71 | 65.51 | 68.15 |
Forfeited, Grant-date Fair Value (USD per share) | 0 | 0 | 0 |
Grant-date Fair Value, End of Period (USD per share) | $ 58.44 | $ 66.83 | $ 68.15 |
Shareholders' Equity And Stoc61
Shareholders' Equity And Stock Incentive Plan (Summary of Performance Share Awards Fair Value Assumptions) (Details) | 12 Months Ended | |||
Dec. 31, 2016$ / sharesRateshares | Dec. 31, 2015$ / sharesRateshares | Dec. 31, 2014$ / sharesRateshares | Dec. 31, 2013$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares | 1,111,710 | 1,041,997 | 1,335,682 | 1,444,867 |
Grant Date Fair Value, Performance Shares | $ 36.93 | $ 44.22 | $ 34.55 | $ 28.03 |
Grants in Period, Performance Shares | shares | 887,254 | 401,421 | 576,812 | |
Weighted Average Grant Date Fair Value | $ 27.80 | $ 51.45 | $ 48.64 | |
Vested Shares/Units | shares | (811,136) | (671,417) | (647,306) | |
Vested, Grant-date Fair Value (USD per share) | $ 36.32 | $ 32.96 | $ 32.64 | |
Forfeited Shares/Units | shares | (6,405) | (23,689) | (38,691) | |
Forfeited, Grant-date Fair Value (USD per share) | $ 34.46 | $ 43.36 | $ 32.89 | |
Performance Shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares | 154,510 | 112,859 | 56,342 | 0 |
Grant Date Fair Value, Performance Shares | $ 58.44 | $ 66.83 | $ 68.15 | $ 0 |
Grants in Period, Performance Shares | shares | 41,651 | 56,517 | 56,342 | |
Weighted Average Grant Date Fair Value | $ 35.71 | $ 65.51 | $ 68.15 | |
Vested Shares/Units | shares | 0 | 0 | 0 | |
Vested, Grant-date Fair Value (USD per share) | $ 0 | $ 0 | $ 0 | |
Forfeited Shares/Units | shares | 0 | 0 | 0 | |
Forfeited, Grant-date Fair Value (USD per share) | $ 0 | $ 0 | $ 0 | |
Number of simulations | 500,000 | 500,000 | 500,000 | |
Expected Term | 3 years 4 days | 2 years 10 months 21 days | 2 years 11 months 19 days | |
Expected volatility | Rate | 55.30% | 45.30% | 49.90% | |
Risk-free interest rate | 1.15% | 0.87% | 0.90% | |
Dividend yield | Rate | 0.00% | 0.00% | 0.00% | |
Weighted Average Grant Date Price | $ 35.71 | $ 53.58 | $ 53.96 |
Shareholders' Equity And Stoc62
Shareholders' Equity And Stock Incentive Plan (Summary Of Stock Options Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Stock Options | |||
Shares, Outstanding, beginning of period | 0 | 2,433 | 36,353 |
Shares Granted, Options | 0 | 0 | |
Shares, Exercised | (2,433) | (33,086) | |
Shares, Forfeited | 0 | 0 | |
Shares, Expired | (834) | ||
Shares, Outstanding, end of period | 0 | 2,433 | |
Shares, Exercisable, end of period | 0 | 2,433 | |
Weighted Average Exercise Prices | |||
Weighted-Average Exercise Prices, Outstanding, beginning period (USD per share) | $ 0 | $ 19.02 | $ 13.91 |
Weighted-Average Exercise Prices, Granted (USD per share) | 0 | 0 | |
Weighted-Average Exercise Prices, Exercised (USD per share) | 19.02 | 13.20 | |
Weighted-Average Exercise Prices, Forfeited (USD per share) | 0 | 0 | |
Weighted Average Exercise Prices, Expired (USD per share) | 27.25 | ||
Weighted-Average Exercise Prices, Outstanding, end of period (USD per share) | 0 | 19.02 | |
Weighted-Average Exercise Prices, Exercisable, end of period (USD per share) | $ 0 | $ 19.02 | |
Additional Disclosures | |||
Weighted-Average Remaining Life, Outstanding, end of period | 6 months 7 days | ||
Weighted - Average Remaining Life, Exercisable, end of period | 6 months 7 days | ||
Aggregate Intrinsic Value, Outstanding, Exercised | $ 100 | $ 1,300 | |
Aggregate Intrinsic Value, Outstanding, end of period | 0 | 100 | |
Aggregate Intrinsic Value, Exercisable, end of period | 0 | 100 | |
Cash Received from Exercises | $ 0 | 46 | 437 |
Tax Benefit Realized from Exercises | $ 100 | $ 400 |
Shareholders' Equity And Stoc63
Shareholders' Equity And Stock Incentive Plan (Stock-Based Compensation Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | $ 40,677 | $ 19,303 | $ 32,977 |
Less: amounts capitalized | (4,591) | (4,574) | (7,099) |
Total stock-based compensation expense | 36,086 | 14,729 | 25,878 |
Restricted Stock Awards And Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | 28,196 | 23,668 | 29,597 |
Stock Appreciation Rights (SARs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | 9,675 | (6,326) | 1,985 |
Performance Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation expense | $ 2,806 | $ 1,961 | $ 1,395 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Related Party Transaction [Line Items] | ||
Due from Related Parties, Current | $ 0.9 | $ 2.4 |
Derivative Instruments (Narrati
Derivative Instruments (Narrative) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)bbl / d$ / bbls | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Derivative [Line Items] | |||
(Gain) loss on derivatives, net | $ | $ 49,073 | $ (99,261) | $ (201,907) |
Crude Oil [Member] | |||
Derivative [Line Items] | |||
(Gain) loss on derivatives, net | $ | $ 29,391 | $ (95,199) | $ (191,351) |
Weighted Average Ceiling Price of $60.00 [Member] | Crude Oil [Member] | 2018 [Member] | |||
Derivative [Line Items] | |||
Crude Oil Volumes (in Bbls/d) | bbl / d | 2,488 | ||
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 60 | ||
Weighted Average Ceiling Price of $62.50 [Member] | Crude Oil [Member] | 2019 [Member] | |||
Derivative [Line Items] | |||
Crude Oil Volumes (in Bbls/d) | bbl / d | 2,975 | ||
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 62.50 | ||
Weighted Average Ceiling Price of $65.00 [Member] | Crude Oil [Member] | 2020 [Member] | |||
Derivative [Line Items] | |||
Crude Oil Volumes (in Bbls/d) | bbl / d | 3,675 | ||
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 65 | ||
Weighted Average Ceiling Price of $75.00 [Member] | Crude Oil [Member] | 2018 [Member] | |||
Derivative [Line Items] | |||
Crude Oil Volumes (in Bbls/d) | bbl / d | 900 | ||
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 75 | ||
Weighted Average Ceiling Price of $77.50 [Member] | Crude Oil [Member] | 2019 [Member] | |||
Derivative [Line Items] | |||
Crude Oil Volumes (in Bbls/d) | bbl / d | 900 | ||
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 77.50 | ||
Weighted Average Ceiling Price of $80.00 [Member] | Crude Oil [Member] | 2020 [Member] | |||
Derivative [Line Items] | |||
Crude Oil Volumes (in Bbls/d) | bbl / d | 900 | ||
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 80 |
Derivative Instruments (Schedul
Derivative Instruments (Schedule of Crude Oil Derivative Positions) (Details) - Crude Oil [Member] | Dec. 31, 2016bbl / d$ / bbls |
Fixed Price Swaps [Member] | Derivative Positions, Q1 2017 [Domain] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 12,000 |
Weighted Average Floor Price ($/Bbl) | $ / bbls | 50.13 |
Fixed Price Swaps [Member] | Derivative Positions, Q2 2017 [Domain] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 12,000 |
Weighted Average Floor Price ($/Bbl) | $ / bbls | 50.13 |
Fixed Price Swaps [Member] | Derivative Positions, Q3 2017 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 6,000 |
Weighted Average Floor Price ($/Bbl) | $ / bbls | 54.15 |
Fixed Price Swaps [Member] | Derivative Positions, Q4 2017 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 3,000 |
Weighted Average Floor Price ($/Bbl) | $ / bbls | 55.01 |
Weighted Average Ceiling Price of $60.00 [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 2,488 |
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 60 |
Weighted Average Ceiling Price of $75.00 [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 900 |
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 75 |
Weighted Average Ceiling Price of $62.50 [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 2,975 |
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 62.50 |
Weighted Average Ceiling Price of $77.50 [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 900 |
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 77.50 |
Weighted Average Ceiling Price of $65.00 [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 3,675 |
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 65 |
Weighted Average Ceiling Price of $80.00 [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Crude Oil Volumes (in Bbls/d) | bbl / d | 900 |
Weighted Average Ceiling Price ($/Bbl) | $ / bbls | 80 |
Derivative Instruments (Sched67
Derivative Instruments (Schedule of Natural Gas Derivative Positions) (Details) - Natural Gas [Member] | Dec. 31, 2016MMBTU / d$ / MMBTU |
Swap [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Natural Gas Volumes (in MMBtu/d) | MMBTU / d | 20,000 |
Weighted Average Floor Price ($/MMBtu) | $ / MMBTU | 3.30 |
Call Option [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Natural Gas Volumes (in MMBtu/d) | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3 |
Call Option [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Natural Gas Volumes (in MMBtu/d) | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.25 |
Call Option [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Natural Gas Volumes (in MMBtu/d) | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.25 |
Call Option [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Natural Gas Volumes (in MMBtu/d) | MMBTU / d | 33,000 |
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU | 3.50 |
Derivative Instruments (Sched68
Derivative Instruments (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - Level 2 [Member] - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 1,237 | $ 132,215 |
Derivative Liability | 45,552 | 8,239 |
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net | (48,892) | 119,550 |
Derivative liabilities (assets), gross amounts offset in the consolidated balance sheets | 0 | 0 |
Derivative Asset (Liability), Net | (48,892) | 119,550 |
Other Current Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 6,507 | 159,447 |
Derivative Asset, Fair Value, Gross Liability | (5,270) | (28,347) |
Derivative Asset | 1,237 | 131,100 |
Other Noncurrent Assets [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1,313 | 10,780 |
Derivative Asset, Fair Value, Gross Liability | (1,313) | (9,665) |
Derivative Asset | 0 | 1,115 |
Other Current Liabilities [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (27,871) | (28,364) |
Derivative Liability, Fair Value, Gross Asset | 5,270 | 28,347 |
Derivative Liability | (22,601) | (17) |
Other Noncurrent Liabilities [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (28,841) | (22,313) |
Derivative Liability, Fair Value, Gross Asset | 1,313 | 9,665 |
Derivative Liability | $ (27,528) | $ (12,648) |
Derivative Instruments (Sched69
Derivative Instruments (Schedule of (Gain) Loss on Derivative Instruments) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||
(Gain) loss on derivatives, net | $ 49,073 | $ (99,261) | $ (201,907) |
Crude Oil [Member] | |||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||
(Gain) loss on derivatives, net | 29,391 | (95,199) | (191,351) |
Natural Gas [Member] | |||
Derivative Instruments, (Gain) Loss, Commodity [Line Items] | |||
(Gain) loss on derivatives, net | $ 19,682 | $ (4,062) | $ (10,556) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative, Fair Value, Net [Abstract] | ||
Fair value amount of transfers in or out of Levels 1 or 2 | $ 0 | $ 0 |
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset | 1,237,000 | 132,215,000 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability | 45,552,000 | 8,239,000 |
Derivative, Fair Value, Net [Abstract] | ||
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net | (48,892,000) | 119,550,000 |
Derivative liabilities (assets), gross amounts offset in the consolidated balance sheets | 0 | 0 |
Derivative Asset (Liability), Net | (48,892,000) | 119,550,000 |
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Current Assets [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 6,507,000 | 159,447,000 |
Derivative Asset, Fair Value, Gross Liability | 5,270,000 | 28,347,000 |
Derivative Asset | 1,237,000 | 131,100,000 |
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Assets [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 1,313,000 | 10,780,000 |
Derivative Asset, Fair Value, Gross Liability | 1,313,000 | 9,665,000 |
Derivative Asset | 0 | 1,115,000 |
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Liabilities [Member] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | (28,841,000) | (22,313,000) |
Derivative Liability, Fair Value, Gross Asset | 1,313,000 | 9,665,000 |
Derivative Liability | $ (27,528,000) | $ (12,648,000) |
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, 2016 | Dec. 31, 2015 |
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 | 1,237 | 132,215 |
Derivative Liability | (45,552) | (8,239) |
Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | $ 0 | $ 0 |
Fair Value Measurements (Sche72
Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
7.50% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | $ 600,000 | $ 600,000 |
6.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 650,000 | 650,000 |
Other Long Term Debt [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 4,425 | 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 | 593,447 | 592,203 |
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 | 640,546 | 639,389 |
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 | 4,425 | 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 | 624,750 | 528,000 |
Estimate of Fair Value Measurement [Member] | 6.25% Senior Notes [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | 672,750 | 533,000 |
Estimate of Fair Value Measurement [Member] | Other Long Term Debt [Member] | ||
Schedule of Fair Value of Debt Instruments [Line Items] | ||
Long-term Debt, Gross | $ 4,419 | $ 4,182 |
Condensed Consolidating Finan73
Condensed Consolidating Financial Information (Narrative) (Details) | Dec. 31, 2016 |
Condensed Consolidating Financial Information [Abstract] | |
Voting interest of the subsidiary owned by the registrant | 100.00% |
Condensed Consolidating Finan74
Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Total current assets | $ 72,988 | $ 232,182 | ||
Total property and equipment, net | 1,545,760 | 1,716,861 | ||
Investment in subsidiaries | 0 | 0 | ||
Other assets | 7,579 | 58,203 | ||
Total Assets | 1,626,327 | 2,007,246 | ||
Current Liabilities | 211,959 | 285,484 | ||
Long-term liabilities | 1,390,910 | 1,277,708 | ||
Total shareholders’ equity | 23,458 | 444,054 | $ 1,103,441 | $ 841,604 |
Total Liabilities and Shareholders’ Equity | 1,626,327 | 2,007,246 | ||
Reportable Legal Entities [Member] | Parent Company [Member] | ||||
Total current assets | 2,735,830 | 2,578,034 | ||
Total property and equipment, net | 42,181 | 44,499 | ||
Investment in subsidiaries | (1,282,292) | (815,836) | ||
Other assets | 7,423 | 74,679 | ||
Total Assets | 1,503,142 | 1,881,376 | ||
Current Liabilities | 114,805 | 161,792 | ||
Long-term liabilities | 1,348,105 | 1,260,200 | ||
Total shareholders’ equity | 40,232 | 459,384 | ||
Total Liabilities and Shareholders’ Equity | 1,503,142 | 1,881,376 | ||
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member] | ||||
Total current assets | 63,513 | 52,067 | ||
Total property and equipment, net | 1,503,695 | 1,671,774 | ||
Investment in subsidiaries | 0 | 0 | ||
Other assets | 156 | 156 | ||
Total Assets | 1,567,364 | 1,723,997 | ||
Current Liabilities | 2,822,729 | 2,521,572 | ||
Long-term liabilities | 26,927 | 18,261 | ||
Total shareholders’ equity | (1,282,292) | (815,836) | ||
Total Liabilities and Shareholders’ Equity | 1,567,364 | 1,723,997 | ||
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member] | ||||
Total current assets | 0 | 0 | ||
Total property and equipment, net | 3,800 | 3,059 | ||
Investment in subsidiaries | 0 | 0 | ||
Other assets | 0 | 0 | ||
Total Assets | 3,800 | 3,059 | ||
Current Liabilities | 3,800 | 3,059 | ||
Long-term liabilities | 0 | 0 | ||
Total shareholders’ equity | 0 | 0 | ||
Total Liabilities and Shareholders’ Equity | 3,800 | 3,059 | ||
Consolidation, Eliminations [Member] | ||||
Total current assets | (2,726,355) | (2,397,919) | ||
Total property and equipment, net | (3,916) | (2,471) | ||
Investment in subsidiaries | 1,282,292 | 815,836 | ||
Other assets | 0 | (16,632) | ||
Total Assets | (1,447,979) | (1,601,186) | ||
Current Liabilities | (2,729,375) | (2,400,939) | ||
Long-term liabilities | 15,878 | (753) | ||
Total shareholders’ equity | 1,265,518 | 800,506 | ||
Total Liabilities and Shareholders’ Equity | $ (1,447,979) | $ (1,601,186) |
Condensed Consolidating Finan75
Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Total revenues | $ 143,831 | $ 111,177 | $ 107,324 | $ 81,262 | $ 99,422 | $ 106,237 | $ 123,494 | $ 100,050 | $ 443,594 | $ 429,203 | $ 710,187 |
Total costs and expenses | 1,119,068 | 1,727,963 | 359,977 | ||||||||
Income (loss) from continuing operations before income taxes | (675,474) | (1,298,760) | 350,210 | ||||||||
Loss on sale of oil and gas properties | 0 | 0 | 0 | ||||||||
Operating income (loss) | 55,000 | 31,634 | 27,167 | (7,491) | 4,484 | (3,752) | 14,034 | (2,588) | |||
Income tax benefit | 0 | 140,875 | (127,927) | ||||||||
Equity in loss of subsidiaries | 0 | 0 | 0 | ||||||||
Income (Loss) From Continuing Operations | (675,474) | (1,157,885) | 222,283 | ||||||||
Income from discontinued operations, net of income taxes | 0 | 2,731 | 4,060 | ||||||||
Net income from discontinued operations, net of income taxes | 0 | 2,731 | 4,060 | ||||||||
Net Income (Loss) | $ (779) | $ (101,174) | $ (262,126) | $ (311,395) | $ (380,165) | $ (707,647) | $ (46,132) | $ (21,210) | (675,474) | (1,155,154) | 226,343 |
Reportable Legal Entities [Member] | Parent Company [Member] | |||||||||||
Total revenues | 482 | 1,708 | 3,938 | ||||||||
Costs and Expenses | 208,054 | 95,464 | |||||||||
Total costs and expenses | (76,531) | ||||||||||
Income (loss) from continuing operations before income taxes | (207,572) | (93,756) | 80,469 | ||||||||
Income tax benefit | 0 | 10,125 | (28,164) | ||||||||
Equity in loss of subsidiaries | 467,410 | 1,049,010 | 171,554 | ||||||||
Income (Loss) From Continuing Operations | (674,982) | (1,132,641) | 223,859 | ||||||||
Income from discontinued operations, net of income taxes | 0 | 2,731 | |||||||||
Net income from discontinued operations, net of income taxes | 4,060 | ||||||||||
Net Income (Loss) | (674,982) | (1,129,910) | 227,919 | ||||||||
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member] | |||||||||||
Total revenues | 443,112 | 427,495 | 706,121 | ||||||||
Costs and Expenses | 910,522 | 1,603,515 | |||||||||
Total costs and expenses | 442,343 | ||||||||||
Income (loss) from continuing operations before income taxes | (467,410) | (1,176,020) | 263,778 | ||||||||
Income tax benefit | 0 | 127,010 | (92,322) | ||||||||
Equity in loss of subsidiaries | 0 | 0 | |||||||||
Income (Loss) From Continuing Operations | (467,410) | (1,049,010) | 171,456 | ||||||||
Income from discontinued operations, net of income taxes | 0 | 0 | |||||||||
Net income from discontinued operations, net of income taxes | 0 | ||||||||||
Net Income (Loss) | (467,410) | (1,049,010) | 171,456 | ||||||||
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member] | |||||||||||
Total revenues | 0 | 0 | 128 | ||||||||
Costs and Expenses | 0 | 0 | |||||||||
Total costs and expenses | 30 | ||||||||||
Income (loss) from continuing operations before income taxes | 0 | 0 | 98 | ||||||||
Income tax benefit | 0 | 0 | 0 | ||||||||
Equity in loss of subsidiaries | 0 | 0 | 0 | ||||||||
Income (Loss) From Continuing Operations | 0 | 0 | 98 | ||||||||
Income from discontinued operations, net of income taxes | 0 | 0 | |||||||||
Net income from discontinued operations, net of income taxes | 0 | ||||||||||
Net Income (Loss) | 0 | 0 | 98 | ||||||||
Consolidation, Eliminations [Member] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
Costs and Expenses | 492 | 28,984 | |||||||||
Total costs and expenses | (5,865) | ||||||||||
Income (loss) from continuing operations before income taxes | (492) | (28,984) | 5,865 | ||||||||
Income tax benefit | 0 | 3,740 | (7,441) | ||||||||
Equity in loss of subsidiaries | (467,410) | (1,049,010) | (171,554) | ||||||||
Income (Loss) From Continuing Operations | 466,918 | 1,023,766 | (173,130) | ||||||||
Income from discontinued operations, net of income taxes | 0 | ||||||||||
Net income from discontinued operations, net of income taxes | 0 | ||||||||||
Net Income (Loss) | $ 466,918 | $ 1,023,766 | $ (173,130) |
Condensed Consolidating Finan76
Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net cash provided by (used in) operating activities from continuing operations | $ 272,768 | $ 378,735 | $ 502,275 | |
Net cash used in investing activities from continuing operations | (619,832) | (673,376) | (940,676) | |
Net cash provided by financing activities from continuing operations | 308,340 | 330,767 | 300,290 | |
Net cash used in discontinued operations | 0 | (4,046) | (8,490) | |
Net decrease in cash and cash equivalents | (38,724) | 32,080 | (146,601) | |
Cash and cash equivalents, beginning of year | 42,918 | 10,838 | 157,439 | |
Cash and cash equivalents, end of year | 4,194 | 42,918 | 10,838 | |
Cash and cash equivalents | 4,194 | 42,918 | 10,838 | $ 157,439 |
Reportable Legal Entities [Member] | Parent Company [Member] | ||||
Net cash provided by (used in) operating activities from continuing operations | (34,773) | 2,655 | (132,683) | |
Net cash used in investing activities from continuing operations | (312,291) | (447,296) | (305,718) | |
Net cash provided by financing activities from continuing operations | 308,340 | 480,767 | 300,290 | |
Net cash used in discontinued operations | 0 | (4,046) | (8,490) | |
Net decrease in cash and cash equivalents | (38,724) | 32,080 | (146,601) | |
Cash and cash equivalents, beginning of year | 42,918 | 10,838 | 157,439 | |
Cash and cash equivalents, end of year | 4,194 | 42,918 | 10,838 | |
Cash and cash equivalents | 42,918 | 10,838 | ||
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member] | ||||
Net cash provided by (used in) operating activities from continuing operations | 307,541 | 376,080 | 634,970 | |
Net cash used in investing activities from continuing operations | (575,824) | (674,758) | (906,509) | |
Net cash provided by financing activities from continuing operations | 268,283 | 298,678 | 271,539 | |
Net cash used in discontinued operations | 0 | 0 | 0 | |
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 from continuing operations | 0 | 0 | (12) | |
Net cash used in investing activities from continuing operations | (740) | 0 | (37,609) | |
Net cash provided by financing activities from continuing operations | 740 | 0 | 37,621 | |
Net cash used in discontinued operations | 0 | 0 | 0 | |
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 from continuing operations | 0 | 0 | 0 | |
Net cash used in investing activities from continuing operations | 269,023 | 448,678 | 309,160 | |
Net cash provided by financing activities from continuing operations | (269,023) | (448,678) | (309,160) | |
Net cash used in discontinued operations | 0 | 0 | 0 | |
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 Inform77
Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 14, 2016 | Oct. 24, 2014 | |
Supplemental Cash Flow Information [Line Items] | ||||||
Cash paid for interest, net of amounts capitalized | $ 75,231 | $ 64,692 | $ 49,379 | |||
Cash paid for income taxes | 0 | 0 | 0 | |||
Change in capital expenditure payables and accruals | (21,492) | (86,878) | 45,716 | |||
Business Combination, Liabilities | $ 4,880 | 4,880 | 0 | 0 | $ 4,880 | $ 423 |
Share-based Compensation, Capitalized Amount | 4,591 | 4,574 | 7,099 | |||
Asset retirement obligation additions | 1,927 | 4,853 | 4,545 | |||
Purchase price adjustments | 10,700 | 0 | 0 | 3,197 | ||
Other non-cash investing activities | 10,068 | 22,562 | 2,244 | |||
Deferred Purchase Payment [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Long-term Debt | $ 0 | $ 0 | $ 0 | $ 148,900 |
Supplemental Disclosures Abou78
Supplemental Disclosures About Oil And Gas Producing Activities (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2016$ / bbls$ / MMcf | Dec. 31, 2015$ / bbls$ / MMcf | Dec. 31, 2014$ / bbls$ / MMcf | |
Crude Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average market prices used in reserves estimates | 39.60 | 47.24 | 92.24 |
Natural Gas Liquids (Bbls) [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average market prices used in reserves estimates | 11.66 | 12 | 27.80 |
Natural Gas (Mcf) [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average market prices used in reserves estimates | $ / MMcf | 1.89 | 1.87 | 3.24 |
Supplemental Disclosures Abou79
Supplemental Disclosures About Oil and Gas Producing Activities (Narrative 2) (Details) MBoe in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)MBoe | Dec. 31, 2015USD ($)MBoe | Dec. 31, 2014USD ($)MBoe | |
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Capitalized interest | $ | $ 17,000 | $ 32,100 | $ 34,500 |
Asset retirement obligation additions | $ | 1,927 | 4,853 | 4,545 |
Internal costs capitalized, oil and gas producing activities | $ | $ 10,500 | $ 15,800 | $ 18,800 |
Reserves discount factor | 10.00% | ||
Proved Developed Reserves [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Extensions and discoveries, Boe | 6,525 | 5,237 | 5,483 |
Purchases of reserves in place, Boe | 4,978 | 4,144 | |
Proved Undeveloped Reserves [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Extensions and discoveries, Boe | 52,047 | 32,067 | 33,048 |
Purchases of reserves in place, Boe | 1,167 | 11,369 | |
Barrel of Oil Equivalent (Boe) [Domain] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Extensions and discoveries, Boe | 58,572 | 37,304 | 38,531 |
Revisions of previous estimates, Boe | (19,713) | (4,323) | 7,469 |
Purchases of reserves in place, Boe | 6,145 | 15,512 | |
Price Reserve Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, Boe | (6,705) | (15,846) | |
Removed Reserves Of Uneconomic Wells [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, Boe | (3,228) | (6,208) | |
Revisions Due To Reduced Tail Reserves [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, Boe | (3,477) | (9,638) | |
Performance Reserve Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, Boe | (6,083) | 11,523 | |
Development Plan Revisions [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Revisions of previous estimates, Boe | (6,925) | ||
Eagle Ford Shale [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Percentage of reserve additions | 79.00% | 89.00% | 92.00% |
Delaware Basin [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Percentage of reserve additions | 20.00% | ||
Sanchez Acquisition [Member] | |||
Supplemental Oil And Gas Reserve Information [Line Items] | |||
Asset retirement obligation additions | $ | $ 2,037 |
Supplemental Disclosures Abou80
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved property acquisition costs | $ 90,661 | $ 0 | $ 183,633 |
Unproved properties | 113,535 | 63,446 | 215,021 |
Total property acquisition costs | 204,196 | 63,446 | 398,654 |
Exploration costs | 37,508 | 117,227 | 194,956 |
Development costs | 374,134 | 389,396 | 530,268 |
Total costs incurred | $ 615,838 | $ 570,069 | $ 1,123,878 |
Supplemental Disclosures Abou81
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, 2016MBoeMMcfMBbls | Dec. 31, 2015MBoeMMcfMBbls | Dec. 31, 2014MBoeMMcfMBbls | Dec. 31, 2013MBoeMMcfMBbls | |
Crude Oil [Member] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year | 109,588 | 100,704 | 62,041 | |
Extensions and discoveries | 40,074 | 26,358 | 29,793 | |
Revisions of previous estimates | (16,731) | (9,059) | 3,046 | |
Purchases of reserves in place | 4,810 | 12,730 | ||
Production | (9,423) | (8,415) | (6,906) | |
Proved developed and undeveloped reserves end of year | 128,318 | 109,588 | 100,704 | |
Proved developed reserves (volume) | 51,062 | 42,311 | 35,238 | 18,321 |
Proved undeveloped reserve (volume) | 77,256 | 67,277 | 65,466 | 43,720 |
Natural Gas Liquids (Bbls) [Member] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year | 20,221 | 13,513 | 8,152 | |
Extensions and discoveries | 8,612 | 5,292 | 3,681 | |
Revisions of previous estimates | (3,230) | 2,768 | 1,270 | |
Purchases of reserves in place | 122 | 1,335 | ||
Production | (1,788) | (1,352) | (925) | |
Proved developed and undeveloped reserves end of year | 23,937 | 20,221 | 13,513 | |
Proved developed reserves (volume) | 9,387 | 7,933 | 5,294 | 2,779 |
Proved undeveloped reserve (volume) | 14,550 | 12,288 | 8,219 | 5,373 |
Natural Gas [Member] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year | MMcf | 244,938 | 221,017 | 187,957 | |
Extensions and discoveries | MMcf | 59,318 | 33,925 | 30,343 | |
Revisions of previous estimates | MMcf | 1,481 | 11,808 | 18,913 | |
Purchases of reserves in place | MMcf | 7,282 | 8,681 | ||
Production | MMcf | (25,574) | (21,812) | (24,877) | |
Proved developed and undeveloped reserves end of year | MMcf | 287,445 | 244,938 | 221,017 | |
Proved developed reserves (volume) | MMcf | 187,054 | 154,725 | 149,697 | 106,976 |
Proved undeveloped reserve (volume) | MMcf | 100,391 | 90,213 | 71,320 | 80,981 |
Barrel of Oil Equivalent (Boe) [Domain] | ||||
Proved Developed and Undeveloped Reserves [Abstract] | ||||
Proved developed and undeveloped reserves beginning of year, Boe | MBoe | 170,632 | 151,053 | 101,519 | |
Extensions and discoveries, Boe | MBoe | 58,572 | 37,304 | 38,531 | |
Revisions of previous estimates, Boe | MBoe | (19,713) | (4,323) | 7,469 | |
Purchases of reserves in place, Boe | MBoe | 6,145 | 15,512 | ||
Production, Boe | MBoe | (15,473) | (13,402) | (11,978) | |
Proved developed and undeveloped reserves end of year, Boe | MBoe | 200,163 | 170,632 | 151,053 | |
Proved developed reserves (energy) | MBoe | 91,625 | 76,032 | 65,482 | 38,929 |
Proved undeveloped reserves (energy) | MBoe | 108,538 | 94,600 | 85,571 | 62,590 |
Supplemental Disclosures Abou82
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 5,903,629 | $ 5,878,348 | $ 10,380,951 | |
Future production costs | (2,241,928) | (2,124,059) | (2,532,106) | |
Future development costs | (1,264,493) | (1,178,773) | (1,680,795) | |
Future income taxes | 0 | 0 | (1,354,524) | |
Future net cash flows | 2,397,208 | 2,575,516 | 4,813,526 | |
Less 10% annual discount to reflect timing of cash flows | (1,093,779) | (1,210,292) | (2,258,444) | |
Standard measure of discounted future net cash flows | $ 1,303,429 | $ 1,365,224 | $ 2,555,082 | $ 1,621,411 |
Supplemental Disclosures Abou83
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure — beginning of period | $ 1,365,224 | $ 2,555,082 | $ 1,621,411 |
Net change in sales prices and production costs related to future production | (346,763) | (2,547,213) | (240,533) |
Net change in estimated future development costs | 74,407 | 342,238 | 89,401 |
Net change due to revisions in quantity estimates | (150,245) | (157,271) | 205,166 |
Accretion of discount | 136,522 | 326,074 | 202,672 |
Changes in production rates (timing) and other | (111,137) | (139,533) | (61,099) |
Total revisions | (397,216) | (2,175,705) | 195,607 |
Net change due to extensions and discoveries, net of estimated future development and production costs | 313,201 | 252,155 | 867,615 |
Net change due to purchases of reserves in place | 43,426 | 0 | 352,867 |
Sales of crude oil, NGLs and natural gas produced, net of production costs | (320,272) | (312,213) | (598,036) |
Previously estimated development costs incurred | 299,066 | 340,247 | 415,963 |
Net change in income taxes | 0 | 705,658 | (300,345) |
Net change in standardized measure of discounted future net cash flows | (61,795) | (1,189,858) | 933,671 |
Standardized measure — end of period | $ 1,303,429 | $ 1,365,224 | $ 2,555,082 |
Selected Quarterly Financial 84
Selected Quarterly Financial Data Selected Quarterly Financial Data (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||
Impairment of proved oil and gas properties | $ 105,100 | $ 197,100 | $ 274,400 | $ 411,600 | $ 812,800 | $ 576,540 | $ 1,224,367 | $ 0 | |
After-tax impairment of oil and gas properties | 0 | ||||||||
Loss on extinguishment of debt | $ 38,137 | 0 | $ 38,137 | $ 0 | |||||
Deferred Tax Assets, Net | $ 0 |
Selected Quarterly Financial 85
Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total revenues | $ 143,831 | $ 111,177 | $ 107,324 | $ 81,262 | $ 99,422 | $ 106,237 | $ 123,494 | $ 100,050 | $ 443,594 | $ 429,203 | $ 710,187 |
Operating income | 55,000 | 31,634 | 27,167 | (7,491) | 4,484 | (3,752) | 14,034 | (2,588) | |||
Net income (loss) from continuing operations | (779) | (101,174) | (262,126) | (311,395) | (380,671) | (708,768) | (46,970) | (21,476) | |||
Net income (loss) | $ (779) | $ (101,174) | $ (262,126) | $ (311,395) | $ (380,165) | $ (707,647) | $ (46,132) | $ (21,210) | $ (675,474) | $ (1,155,154) | $ 226,343 |
Income (Loss) from Continuing Operations (in dollars per share) | $ (0.01) | $ (1.72) | $ (4.46) | $ (5.34) | $ (6.73) | $ (13.75) | $ (0.92) | $ (0.46) | $ (11.27) | $ (22.50) | $ 4.90 |
Net income (loss) per share basic (in dollars per share) | (0.01) | (1.72) | (4.46) | (5.34) | (6.72) | (13.73) | (0.90) | (0.46) | (11.27) | (22.45) | 4.99 |
Net income (loss) from continuing operations, diluted (in dollars per share) | (0.01) | (1.72) | (4.46) | (5.34) | (6.73) | (13.75) | (0.92) | (0.46) | (11.27) | (22.50) | 4.81 |
Net income per share, diluted (in dollars per share) | $ (0.01) | $ (1.72) | $ (4.46) | $ (5.34) | $ (6.72) | $ (13.73) | $ (0.90) | $ (0.46) | $ (11.27) | $ (22.45) | $ 4.90 |