Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 26, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | CALLON PETROLEUM CO | ||
Entity Central Index Key | 928,022 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Public Float | $ 537.5 | ||
Entity Common Stock, Shares Outstanding | 80,843,938 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 1,224 | $ 968 |
Accounts receivable | 39,624 | 30,198 |
Fair value of derivatives | 19,943 | 27,850 |
Other current assets | 1,461 | 1,441 |
Total current assets | 62,252 | 60,457 |
Oil and natural gas properties, full-cost accounting method: | ||
Evaluated properties | 2,335,223 | 2,077,985 |
Less accumulated depreciation, depletion and amortization | (1,756,018) | (1,478,355) |
Net oil and natural gas properties | 579,205 | 599,630 |
Unevaluated properties | 132,181 | 142,525 |
Total oil and natural gas properties | 711,386 | 742,155 |
Other property and equipment, net | 7,700 | 7,118 |
Restricted investments | 3,309 | 3,810 |
Deferred tax asset | 44,688 | |
Deferred financing costs | 3,642 | 4,776 |
Other assets, net | 305 | 342 |
Total assets | 788,594 | 863,346 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 70,970 | 76,753 |
Accrued interest | 5,989 | 5,993 |
Cash-settled restricted stock unit awards | 10,128 | 3,856 |
Asset retirement obligations | 790 | 4,747 |
Deferred tax liability | 6,214 | |
Fair value of derivatives | 1,249 | |
Total current liabilities | 87,877 | 98,812 |
Senior secured revolving credit facility | 40,000 | 35,000 |
Secured second lien term loan, net of unamortized deferred financing costs | 288,565 | 286,576 |
Asset retirement obligations | 4,317 | 1,927 |
Cash-settled restricted stock unit awards | 4,877 | 7,175 |
Other long-term liabilities | 200 | 121 |
Total liabilities | 425,836 | 429,611 |
Stockholders' equity: | ||
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively | 16 | 16 |
Common stock, $0.01 par value, 150,000,000 and 110,000,000 shares authorized; 80,087,148 and 55,225,288 shares outstanding, respectively | 801 | 552 |
Capital in excess of par value | 702,970 | 526,162 |
Accumulated deficit | (341,029) | (92,995) |
Total stockholders' equity | 362,758 | 433,735 |
Total liabilities and stockholders' equity | $ 788,594 | $ 863,346 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Stockholders' equity: | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 150,000,000 | 110,000,000 |
Common stock, shares outstanding | 80,087,148 | 55,225,288 |
Series A Preferred Stock [Member] | ||
Stockholders' equity: | ||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, liquidation preference (in dollars per share) | $ 50 | $ 50 |
Preferred stock, shares authorized | 2,500,000 | 2,500,000 |
Preferred stock, shares outstanding | 1,578,948 | 1,578,948 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Operating revenues: | ||||
Total operating revenues | $ 137,512 | $ 151,862 | $ 102,569 | |
Operating expenses: | ||||
Lease operating expenses | 27,036 | 22,372 | 19,779 | |
Production taxes | 9,793 | 8,973 | 4,133 | |
Depreciation, depletion and amortization | 69,249 | 56,724 | 43,967 | |
General and administrative | 28,347 | 25,109 | 20,534 | |
Accretion expense | 660 | 826 | 1,785 | |
Write-down of oil and natural gas properties | 208,435 | |||
Rig termination fee | 3,075 | |||
Gain on sale of other property and equipment | (1,080) | |||
Impairment of other property and equipment | 1,707 | |||
Acquisition expense | 27 | 668 | ||
Total operating expenses | 346,622 | 113,592 | 91,905 | |
Income (loss) from operations | (209,110) | 38,270 | 10,664 | |
Other (income) expenses: | ||||
Interest expense | 21,111 | 9,772 | 6,094 | |
Gain on early extinguishment of debt | (151) | (3,696) | ||
(Gain) loss on derivative contracts | (28,358) | (31,736) | 1,360 | |
Other income | (198) | (515) | (485) | |
Total other (income) expense | (7,445) | (22,630) | 3,273 | |
Income (loss) before income taxes | (201,665) | 60,900 | 7,391 | |
Income tax expense | 38,474 | 23,134 | 3,104 | |
Income (loss) before equity in earnings of Medusa Spar LLC | (240,139) | 37,766 | 4,287 | |
Equity in earnings of Medusa Spar LLC | 17 | |||
Net income (loss) | (240,139) | 37,766 | 4,304 | |
Preferred stock dividends | (7,895) | (7,895) | (4,627) | |
Income (loss) available to common stockholders | $ (248,034) | $ 29,871 | $ (323) | |
Income (loss) per common share: | ||||
Basic | $ (3.77) | $ 0.67 | $ (0.01) | |
Diluted | $ (3.77) | $ 0.65 | $ (0.01) | |
Shares used in computing income (loss) per common share: | ||||
Basic | 65,708 | 44,848 | 40,133 | |
Diluted | [1] | 65,708 | 45,961 | 40,133 |
Crude Oil [Member] | ||||
Operating revenues: | ||||
Total operating revenues | $ 125,166 | $ 139,374 | $ 88,960 | |
Natural Gas [Member] | ||||
Operating revenues: | ||||
Total operating revenues | $ 12,346 | $ 12,488 | $ 13,609 | |
[1] | Because the Company reported a loss available to common stockholders for the years ended December 31, 2015 and 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Preferred Stock | Common Stock | Capital in Excess of Par | Retained Earnings (Deficit) | Total |
Balance at Dec. 31, 2012 | $ 398 | $ 328,116 | $ (122,543) | $ 205,971 | |
Net income (loss) | 4,304 | 4,304 | |||
Shares issued pursuant to employee benefit plans | 243 | 243 | |||
Restricted stock | 6 | 3,162 | 3,168 | ||
Stock issued | $ 16 | 70,019 | 70,035 | ||
Preferred stock dividend | (4,627) | (4,627) | |||
Balance at Dec. 31, 2013 | 16 | 404 | 401,540 | (122,866) | 279,094 |
Net income (loss) | 37,766 | 37,766 | |||
Shares issued pursuant to employee benefit plans | 262 | 262 | |||
Restricted stock | 4 | 2,054 | 2,058 | ||
Stock issued | 144 | 122,306 | 122,450 | ||
Preferred stock dividend | (7,895) | (7,895) | |||
Balance at Dec. 31, 2014 | 16 | 552 | 526,162 | (92,995) | 433,735 |
Net income (loss) | (240,139) | (240,139) | |||
Shares issued pursuant to employee benefit plans | 268 | 268 | |||
Restricted stock | 8 | 1,323 | 1,331 | ||
Stock issued | 241 | 175,217 | 175,458 | ||
Preferred stock dividend | (7,895) | (7,895) | |||
Balance at Dec. 31, 2015 | $ 16 | $ 801 | $ 702,970 | $ (341,029) | $ 362,758 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (240,139) | $ 37,766 | $ 4,304 |
Adjustments to reconcile net income to cash provided by operating activities: | |||
Depreciation, depletion and amortization | 69,891 | 58,014 | 45,393 |
Write-down of oil and natural gas properties | 208,435 | ||
Accretion expense | 660 | 826 | 1,785 |
Amortization of non-cash debt related items | 3,123 | 1,272 | 471 |
Amortization of deferred credit | (487) | (3,164) | |
Equity in earnings of Medusa Spar LLC | (17) | ||
Deferred income tax expense | 38,474 | 23,134 | 2,778 |
Net loss (gain) on derivatives, net of settlements | 6,658 | (27,650) | 2,730 |
Impairment of other property and equipment | 1,707 | ||
Gain on sale of other property and equipment | (1,080) | ||
Non-cash gain on early debt extinguishment | (151) | (3,696) | |
Non-cash expense related to equity share-based awards | 221 | 1,126 | 2,092 |
Change in the fair value of liability share-based awards | 6,612 | 3,936 | 2,903 |
Payments to settle asset retirement obligations | (3,258) | (3,808) | (721) |
Changes in current assets and liabilities: | |||
Accounts receivable | (4,761) | (7,915) | (3,497) |
Other current assets | (20) | 622 | (560) |
Current liabilities | 8,001 | 12,805 | 3,583 |
Payments to settle vested liability share-based awards related to early retirements | (3,538) | (1,417) | |
Payments to settle vested liability share-based awards | (3,925) | (2,052) | (239) |
Change in other long-term liabilities | 80 | (106) | (711) |
Change in other assets, net | 338 | (448) | (666) |
Net cash provided by operating activities | 86,852 | 94,387 | 54,475 |
Cash flows from investing activities: | |||
Capital expenditures | (227,292) | (232,596) | (159,724) |
Acquisitions | (32,245) | (222,883) | (10,885) |
Proceeds from sales of mineral interests and equipment | 377 | 2,978 | 89,992 |
Distribution from Medusa Spar LLC | 813 | ||
Net cash used in investing activities | (259,160) | (452,501) | (79,804) |
Cash flows from financing activities: | |||
Borrowings on senior secured revolving credit facility | 181,000 | 132,500 | 80,000 |
Payments on senior secured revolving credit facility | (176,000) | (119,500) | (68,000) |
Borrowings on term loan | 382,500 | ||
Payments on term loan | (84,149) | ||
Payment of deferred financing costs | (19,779) | (146) | |
Redemption of 13% senior notes | (50,057) | (50,060) | |
Issuance of preferred stock | 70,035 | ||
Issuance of common stock | 175,459 | 122,450 | |
Payment of preferred stock dividends | (7,895) | (7,895) | (4,627) |
Net cash provided by financing activities | 172,564 | 356,070 | 27,202 |
Net change in cash and cash equivalents | 256 | (2,044) | 1,873 |
Balance, beginning of period | 968 | 3,012 | 1,139 |
Balance, end of period | $ 1,224 | $ 968 | $ 3,012 |
Description of Business and Bas
Description of Business and Basis of Presentation | 12 Months Ended |
Dec. 31, 2015 | |
Description of Business and Basis of Presentation [Abstract] | |
Description of Business and Basis of Presentation | Note 1 - Description of Busi ness and Basis of Presentation Description of business Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. Callon is focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. Basis of presentation Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data. The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 2 – Summary of Significant Accounting Policies A. 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 disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. B. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. C. Accounts Receivable Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners. D. Revenue Recognition and Natural Gas Balancing The Company recognizes revenue under the entitlement s method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2015 and 2014 . In May 2014, the Financial Accounting Standards Board (“FASB”) issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at 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 replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31 , 201 7, including interim periods within that reporting period. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures. E. Major Customers The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended: For the Year Ended December 31, 2015 2014 2013 Enterprise Crude Oil, LLC 42% 51% 38% Plains Marketing, L.P. 19% 22% 15% Permian Transport and Trading 15% 7% — Sunoco 9% 10% — Shell Trading Company 4% — 31% Other 11% 10% 16% Total 100% 100% 100% Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. F. Oil and Natural Gas Properties The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which ca se a gain or loss is recognized . Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. For the period ended December 31, 2015 , the Company recognized a write-down of oil and natural gas properties o f $208,435 a s a result of the ceiling test limita tion. See Note 13 for additional information regarding the Company’s oil and natural gas properties. Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle , abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. G. Other Property and Equipment The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $865 , $836 and $750 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2015 , 2014 and 2013 , respectively. The accumulated depreciation on other property and equipment was $14,719 and $14,005 as of December 31, 2015 and 2014 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 14 for addition al information. H. Capitalized Interest The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2015 , 2014 and 2013 , the Company capitalized $10,459 , $4,295 and $4,410 of interest expense. I. Deferred Financing Costs Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan . Amortization of deferred financing costs of $3,123 , $1,272 and $471 was recorded for the years ended December 31, 2015 , 2014 and 2013 , respectively. In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s carrying value. The guidance in ASU 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein, and is to be applied on a retrospective basis. T he Company adopted this standard effective December 31, 2015. As a result, def erred financing costs of $ 11,435 and $13,424 related to the Company’s secured second lien term loan were reclassified from deferred financing costs to a direct reduction from the debt’s carrying value as of December 31, 2015 and 2014 , respectively . In August 2015, the FASB issued ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). ASU 2015-15 updates the accounting guidance included in ASU 2015-03 a s a result of the June 18, 2015, Emerging Issues Task Force meeting, in which the SEC stated that the SEC staff would not object to an entity deferring and presenting costs related to revolving debt arrangements as a n asset. T he Company adopted this standard effective December 31, 2015. For the y ears ended December 31, 2015 and 2014, deferred financing costs related to the Company’s senior secured revolving credit facility of $3,642 and $4,776 , re spectively, we re presented on the balance sheet as an asset. J. Asset Retirement Obligations The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 12 for additional information. K. Derivatives Derivative contracts outstanding as of December 31, 2015 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts. L. Income Taxes Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets , if any, for which it is deemed more likely than not that it will not be realized. As of December 31, 2015 the valuation allowance wa s $ 108,843 . See Note 11 for additional information. In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which eliminates the requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet . Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet . The guidance in ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016 , and interim periods within those annual periods. Early application is permitted. The Company does not expect the adoption of this ASU will have a material impact on its financial statements. M. Share-Based Compensation The Company grants to directors and employee s stock options a nd restricted stock awards (“RS awards”). The Company also grants restricted stock unit awards (“ RSU awards ”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”). Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years). RS awards, RSU equity awards and Cash-settleable RSU awards. For RS and RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For RSU equity awards with vesting subject to a market condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expe nse is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated fair value recognized over the vesting period (generally three years). N. Statements of Cash Flows Supplemental Information During the three year period ended 2015 , the Company paid no federal income taxes. During the years ended December 31, 2015 , 2014 and 2013 , the company made cash interest payments of $28,437 , $7,283 and $13,189 , respectively. O. Investment in Medusa Spar LLC During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 3 for additional information on the Medusa divestiture. P. Earnings per Share ( “ EPS ” ) The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in share s. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2015 | |
Acquisitions and Dispositions [Abstract] | |
Acquisitions and Dispositions | Note 3 – Acquisitions and Dispositio ns Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach. 2015 acquisitions On November 9, 2015, the Company acquired additional working interest s in 628 net acres located i n the Carpe Diem field and CaBo area in Midland , Andrews , Ector and Martin Counties, Texas, which are located in the central portion of the Midland Basin, for an aggregate cash purchase price of $ 29,800 based on an effective date of October 1, 2015 . The acquisition increases the Company’s working interest in the Carpe Diem field to approximately 100% with a net revenue interest of 79% and increases the working interest in the CaBo area to approximately 67% with a net revenue interest of 50% . The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: Oil and natural gas properties $ 24,926 Unevaluated oil and natural gas properties 4,911 Asset retirement obligations (37) Net assets acquired $ 29,800 2014 acquisitions In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near its existing core development fields, for an aggregate cash purchase price of $8,200 . The properties bear a working interest of 100% and an average net revenue interest of 78% . The following table summarizes the acquisition date fair values of the net assets acquired: Oil and natural gas properties $ 930 Unevaluated oil and natural gas properties 7,394 Asset retirement obligations (124) Net assets acquired $ 8,200 On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205 based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest ( 46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,514 and a portion of the proceeds from borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see Notes 5 and 10 , respectively. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: Oil and natural gas properties $ 91,895 Unevaluated oil and natural gas properties 118,450 Asset retirement obligations (140) Net assets acquired $ 210,205 The following unaudited summary pro forma financial information for the year s ended December 31, 2014 and 2013 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition and the debt transactions and equity offering discussed in Notes 5 and 10 , respectively, occurred as of January 1, 2013. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. For the Years Ended December 31, 2014 2013 Revenues $ 180,458 $ 151,766 Income from operations 53,526 36,002 Income available to common stockholders 33,674 4,033 Net income per common share Basic $ 0.57 $ 0.07 Diluted $ 0.56 $ 0.07 2013 acquisitions During the second quarter of 2013, the Company acquired approximately 2,468 gross ( 2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the Southern Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 10 ). The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: Oil and natural gas properties $ 9,025 Unevaluated oil and natural gas properties 2,000 Asset retirement obligations (25) Net assets acquired $ 11,000 2013 dispositions During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties for total net cash consideration of approximately $88,000 . Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2,000 . This was the Company’s only field in the Haynesville shale. The proceeds from these sales were accounted for as a reduction to capitalized costs as the sales did not significantly alter the relationship between capitalized costs and proved reserves. Subsequent event Subsequent to December 31, 2015, the Company completed the acquisition of an additional 4.9% working interest ( 3.7 % net revenue interest) in the CaBo area for total cash consideration of $ 9,300 , excluding customary purchase price adjustments. Following the completion of this acquisition the Company will own 71.3% working interest ( 53.5% net revenue interest) in the CaBo area . |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Note 4 - Ear nings Per Share Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: For the Year Ended December 31, 2015 2014 2013 Net income (loss) $ (240,139) $ 37,766 $ 4,304 Preferred stock dividends (7,895) (7,895) (4,627) Income (loss) available to common stockholders $ (248,034) $ 29,871 $ (323) Weighted average shares outstanding 65,708 44,848 40,133 Dilutive impact of restricted stock — 1,113 — Weighted average shares outstanding for diluted income (loss) per share (a) 65,708 45,961 40,133 Basic income (loss) per share $ (3.77) $ 0.67 $ (0.01) Diluted income (loss) per share $ (3.77) $ 0.65 $ (0.01) The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive: Stock options 15 30 52 Restricted stock 126 317 398 (a) Because the Company reported a loss available to common stockholders for the years ended December 31, 2015 and 2013 , no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. |
Borrowings
Borrowings | 12 Months Ended |
Dec. 31, 2015 | |
Borrowings [Abstract] | |
Borrowings | Note 5 – Borr owings The Company’s borrowings consisted of the following at: For the Year Ended December 31, 2015 2014 Principal components: Senior secured revolving credit facility $ 40,000 $ 35,000 Secured second lien term loan 300,000 300,000 Total principal outstanding 340,000 335,000 Secured second lien term loan, unamortized deferred financing costs (11,435) (13,424) Total carrying value of borrowings $ 328,565 $ 321,576 C redit F acility On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019 . JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Ban k of Canada. The total notional amount available under the Credit Facility is $500,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. As of December 31, 2015, the Credit Facility’s borrowing base was $ 300,000 . The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. As of December 31, 2015 , the balance outstanding on the Credit Facility was $40,000 with a weighted-average interest rate of 2.07% , calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base. The Company had $ 260,000 of available borrowings under the Credit Facility as of December 31, 2015 . Term loans On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000 , including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019, and was not subject to mandatory prepayments unless new debt or preferred stock was issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. On April 10, 2014, the Company drew an initial amount of $62,500 with an original issue discount of 1.0% . On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the Central Midland Acquisition, resulting in a loss on early extinguishment of debt of $3,054 . The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014, the Company drew an initial amount of $300,000 with a discount of 2.0% and an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0% %) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2016, and (ii) 101% if the prepayment event occurs on or after October 8, 2016 but before October 8, 2017, and (iii) 100% for prepayments made on or after October 8, 2017. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. As of December 31, 2015 , the balance outstanding on the Second Lien Loan was $ 300,000 with an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0% ) plus 7.5% per annum. The Company can elect a LIBOR rate based on various tenors, and is currently incurring interest based on an underlying three-month LIBOR rate, which was last elected in January 2016. 13% senior notes due 2016 (“Senior Notes”) and deferred credit On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Loan. The redemption resulted in a net $3,205 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes ( $1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193 in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms. Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013 , the Company redeemed $48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes (inclusive of $1,576 of redemption expenses, primarily the call premium) and the carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit amortization). Restrictive covenants The Company’s Credit Facility and Second Lien Loan contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2015 . |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Derivative Instruments and Hedging Activities | Note 6 - Der ivative Instruments and Hedging Activities Objectives and strategies for using derivative instruments The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, puts, calls and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. Counterparty risk and offsetting The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value. The Company executes commodity derivative contracts under master agreements that have netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. Financial statement presentation and settlements Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. Derivatives not designated as hedging instruments The Company records its derivative contracts at fair value in the consolidated balance sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations. The following table reflects the fair value of the Company’s derivative instruments not designated as hedging instruments under ASC 815 for the periods presented: Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 12/31/2015 12/31/2014 12/31/2015 12/31/2014 12/31/2015 12/31/2014 Natural gas Current Fair value of derivatives $ — $ 1,262 $ — $ (7) $ — $ 1,255 Oil Current Fair value of derivatives 19,943 26,588 — (1,242) 19,943 25,346 Total $ 19,943 $ 27,850 $ — $ (1,249) $ 19,943 $ 26,601 As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: For the Year Ended December 31, 2015 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives $ 19,943 $ — $ 19,943 For the Year Ended December 31, 2014 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives $ 27,850 $ — $ 27,850 Current liabilities: Fair value of derivatives (1,249) — (1,249) Derivatives not designated as hedging instruments under ASC 815 For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: For the Year Ended December 31, 2015 2014 2013 Natural gas derivatives Net gain (loss) on settlements $ 1,717 $ (84) $ (148) Net gain (loss) on fair value adjustments (1,255) 1,267 230 Total gain (loss) $ 462 $ 1,183 $ 82 Oil derivatives Net gain (loss) on settlements $ 33,299 $ 4,170 $ 1,518 Net gain (loss) on fair value adjustments (5,403) 26,383 (2,960) Total gain (loss) $ 27,896 $ 30,553 $ (1,442) Total gain (loss) on derivative contracts $ 28,358 $ 31,736 $ (1,360) Derivative positions As of December 31, 2015, the Company had no outstanding natural gas derivative contracts. Listed in the table below are the outstanding oil derivative contracts as of December 31, 2015 : For the Three Months Ended March 31, June 30, September 30, December 31, Oil contracts 2016 2016 2016 2016 Swap contracts (NYMEX) Total volume (MBbls) 182 182 184 184 Weighted average price per Bbl $ 58.23 $ 58.23 $ 58.23 $ 58.23 Swap contracts (Midland basis differentials) Volume (MBbls) 364 364 368 368 Weighted average price per Bbl $ 0.17 $ 0.17 $ 0.17 $ 0.17 Collar contracts combined with short puts (WTI, three-way collar) Total volume (MBbls) 182 182 184 184 Weighted average price per Bbl Ceiling (short call) $ 65.00 $ 65.00 $ 65.00 $ 65.00 Floor (long put) $ 55.00 $ 55.00 $ 55.00 $ 55.00 Short put $ 40.33 $ 40.33 $ 40.33 $ 40.33 The following derivative contracts for oil and natural gas were executed subsequent to December 31, 2015 : For the Three Months Ended March 31, June 30, September 30, December 31, Oil contracts 2016 2016 2016 2016 Collar contracts Total volume (MBbls) 120 182 184 184 Weighted average price per Bbl Ceiling (short call) $ 46.50 $ 46.50 $ 46.50 $ 46.50 Floor (long put) $ 37.50 $ 37.50 $ 37.50 $ 37.50 Natural gas contracts Swap contracts Total volume (BBtu) 360 546 552 552 Weighted average price per MMBtu $ 2.52 $ 2.52 $ 2.52 $ 2.52 For the Three Months Ended March 31, June 30, September 30, December 31, Oil contracts 2017 2017 2017 2017 Call contracts (short) Total volume (MBbls) 165 167 169 169 Weighted average price per Bbl Call strike price $ 50.00 $ 50.00 $ 50.00 $ 50.00 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | Note 7 - Fair Valu e Measurements The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. Fair Value of Financial Instruments Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. Debt. The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. Assets and liabilities measured at fair value on a recurring basis Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: December 31, 2015 Balance Sheet Presentation Level 1 Level 2 Level 3 Total Assets Derivative financial instruments (current) Fair value of derivatives $ — $ 19,943 $ — $ 19,943 Liabilities Derivative financial instruments (current) Fair value of derivatives $ — $ — $ — $ — Total net assets $ — $ 19,943 $ — $ 19,943 December 31, 2014 Balance Sheet Presentation Level 1 Level 2 Level 3 Total Assets Derivative financial instruments (current) Fair value of derivatives $ — $ 27,850 $ — $ 27,850 Liabilities Derivative financial instruments (current) Fair value of derivatives $ — $ (1,249) $ — $ (1,249) Total net assets $ — $ 26,601 $ — $ 26,601 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Acquisition. A s discussed in Note 3 , the Company completed acquisitions during 2014 and 2015. The Company determined the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve quantities , costs to produce and develop reserves , and oil and gas forward prices. Asset retirement obligations assumed in connection with acquisition s were determined in accordance with applicable accounting standards. The fair value measurements were based on level 2 and level 3 inputs. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2015 | |
Employee Benefit Plans [Abstract] | |
Employee Benefit Plans | Note 8 – Emplo yee Benefit Plans The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9 . The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan: Savings and Protection Plan The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $999 , $1,017 and $923 in the years 2015 , 2014 and 2013 , respectively. 2011 Omnibus Incentive Plan (the “2011 Plan”) The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the plan. Another provision provided that shares which would otherwise become available for issuance under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the Company’s common stock available for grant under the Plan by 2,000,000 shares from 2,300,000 shares to 4,300,000 shares, (ii) the adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan is 5,141,000 as of the effective date of the First Amendment. As of December 31, 2015 , the 2011 Plan had 2,926,545 shares remaining and eligible for future issuance. RSU e quity a wards . RSU equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU e quity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For market-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date . A wards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Market-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. Cash-settled RSU awards. Certain of the Company’s RSUs awarded require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. A significant portion of the Company’s cash-settled RSU awards include a market-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. |
Share-Based Compensation
Share-Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Share-based Compensation [Abstract] | |
Share-Based Compensation | Note 9 - Shar e-Based Compensation As discussed in Note 8 , the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2015 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 2,926,545 . The following table presents share-based compensation expense for each respective period: For the Year Ended December 31, 2015 2014 2013 Share-based compensation cost for: Equity-based Liability-based Equity-based Liability-based Equity-based Liability-based RSU equity awards $ 3,797 $ — $ 4,223 $ — $ 3,975 $ — Cash-settleable RSU awards — 11,437 — 6,918 — 5,347 401(k) contributions in shares 266 — 270 — 219 — Total share-based compensation cost (a) $ 4,063 $ 11,437 $ 4,493 $ 6,918 $ 4,194 $ 5,347 (a) The portion of this share-based compensation cost that was included in general and administrative expense totaled $9,299 , $ 7,235 and $ 5,751 for the same years, respectively, and the portion capitalized to oil and gas properties was $6,201 , $ 4,176 and $ 3,791 , respectively . The following table presents the unrecognized compensation cost for the indicated periods: December 31, Unrecognized compensation cost related to: 2015 2014 2013 Unvested RSU equity awards $ 5,208 $ 3,979 $ 5,331 Unvested cash-settleable RSU awards 4,728 4,977 7,669 The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 1.8 years . The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated: December 31, Consolidated Balance Sheets Classification 2015 2014 Cash-settled restricted stock unit awards (current) $ 10,128 $ 3,856 Cash-settled restricted stock unit awards (non-current) 4,877 7,175 Total cash-settled RSU awards $ 15,005 $ 11,031 Stock Options The Company issued no stock options for the past three years and had no options vest or forfeit during 2015 . Additionally, no options were exercised, and 15,000 options expired unexercised during the year. As of December 31, 2015 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. As of December 31, 2014 , the Company had 30,000 options outstanding and exercisable at a weighted average exercise price per option of $14.04 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. As of December 31, 2013, the Company had 52,000 options outstanding and exercisable at a weighted average exercise price per option of $13.75 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. Restricted Stock Units The following table represents unvested restricted stock activity for the year ended December 31, 2015 : Weighted average (shares in 000s) Number of Shares Grant-Date Fair Value per Share Period over which expense is expected to be recognized Outstanding at the beginning of the period 1,868 $ 5.40 Granted (a) 560 8.98 Vested (b) (1,012) 5.36 Forfeited — Outstanding at the end of the period 1,416 $ 6.94 1.5 (a) Includes 126 market-based RSUs that will vest at a range of 0% - 200% . See Note 8 for additional information about market-based RSU equity awards. (b) The fair value of shares vest ed was $5,425 . For the year ended December 31, 2 014 , the Company granted 333,000 RSUs with a weighted average grant-date fair value of $ 9.67 per share. The fair value of shares vested during 2014 was $ 4,338 . For the year ended December 31, 2013, the Company granted 944,000 RSUs with a weighted average grant-date fair value of $3.82 per share. The fair value of shares vested during 2013 was $2,689 . As of December 31, 2015 , the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition): (shares in 000s) Base Units Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting Vesting in 2016 332 45 619 Vesting in 2017 231 19 443 Vesting in 2018 25 25 25 Other 167 167 167 Total cash-settleable RSUs 755 256 1,254 For the year ended December 31, 2015 , 853,673 market-based cash-settled RSUs subject to the peer market-based vesting described in Note 8 vested at between 150% - 200% of their issued units, depending on the date of vesting , resulting in cash payments of $3,319 in 2015 and payable amounts of $9,807 in 2016 . Also during 2015 , 72,108 non-market-based cash settled RSUs vested, resulting in cash payments of $545 in 2015 . During 2014 , 523,000 market-based cash-settled RSUs subject to the peer market-based vesting described above vested at between 150% - 200% of their issued units, depending on the date of the vesting, resulting in cash payments of $1,241 in 2014 and $ 3,599 in 2015 . Also during 2014 , 58,000 non-market-based cash settled RSUs vested, resulting in cash payments of $559 in 2014 . See Note 8 for additional information regarding cash-settleable RSUs. |
Equity Transactions
Equity Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Equity Transactions [Abstract] | |
Equity Transactions | Note 10 – Eq uity Transactions 10% Series A Cumulative Preferred Stock (“Preferred Stock”) Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7,895 , $7,895 and $ 4,627 in 2015 , 2014 and 2013 respectively. The Preferred Stock has no stated maturity and is not be subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. Following a change of control, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon a change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2015 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $ 8.34 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.0 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. Subsequent to December 31, 2015, a total of 120,000 shares of Preferred Stock were exchanged for a total of 719,000 shares of Common Stock. Common Stock On November 16, 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $ 8.40 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $ 109,913 , after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility. On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $ 6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $ 65,644 , after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility. On September 15, 2014 the Company completed an underwritten public offering of 12,500,000 shares of its common stock at $9.00 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares of common stock at $9.00 per share. The Company received net proceeds of approximately $122,514 , after the underwriting discounts and estimated offering costs, which were used to fund a portion of the purchase price of the Central Midland Basin Acquisition (see Note 3 ). |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes [Abstract] | |
Income Taxes | Note 11 - Inco me Taxes The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences: As of December 31, 2015 2014 Deferred tax asset Federal net operating loss carryforward $ 107,935 $ 86,629 Statutory depletion carryforward 8,843 8,876 Alternative minimum tax credit carryforward 208 208 Asset retirement obligations 630 1,003 Other 8,241 6,621 Deferred tax asset before valuation allowance 125,857 103,337 Deferred tax liability Oil and natural gas properties 6,488 54,723 Other 10,526 10,140 Total deferred tax liability 17,014 64,863 Net deferred tax asset before valuation allowance 108,843 38,474 Less: Valuation allowance (108,843) — Net deferred tax asset $ — $ 38,474 If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows: Year Expiring Total 2016-2021 2022-2024 2025-2027 2028-2030 2031-2035 Federal NOL carryforwards $ 308,385 $ 13,892 $ 101,495 $ 39,714 $ 32,111 $ 121,173 As a result of the write-down of oil and natural gas properties discussed in Note 13 , the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $ 108,843 as of December 31, 2015 . The Company had no significant unrecognized tax benefits at December 31, 2015 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2002 through 2015 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations : For the Year Ended December 31, Components of income tax rate reconciliation 2015 2014 2013 Income tax expense computed at the statutory federal income tax rate 35% 35% 35% Percentage depletion carryforward —% —% (8)% State taxes net of federal benefit 1% 1% 4% Restricted stock and stock options —% —% 5% Section 162(m) (1)% 2% 6% Valuation allowance (54)% —% —% Effective income tax rate (19)% 38% 42% For the Year Ended December 31, Components of income tax expense 2015 2014 2013 Current state income tax expense $ — $ — $ 326 Deferred federal income tax (benefit) expense (69,087) 22,373 2,652 Deferred state income tax (benefit) expense (1,282) 761 126 Valuation allowance 108,843 — — Total income tax expense $ 38,474 $ 23,134 $ 3,104 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | Note 12 - Asset Reti rement Obligations The table below summarizes the activity for the Company’s asset retirement obligations: For the Year Ended December 31, 2015 2014 Asset retirement obligations at January 1, 2015 $ 6,674 $ 6,732 Accretion expense 660 826 Liabilities incurred 165 638 Liabilities assumed — 140 Liabilities settled (2,964) (2,130) Revisions to estimate 572 468 Asset retirement obligations at end of period 5,107 6,674 Less: Current asset retirement obligations (790) (4,747) Long-term asset retirement obligations at December 31, 2015 $ 4,317 $ 1,927 Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2015 and 2014 as long-term restricted investments were $3,309 and $3,810 , respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Properties (unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Information on Oil and Natural Gas Properties [Abstract] | |
Supplemental Information on Oil and Natural Gas Properties (unaudited) | Note 13 – Supplemental Information on Oil and N atural Gas Properties (Unaudited) The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States. For the Year Ended December 31, 2015 2014 2013 Evaluated Properties Beginning of period balance $ 2,077,985 $ 1,701,577 $ 1,497,010 Capitalized G&A 10,529 10,071 10,014 Property acquisition costs (a) 26,726 94,541 10,885 Exploration costs 81,320 118,251 147,164 Development costs 138,663 153,545 36,504 End of period balance $ 2,335,223 $ 2,077,985 $ 1,701,577 Unevaluated Properties Beginning of period balance $ 142,525 $ 43,222 $ 68,776 Property acquisition costs (a) 5,520 128,342 2,259 Exploration costs 4,576 11,177 10,767 Capitalized interest 10,459 4,295 4,410 Transfers to evaluated (30,899) (44,511) (42,990) End of period balance $ 132,181 $ 142,525 $ 43,222 Accumulated depreciation, depletion and amortization Beginning of period balance $ 1,478,355 $ 1,420,612 $ 1,296,265 Provision charged to expense 69,228 56,663 42,251 Write-down of oil and natural gas properties 208,435 — — Sale of mineral interests — 1,080 82,096 End of period balance $ 1,756,018 $ 1,478,355 $ 1,420,612 (a) For more information on acquisitions refer to Note 3 . Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three to five years. Subsequent to December 31, 2015 and through February 26, 2016 , the Company dri lled 5 gross horizontal wells and completed 2 gross horizontal wells and had 5 gross horizontal wells awaiting completion. Depletion per unit-of-production, on a BOE basis, amounted to $19.74 , $27.51 and $31.12 for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $7.71 , $10.85 , and $14.00 for the years ended December 31, 2015 , 2014 , and 2013 , respectively. The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2015, the prices used in determining the estimated future net cash flows from proved reserves were $47.25 per barrel of oil and $2.73 per Mcf of natural gas. For the year ended December 31, 2015, the Company recognized a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation. Estimated Reserves The Company’s proved oil and natural gas reserves at December 31, 2015 and 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The Company’s proved oil and natural gas reserves at December 31, 2013 were estimated by Huddleston & Co., Inc. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. The following tables disclose c hanges in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: For the Year Ended December 31, Proved developed and undeveloped reserves: 2015 2014 2013 Oil (MBbls): Beginning of period 25,733 11,898 10,780 Revisions to previous estimates (1,632) (243) (2,540) Purchase of reserves in place 2,932 3,223 150 Sale of reserves in place (23) — (3,294) Extensions and discoveries 19,127 12,547 7,713 Production (2,789) (1,692) (911) End of period 43,348 25,733 11,898 Natural Gas (MMcf): Beginning of period 42,548 17,751 19,753 Revisions to previous estimates 4,870 (215) (5,351) Purchase of reserves in place 2,915 8,591 317 Sale of reserves in place (105) — (4,576) Extensions and discoveries 19,621 18,641 10,619 Production (4,312) (2,220) (3,011) End of period 65,537 42,548 17,751 For the Year Ended December 31, Proved developed reserves: 2015 2014 2013 Oil (MBbls): Beginning of period 14,006 5,960 4,955 End of period 22,257 14,006 5,960 Natural gas (MMcf): Beginning of period 25,171 9,059 10,680 End of period 38,157 25,171 9,059 MBOE: Beginning of period 18,201 7,470 6,735 End of period 28,617 18,201 7,470 Proved undeveloped reserves: Oil (MBbls): Beginning of period 11,727 5,938 5,825 End of period 21,091 11,727 5,938 Natural gas (MMcf): Beginning of period 17,377 8,692 9,073 End of period 27,380 17,377 8,692 MBOE: Beginning of period 14,623 7,387 7,337 End of period 25,654 14,623 7,387 Total Proved Reserves: The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 36 gross ( 27.1 net) wells, and acquisitions made during 2015 . This increase was primarily offset by 2015 production and revisions. The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 34 gross ( 28.7 net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions. The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories. Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014 , respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19% , included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933 , net. The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24% , included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $ 34,619 , net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development. The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by 3,724 MBOE, or 51% , included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to horizontal probable reserves, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include locations that included certain target zones that were expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18% , included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells. Standardized Measure The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2015 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods: 2015 2014 2013 Average 12-month price, net of differentials, per Mcf of natural gas $ 2.73 $ 6.38 $ 5.45 Average 12-month price, net of differentials, per barrel of oil $ 47.25 $ 86.30 $ 92.16 Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Natural gas production from our Permian Basin properties has a high Btu content of separator natural gas. The natural gas per Mcf prices of $2.73 , $6.38 and $5.45 used in the 2015 , 2014 and 2013 reserve estimates , respectively, include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices per Bbl of $47.25 , $86.30 and $92.16 used in the 2015 , 2014 and 2013 reserve estimates , respectively, have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. Standardized Measure For the Year Ended December 31, 2015 2014 2013 Future cash inflows $ 2,227,463 $ 2,492,178 $ 1,193,299 Future costs Production (827,555) (873,469) (357,005) Development and net abandonment (239,100) (288,081) (155,667) Future net inflows before income taxes 1,160,808 1,330,628 680,627 Future income taxes — (164,490) (68,239) Future net cash flows 1,160,808 1,166,138 612,388 10% discount factor (589,918) (586,596) (328,442) Standardized measure of discounted future net cash flows $ 570,890 $ 579,542 $ 283,946 Changes in Standardized Measure For the Year Ended December 31, 2015 2014 2013 Standardized measure at the beginning of the period $ 579,542 $ 283,946 $ 231,148 Sales and transfers, net of production costs (110,476) (120,518) (78,661) Net change in sales and transfer prices, net of production costs (286,660) (156,066) (46,088) Net change due to purchases and sales of in place reserves 37,616 111,331 (145,711) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 184,469 299,192 212,431 Changes in future development cost 108,216 186,605 153,983 Revisions of quantity estimates (12,625) (7,673) (68,958) Accretion of discount 62,968 30,114 25,010 Net change in income taxes 35,407 (32,940) 1,751 Changes in production rates, timing and other (27,567) (14,449) (959) Aggregate change (8,652) 295,596 52,798 Standardized measure at the end of period $ 570,890 $ 579,542 $ 283,946 |
Other
Other | 12 Months Ended |
Dec. 31, 2015 | |
Other [Abstract] | |
Other | Note 14 – Other Commitments and contingencies The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. Operating leases As of December 31, 2015 , the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”). The Cactus 1 Rig was initially contracted for a term of two years in April 2012. The Cactus 2 Rig was initially contracted for a term of two years in April 2014. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In March 2015, the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018, respectively. The rig lease agreements include early termination provisions that obligate the Company to reduced minimum rentals pursuant to a “standby” dayrate for the term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. In January 2016, the Company decided to place the Cactus 1 Rig on standby and will be required to pay a “standby” day rate of $ 15,000 per day, pursuant to the terms of the agreement, and the Company retains the option to return the rig to service. In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015). The Company paid approximately $ 3,075 in reduced rental payments over the remainder of the lease term, which ended November 2015. The amount was recognized as rig termination fee on the consolidated statements of operations for the year ended December 31 , 2015 . Other property and equipment During 2012, the Company sold certain specialized deep water property and equipment valued at $527 and determined that certain equipment components were not usable without additional rework and thus recorded an impairment charge to with respect to such equipment of $1,177 . During 2013, after selling certain specialized deep water property and equipment valued at $114 , the Company made a decision to abandon the equipment. As such the Company recorded an impairment charge of $1,707 representing the remaining value of this equipment. During 2014, the Company entered into an agreement to sell the property and equipment to a third party. As a result of the subsequent sale of the property and equipment, the Company recognized a gain of $1,080 . |
Summarized Quarterly Financial
Summarized Quarterly Financial Information (unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Summarized Quarterly Financial Information [Abstract] | |
Summarized Quarterly Financial Information (unaudited) | Note 15 – S ummarized Quarterly Financial Information (Unaudited) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenues $ 30,391 $ 39,242 $ 34,316 $ 33,563 Income (loss) from operations (a) (12,889) 6,231 (83,910) (118,542) Net loss (a) (10,197) (4,967) (111,805) (113,170) Loss available to common shares (12,171) (6,940) (113,779) (115,144) Loss per common share - basic $ (0.21) $ (0.11) $ (1.72) $ (1.58) Loss per common share - diluted $ (0.21) $ (0.11) $ (1.72) $ (1.58) (a) Loss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and gas properties of $ 87,301 and $121,134 , r espectively. 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenues $ 33,285 $ 40,502 $ 39,657 $ 38,418 Income from operations 6,645 12,080 11,562 7,983 Net income (loss) 1,863 4,740 12,201 18,962 Income (loss) available to common shares (111) 2,767 10,227 16,988 Income (loss) per common share - basic $ 0.00 $ 0.07 $ 0.24 $ 0.31 Income (loss) per common share - diluted $ 0.00 $ 0.07 $ 0.23 $ 0.30 |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Use of Estimates | A. 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 disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Cash and Cash Equivalents | B. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. |
Accounts Receivable | C. Accounts Receivable Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners. |
Revenue Recognition and Natural Gas Balancing | D. Revenue Recognition and Natural Gas Balancing The Company recognizes revenue under the entitlement s method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2015 and 2014 . In May 2014, the Financial Accounting Standards Board (“FASB”) issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at 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 replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31 , 201 7, including interim periods within that reporting period. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures. |
Major Customers | E. Major Customers The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended: For the Year Ended December 31, 2015 2014 2013 Enterprise Crude Oil, LLC 42% 51% 38% Plains Marketing, L.P. 19% 22% 15% Permian Transport and Trading 15% 7% — Sunoco 9% 10% — Shell Trading Company 4% — 31% Other 11% 10% 16% Total 100% 100% 100% Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. |
Oil and Natural Gas Properties | F. Oil and Natural Gas Properties The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which ca se a gain or loss is recognized . Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. For the period ended December 31, 2015 , the Company recognized a write-down of oil and natural gas properties o f $208,435 a s a result of the ceiling test limita tion. See Note 13 for additional information regarding the Company’s oil and natural gas properties. Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle , abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. |
Other Property and Equipment | G. Other Property and Equipment The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $865 , $836 and $750 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2015 , 2014 and 2013 , respectively. The accumulated depreciation on other property and equipment was $14,719 and $14,005 as of December 31, 2015 and 2014 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 14 for addition al information. |
Capitalized Interest | H. Capitalized Interest The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2015 , 2014 and 2013 , the Company capitalized $10,459 , $4,295 and $4,410 of interest expense. |
Deferred Financing Costs | I. Deferred Financing Costs Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan . Amortization of deferred financing costs of $3,123 , $1,272 and $471 was recorded for the years ended December 31, 2015 , 2014 and 2013 , respectively. In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s carrying value. The guidance in ASU 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein, and is to be applied on a retrospective basis. T he Company adopted this standard effective December 31, 2015. As a result, def erred financing costs of $ 11,435 and $13,424 related to the Company’s secured second lien term loan were reclassified from deferred financing costs to a direct reduction from the debt’s carrying value as of December 31, 2015 and 2014 , respectively . In August 2015, the FASB issued ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). ASU 2015-15 updates the accounting guidance included in ASU 2015-03 a s a result of the June 18, 2015, Emerging Issues Task Force meeting, in which the SEC stated that the SEC staff would not object to an entity deferring and presenting costs related to revolving debt arrangements as a n asset. T he Company adopted this standard effective December 31, 2015. For the y ears ended December 31, 2015 and 2014, deferred financing costs related to the Company’s senior secured revolving credit facility of $3,642 and $4,776 , re spectively, we re presented on the balance sheet as an asset. |
Asset Retirement Obligations | J. Asset Retirement Obligations The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 12 for additional information. |
Derivatives | K. Derivatives Derivative contracts outstanding as of December 31, 2015 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts. |
Income Taxes | L. Income Taxes Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets , if any, for which it is deemed more likely than not that it will not be realized. As of December 31, 2015 the valuation allowance wa s $ 108,843 . See Note 11 for additional information. In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which eliminates the requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet . Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet . The guidance in ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016 , and interim periods within those annual periods. Early application is permitted. The Company does not expect the adoption of this ASU will have a material impact on its financial statements. |
Share-based Compensation | M. Share-Based Compensation The Company grants to directors and employee s stock options a nd restricted stock awards (“RS awards”). The Company also grants restricted stock unit awards (“ RSU awards ”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”). Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years). RS awards, RSU equity awards and Cash-settleable RSU awards. For RS and RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For RSU equity awards with vesting subject to a market condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expe nse is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated fair value recognized over the vesting period (generally three years). |
Statements of Cash Flows Supplemental Information | N. Statements of Cash Flows Supplemental Information During the three year period ended 2015 , the Company paid no federal income taxes. During the years ended December 31, 2015 , 2014 and 2013 , the company made cash interest payments of $28,437 , $7,283 and $13,189 , respectively. |
Investment in Medusa Spar LLC | O. Investment in Medusa Spar LLC During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 3 for additional information on the Medusa divestiture. |
Earnings per Share (EPS) | P. Earnings per Share ( “ EPS ” ) The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in share s. |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Schedule of Revenue by Major Customers | For the Year Ended December 31, 2015 2014 2013 Enterprise Crude Oil, LLC 42% 51% 38% Plains Marketing, L.P. 19% 22% 15% Permian Transport and Trading 15% 7% — Sunoco 9% 10% — Shell Trading Company 4% — 31% Other 11% 10% 16% Total 100% 100% 100% |
Acquisitions and Disposition (T
Acquisitions and Disposition (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Unaudited Summary Pro Forma Financial Information | For the Years Ended December 31, 2014 2013 Revenues $ 180,458 $ 151,766 Income from operations 53,526 36,002 Income available to common stockholders 33,674 4,033 Net income per common share Basic $ 0.57 $ 0.07 Diluted $ 0.56 $ 0.07 |
Central Midland Basin Texas [Member] | 2015 acquisitions [Member] | |
Fair Value of Net Assets Acquired | Oil and natural gas properties $ 24,926 Unevaluated oil and natural gas properties 4,911 Asset retirement obligations (37) Net assets acquired $ 29,800 |
Central Midland Basin Texas [Member] | 2014 acquisitions [Member] | |
Fair Value of Net Assets Acquired | Oil and natural gas properties $ 91,895 Unevaluated oil and natural gas properties 118,450 Asset retirement obligations (140) Net assets acquired $ 210,205 |
Southern Midland Basin Texas [Member] | 2014 acquisitions [Member] | |
Fair Value of Net Assets Acquired | Oil and natural gas properties $ 930 Unevaluated oil and natural gas properties 7,394 Asset retirement obligations (124) Net assets acquired $ 8,200 |
Southern Midland Basin Texas [Member] | 2013 acquisitions [Member] | |
Fair Value of Net Assets Acquired | Oil and natural gas properties $ 9,025 Unevaluated oil and natural gas properties 2,000 Asset retirement obligations (25) Net assets acquired $ 11,000 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earnings Per Share | For the Year Ended December 31, 2015 2014 2013 Net income (loss) $ (240,139) $ 37,766 $ 4,304 Preferred stock dividends (7,895) (7,895) (4,627) Income (loss) available to common stockholders $ (248,034) $ 29,871 $ (323) Weighted average shares outstanding 65,708 44,848 40,133 Dilutive impact of restricted stock — 1,113 — Weighted average shares outstanding for diluted income (loss) per share (a) 65,708 45,961 40,133 Basic income (loss) per share $ (3.77) $ 0.67 $ (0.01) Diluted income (loss) per share $ (3.77) $ 0.65 $ (0.01) The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive: Stock options 15 30 52 Restricted stock 126 317 398 (a) Because the Company reported a loss available to common stockholders for the years ended December 31, 2015 and 2013 , no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. |
Borrowings (Tables)
Borrowings (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Borrowings [Abstract] | |
Schedule of Borrowings | For the Year Ended December 31, 2015 2014 Principal components: Senior secured revolving credit facility $ 40,000 $ 35,000 Secured second lien term loan 300,000 300,000 Total principal outstanding 340,000 335,000 Secured second lien term loan, unamortized deferred financing costs (11,435) (13,424) Total carrying value of borrowings $ 328,565 $ 321,576 |
Derivative Instruments and He27
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 12/31/2015 12/31/2014 12/31/2015 12/31/2014 12/31/2015 12/31/2014 Natural gas Current Fair value of derivatives $ — $ 1,262 $ — $ (7) $ — $ 1,255 Oil Current Fair value of derivatives 19,943 26,588 — (1,242) 19,943 25,346 Total $ 19,943 $ 27,850 $ — $ (1,249) $ 19,943 $ 26,601 As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: For the Year Ended December 31, 2015 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives $ 19,943 $ — $ 19,943 For the Year Ended December 31, 2014 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives $ 27,850 $ — $ 27,850 Current liabilities: Fair value of derivatives (1,249) — (1,249) |
Schedule of Gain or Loss on Derivative Contracts | For the Year Ended December 31, 2015 2014 2013 Natural gas derivatives Net gain (loss) on settlements $ 1,717 $ (84) $ (148) Net gain (loss) on fair value adjustments (1,255) 1,267 230 Total gain (loss) $ 462 $ 1,183 $ 82 Oil derivatives Net gain (loss) on settlements $ 33,299 $ 4,170 $ 1,518 Net gain (loss) on fair value adjustments (5,403) 26,383 (2,960) Total gain (loss) $ 27,896 $ 30,553 $ (1,442) Total gain (loss) on derivative contracts $ 28,358 $ 31,736 $ (1,360) |
Schedule of Outstanding Oil and Natural Gas Derivative Contracts | As of December 31, 2015, the Company had no outstanding natural gas derivative contracts. Listed in the table below are the outstanding oil derivative contracts as of December 31, 2015 : For the Three Months Ended March 31, June 30, September 30, December 31, Oil contracts 2016 2016 2016 2016 Swap contracts (NYMEX) Total volume (MBbls) 182 182 184 184 Weighted average price per Bbl $ 58.23 $ 58.23 $ 58.23 $ 58.23 Swap contracts (Midland basis differentials) Volume (MBbls) 364 364 368 368 Weighted average price per Bbl $ 0.17 $ 0.17 $ 0.17 $ 0.17 Collar contracts combined with short puts (WTI, three-way collar) Total volume (MBbls) 182 182 184 184 Weighted average price per Bbl Ceiling (short call) $ 65.00 $ 65.00 $ 65.00 $ 65.00 Floor (long put) $ 55.00 $ 55.00 $ 55.00 $ 55.00 Short put $ 40.33 $ 40.33 $ 40.33 $ 40.33 The following derivative contracts for oil and natural gas were executed subsequent to December 31, 2015 : For the Three Months Ended March 31, June 30, September 30, December 31, Oil contracts 2016 2016 2016 2016 Collar contracts Total volume (MBbls) 120 182 184 184 Weighted average price per Bbl Ceiling (short call) $ 46.50 $ 46.50 $ 46.50 $ 46.50 Floor (long put) $ 37.50 $ 37.50 $ 37.50 $ 37.50 Natural gas contracts Swap contracts Total volume (BBtu) 360 546 552 552 Weighted average price per MMBtu $ 2.52 $ 2.52 $ 2.52 $ 2.52 For the Three Months Ended March 31, June 30, September 30, December 31, Oil contracts 2017 2017 2017 2017 Call contracts (short) Total volume (MBbls) 165 167 169 169 Weighted average price per Bbl Call strike price $ 50.00 $ 50.00 $ 50.00 $ 50.00 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value of Assets and Liabilities Measured on Recurring Basis | December 31, 2015 Balance Sheet Presentation Level 1 Level 2 Level 3 Total Assets Derivative financial instruments (current) Fair value of derivatives $ — $ 19,943 $ — $ 19,943 Liabilities Derivative financial instruments (current) Fair value of derivatives $ — $ — $ — $ — Total net assets $ — $ 19,943 $ — $ 19,943 December 31, 2014 Balance Sheet Presentation Level 1 Level 2 Level 3 Total Assets Derivative financial instruments (current) Fair value of derivatives $ — $ 27,850 $ — $ 27,850 Liabilities Derivative financial instruments (current) Fair value of derivatives $ — $ (1,249) $ — $ (1,249) Total net assets $ — $ 26,601 $ — $ 26,601 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Share-based Compensation [Abstract] | |
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | For the Year Ended December 31, 2015 2014 2013 Share-based compensation cost for: Equity-based Liability-based Equity-based Liability-based Equity-based Liability-based RSU equity awards $ 3,797 $ — $ 4,223 $ — $ 3,975 $ — Cash-settleable RSU awards — 11,437 — 6,918 — 5,347 401(k) contributions in shares 266 — 270 — 219 — Total share-based compensation cost (a) $ 4,063 $ 11,437 $ 4,493 $ 6,918 $ 4,194 $ 5,347 (a) The portion of this share-based compensation cost that was included in general and administrative expense totaled $9,299 , $ 7,235 and $ 5,751 for the same years, respectively, and the portion capitalized to oil and gas properties was $6,201 , $ 4,176 and $ 3,791 , respectively . |
Schedule of Unrecognized Compensation Cost, Nonvested Awards | December 31, Unrecognized compensation cost related to: 2015 2014 2013 Unvested RSU equity awards $ 5,208 $ 3,979 $ 5,331 Unvested cash-settleable RSU awards 4,728 4,977 7,669 |
Schedule of Cash-Settleable RSU awards | December 31, Consolidated Balance Sheets Classification 2015 2014 Cash-settled restricted stock unit awards (current) $ 10,128 $ 3,856 Cash-settled restricted stock unit awards (non-current) 4,877 7,175 Total cash-settled RSU awards $ 15,005 $ 11,031 |
Schedule of Unvested Restricted Stock Units Activity | Weighted average (shares in 000s) Number of Shares Grant-Date Fair Value per Share Period over which expense is expected to be recognized Outstanding at the beginning of the period 1,868 $ 5.40 Granted (a) 560 8.98 Vested (b) (1,012) 5.36 Forfeited — Outstanding at the end of the period 1,416 $ 6.94 1.5 (a) Includes 126 market-based RSUs that will vest at a range of 0% - 200% . See Note 8 for additional information about market-based RSU equity awards. (b) The fair value of shares vest ed was $5,425 . |
Schedule of Cash-Settleable Vesting Period RSU Awards | (shares in 000s) Base Units Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting Vesting in 2016 332 45 619 Vesting in 2017 231 19 443 Vesting in 2018 25 25 25 Other 167 167 167 Total cash-settleable RSUs 755 256 1,254 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes [Abstract] | |
Schedule of Deferred Tax Assets and Liabilities | As of December 31, 2015 2014 Deferred tax asset Federal net operating loss carryforward $ 107,935 $ 86,629 Statutory depletion carryforward 8,843 8,876 Alternative minimum tax credit carryforward 208 208 Asset retirement obligations 630 1,003 Other 8,241 6,621 Deferred tax asset before valuation allowance 125,857 103,337 Deferred tax liability Oil and natural gas properties 6,488 54,723 Other 10,526 10,140 Total deferred tax liability 17,014 64,863 Net deferred tax asset before valuation allowance 108,843 38,474 Less: Valuation allowance (108,843) — Net deferred tax asset $ — $ 38,474 |
Summary of Operating Loss Carryforwards | Year Expiring Total 2016-2021 2022-2024 2025-2027 2028-2030 2031-2035 Federal NOL carryforwards $ 308,385 $ 13,892 $ 101,495 $ 39,714 $ 32,111 $ 121,173 |
Schedule of Effective Income Tax Rate Reconciliation | For the Year Ended December 31, Components of income tax rate reconciliation 2015 2014 2013 Income tax expense computed at the statutory federal income tax rate 35% 35% 35% Percentage depletion carryforward —% —% (8)% State taxes net of federal benefit 1% 1% 4% Restricted stock and stock options —% —% 5% Section 162(m) (1)% 2% 6% Valuation allowance (54)% —% —% Effective income tax rate (19)% 38% 42% For the Year Ended December 31, Components of income tax expense 2015 2014 2013 Current state income tax expense $ — $ — $ 326 Deferred federal income tax (benefit) expense (69,087) 22,373 2,652 Deferred state income tax (benefit) expense (1,282) 761 126 Valuation allowance 108,843 — — Total income tax expense $ 38,474 $ 23,134 $ 3,104 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligations [Abstract] | |
Schedule of Change in Asset Retirement Obligation | For the Year Ended December 31, 2015 2014 Asset retirement obligations at January 1, 2015 $ 6,674 $ 6,732 Accretion expense 660 826 Liabilities incurred 165 638 Liabilities assumed — 140 Liabilities settled (2,964) (2,130) Revisions to estimate 572 468 Asset retirement obligations at end of period 5,107 6,674 Less: Current asset retirement obligations (790) (4,747) Long-term asset retirement obligations at December 31, 2015 $ 4,317 $ 1,927 |
Supplemental Information on O32
Supplemental Information on Oil and Natural Gas Properties (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Information on Oil and Natural Gas Properties [Abstract] | |
Capitalized Costs Relating to Oil and Natural Gas Activities | The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States. For the Year Ended December 31, 2015 2014 2013 Evaluated Properties Beginning of period balance $ 2,077,985 $ 1,701,577 $ 1,497,010 Capitalized G&A 10,529 10,071 10,014 Property acquisition costs (a) 26,726 94,541 10,885 Exploration costs 81,320 118,251 147,164 Development costs 138,663 153,545 36,504 End of period balance $ 2,335,223 $ 2,077,985 $ 1,701,577 Unevaluated Properties Beginning of period balance $ 142,525 $ 43,222 $ 68,776 Property acquisition costs (a) 5,520 128,342 2,259 Exploration costs 4,576 11,177 10,767 Capitalized interest 10,459 4,295 4,410 Transfers to evaluated (30,899) (44,511) (42,990) End of period balance $ 132,181 $ 142,525 $ 43,222 Accumulated depreciation, depletion and amortization Beginning of period balance $ 1,478,355 $ 1,420,612 $ 1,296,265 Provision charged to expense 69,228 56,663 42,251 Write-down of oil and natural gas properties 208,435 — — Sale of mineral interests — 1,080 82,096 End of period balance $ 1,756,018 $ 1,478,355 $ 1,420,612 For more information on acquisitions refer to Note 3 |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | For the Year Ended December 31, Proved developed and undeveloped reserves: 2015 2014 2013 Oil (MBbls): Beginning of period 25,733 11,898 10,780 Revisions to previous estimates (1,632) (243) (2,540) Purchase of reserves in place 2,932 3,223 150 Sale of reserves in place (23) — (3,294) Extensions and discoveries 19,127 12,547 7,713 Production (2,789) (1,692) (911) End of period 43,348 25,733 11,898 Natural Gas (MMcf): Beginning of period 42,548 17,751 19,753 Revisions to previous estimates 4,870 (215) (5,351) Purchase of reserves in place 2,915 8,591 317 Sale of reserves in place (105) — (4,576) Extensions and discoveries 19,621 18,641 10,619 Production (4,312) (2,220) (3,011) End of period 65,537 42,548 17,751 For the Year Ended December 31, Proved developed reserves: 2015 2014 2013 Oil (MBbls): Beginning of period 14,006 5,960 4,955 End of period 22,257 14,006 5,960 Natural gas (MMcf): Beginning of period 25,171 9,059 10,680 End of period 38,157 25,171 9,059 MBOE: Beginning of period 18,201 7,470 6,735 End of period 28,617 18,201 7,470 Proved undeveloped reserves: Oil (MBbls): Beginning of period 11,727 5,938 5,825 End of period 21,091 11,727 5,938 Natural gas (MMcf): Beginning of period 17,377 8,692 9,073 End of period 27,380 17,377 8,692 MBOE: Beginning of period 14,623 7,387 7,337 End of period 25,654 14,623 7,387 |
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure | 2015 2014 2013 Average 12-month price, net of differentials, per Mcf of natural gas $ 2.73 $ 6.38 $ 5.45 Average 12-month price, net of differentials, per barrel of oil $ 47.25 $ 86.30 $ 92.16 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | Standardized Measure For the Year Ended December 31, 2015 2014 2013 Future cash inflows $ 2,227,463 $ 2,492,178 $ 1,193,299 Future costs Production (827,555) (873,469) (357,005) Development and net abandonment (239,100) (288,081) (155,667) Future net inflows before income taxes 1,160,808 1,330,628 680,627 Future income taxes — (164,490) (68,239) Future net cash flows 1,160,808 1,166,138 612,388 10% discount factor (589,918) (586,596) (328,442) Standardized measure of discounted future net cash flows $ 570,890 $ 579,542 $ 283,946 Changes in Standardized Measure For the Year Ended December 31, 2015 2014 2013 Standardized measure at the beginning of the period $ 579,542 $ 283,946 $ 231,148 Sales and transfers, net of production costs (110,476) (120,518) (78,661) Net change in sales and transfer prices, net of production costs (286,660) (156,066) (46,088) Net change due to purchases and sales of in place reserves 37,616 111,331 (145,711) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 184,469 299,192 212,431 Changes in future development cost 108,216 186,605 153,983 Revisions of quantity estimates (12,625) (7,673) (68,958) Accretion of discount 62,968 30,114 25,010 Net change in income taxes 35,407 (32,940) 1,751 Changes in production rates, timing and other (27,567) (14,449) (959) Aggregate change (8,652) 295,596 52,798 Standardized measure at the end of period $ 570,890 $ 579,542 $ 283,946 |
Summarized Quarterly Financia33
Summarized Quarterly Financial Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summarized Quarterly Financial Information [Abstract] | |
Schedule of Quarterly Financial Information | 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenues $ 30,391 $ 39,242 $ 34,316 $ 33,563 Income (loss) from operations (a) (12,889) 6,231 (83,910) (118,542) Net loss (a) (10,197) (4,967) (111,805) (113,170) Loss available to common shares (12,171) (6,940) (113,779) (115,144) Loss per common share - basic $ (0.21) $ (0.11) $ (1.72) $ (1.58) Loss per common share - diluted $ (0.21) $ (0.11) $ (1.72) $ (1.58) (a) Loss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and gas properties of $ 87,301 and $121,134 , r espectively. 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenues $ 33,285 $ 40,502 $ 39,657 $ 38,418 Income from operations 6,645 12,080 11,562 7,983 Net income (loss) 1,863 4,740 12,201 18,962 Income (loss) available to common shares (111) 2,767 10,227 16,988 Income (loss) per common share - basic $ 0.00 $ 0.07 $ 0.24 $ 0.31 Income (loss) per common share - diluted $ 0.00 $ 0.07 $ 0.23 $ 0.30 |
Summary of Significant Accoun34
Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015 | Sep. 30, 2015 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accounting Policies [Line Items] | ||||||
Write-down of oil and natural gas properties | $ 121,134 | $ 87,301 | $ 208,435 | |||
Capitalized interest | 10,459 | $ 4,295 | $ 4,410 | |||
Amortization of financing costs | 3,123 | 1,272 | 471 | |||
Deferred financing costs, net of accumulated amortization | 11,435 | 11,435 | 13,424 | |||
Deferred financing costs | 3,642 | 3,642 | 4,776 | |||
Deferred tax assets, valuation allowance | 108,843 | 108,843 | ||||
Interest paid | 28,437 | 7,283 | 13,189 | |||
Other Property and Equipment [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Depreciation | 865 | 836 | $ 750 | |||
Accumulated depreciation | $ 14,719 | $ 14,719 | $ 14,005 | |||
Other Property and Equipment [Member] | Minimum [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Useful life | 3 years | |||||
Other Property and Equipment [Member] | Maximum [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Useful life | 20 years | |||||
Medusa Spar, LLC [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Divestiture of business, percentage of business sold | 10.00% | |||||
Ownership percentage of production facilities | 75.00% | 75.00% | ||||
Medusa Field [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Divestiture of business, percentage of business sold | 15.00% | |||||
Stock options [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Vesting period | 3 years | |||||
RSU RSU equity awards [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Vesting period | 3 years | |||||
Cash-settleable RSU awards [Member] | ||||||
Accounting Policies [Line Items] | ||||||
Vesting period | 3 years |
Summary of Significant Accoun35
Summary of Significant Accounting Policies (Major Customers) (Details) - Sales Revenue, Goods, Net [Member] - Customer Concentration Risk [Member] | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 100.00% | 100.00% | 100.00% |
Enterprise Crude Oil, LLC [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 42.00% | 51.00% | 38.00% |
Plains Marketing, L.P. [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 19.00% | 22.00% | 15.00% |
Permian Transport And Trading [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 15.00% | 7.00% | |
Sunoco [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 9.00% | 10.00% | |
Shell Trading Company [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 4.00% | 31.00% | |
Other [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 11.00% | 10.00% | 16.00% |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Narrative) (Details) $ in Thousands | Nov. 09, 2015USD ($)a | Oct. 08, 2014USD ($) | Jan. 31, 2016USD ($) | Mar. 31, 2014USD ($)a | Dec. 31, 2013USD ($) | Jun. 30, 2013USD ($)aitembbl |
Central Midland Basin Texas [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Gas and oil area, developed and undeveloped, net | a | 628 | |||||
Aggregate cash purchase price | $ 29,800 | $ 210,205 | ||||
Working interest | 62.00% | |||||
Net revenue interest | 46.50% | |||||
Net proceeds from an equity offering | $ 122,514 | |||||
Southern Midland Basin Texas [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Gas and oil area, developed and undeveloped, net | a | 1,527 | 2,186 | ||||
Gas and oil area, developed and undeveloped, gross | a | 2,468 | |||||
Aggregate cash purchase price | $ 8,200 | $ 11,000 | ||||
Working interest | 100.00% | |||||
Net revenue interest | 78.00% | |||||
Productive oil wells, number of wells, gross | item | 7 | |||||
Proved developed reserves | bbl | 1,301 | |||||
Medusa Fields, Medusa Spar LLC, And Gulf Of Mexico Shelf Properties [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Divestiture of business, sales price | $ 88,000 | |||||
Swan Lake Field [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Divestiture of business, percentage of business sold | 69.00% | |||||
Divestiture of business, sales price | $ 2,000 | |||||
Medusa Spar, LLC [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Divestiture of business, percentage of business sold | 10.00% | |||||
Medusa Field [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Divestiture of business, percentage of business sold | 15.00% | |||||
Carpe Diem Field [Member] | Central Midland Basin Texas [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Working interest | 100.00% | |||||
Net revenue interest | 79.00% | |||||
CaBo Fields [Member] | Subsequent Event [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Working interest | 71.30% | |||||
Net revenue interest | 53.50% | |||||
CaBo Fields [Member] | Central Midland Basin Texas [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Working interest | 67.00% | |||||
Net revenue interest | 50.00% | |||||
CaBo Fields [Member] | Central Midland Basin Texas [Member] | Subsequent Event [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | $ 9,300 | |||||
Working interest | 4.90% | |||||
Net revenue interest | 3.70% |
Acquisitions and Dispositions37
Acquisitions and Dispositions (Schedule of Acquisition Fair Value of Net Assets ) (Details) - USD ($) $ in Thousands | Nov. 09, 2015 | Oct. 08, 2014 | Mar. 31, 2014 | Jun. 30, 2013 |
Central Midland Basin Texas [Member] | ||||
Business Acquisition [Line Items] | ||||
Asset retirement obligations | $ (37) | $ (140) | ||
Net assets acquired | 29,800 | 210,205 | ||
Central Midland Basin Texas [Member] | Oil and Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | 24,926 | 91,895 | ||
Central Midland Basin Texas [Member] | Unevaluated Oil and Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | $ 4,911 | $ 118,450 | ||
Southern Midland Basin Texas [Member] | ||||
Business Acquisition [Line Items] | ||||
Asset retirement obligations | $ (124) | $ (25) | ||
Net assets acquired | 8,200 | 11,000 | ||
Southern Midland Basin Texas [Member] | Oil and Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | 930 | 9,025 | ||
Southern Midland Basin Texas [Member] | Unevaluated Oil and Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | $ 7,394 | $ 2,000 |
Acquisitions and Dispositions38
Acquisitions and Dispositions (Unaudited Pro Forma Financial Information) (Details) - Central Midland Basin Texas [Member] - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | ||
Revenues | $ 180,458 | $ 151,766 |
Income from operations | 53,526 | 36,002 |
Income available to common stockholders | $ 33,674 | $ 4,033 |
Basic | $ 0.57 | $ 0.07 |
Diluted | $ 0.56 | $ 0.07 |
Earnings Per Share (Computation
Earnings Per Share (Computation of Basic and Diluted Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||||
Earnings Per Share, Basic and Diluted | ||||||||||||||||
Net income (loss) | $ (113,170) | [1] | $ (111,805) | [1] | $ (4,967) | [1] | $ (10,197) | [1] | $ 18,962 | $ 12,201 | $ 4,740 | $ 1,863 | $ (240,139) | $ 37,766 | $ 4,304 | |
Preferred stock dividends | (7,895) | (7,895) | (4,627) | |||||||||||||
Income (loss) available to common stockholders | $ (115,144) | $ (113,779) | $ (6,940) | $ (12,171) | $ 16,988 | $ 10,227 | $ 2,767 | $ (111) | $ (248,034) | $ 29,871 | $ (323) | |||||
Weighted average shares outstanding | 65,708 | 44,848 | 40,133 | |||||||||||||
Weighted average shares outstanding for diluted income (loss) per share | [2] | 65,708 | 45,961 | 40,133 | ||||||||||||
Basic income (loss) per share | $ (1.58) | $ (1.72) | $ (0.11) | $ (0.21) | $ 0.31 | $ 0.24 | $ 0.07 | $ 0 | $ (3.77) | $ 0.67 | $ (0.01) | |||||
Diluted income (loss) per share | $ (1.58) | $ (1.72) | $ (0.11) | $ (0.21) | $ 0.30 | $ 0.23 | $ 0.07 | $ 0 | $ (3.77) | $ 0.65 | $ (0.01) | |||||
Stock options [Member] | ||||||||||||||||
Earnings Per Share, Basic and Diluted | ||||||||||||||||
Excluded from the diluted EPS calculation because their effect would be anti-dilutive | 15 | 30 | 52 | |||||||||||||
Restricted Stock [Member] | ||||||||||||||||
Earnings Per Share, Basic and Diluted | ||||||||||||||||
Dilutive impact | 1,113 | |||||||||||||||
Excluded from the diluted EPS calculation because their effect would be anti-dilutive | 126 | 317 | 398 | |||||||||||||
[1] | Loss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and gas properties of $87,301 and $121,134, respectively. | |||||||||||||||
[2] | Because the Company reported a loss available to common stockholders for the years ended December 31, 2015 and 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. |
Borrowings (Senior secured revo
Borrowings (Senior secured revolving credit facility ) (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Mar. 11, 2014 | |
Line of Credit Facility [Line Items] | |||
Senior secured revolving credit facility | $ 40,000 | $ 35,000 | |
Senior Secured Revolving Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 500,000 | ||
Current borrowing capacity | 300,000 | ||
Senior secured revolving credit facility | $ 40,000 | ||
Interest rate at period end (as a percent) | 2.07% | ||
Unused capacity, commitment fee (as a percent) | 0.50% | ||
Remaining borrowing capacity | $ 260,000 | ||
Debt instrument maturity date | Mar. 11, 2019 | ||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | LIBOR [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt instrument interest rate | 1.75% | ||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | LIBOR [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt instrument interest rate | 2.75% |
Borrowings (Term Loans) (Narrat
Borrowings (Term Loans) (Narrative) (Details) - USD ($) $ in Thousands | Oct. 08, 2014 | Apr. 10, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Line of Credit Facility [Line Items] | |||||
Debt instrument outstanding | $ 340,000 | $ 335,000 | |||
Gain (loss) on early extinguishment of debt | $ (3,054) | 151 | $ 3,696 | ||
Secured second lien term loan [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt, total availability | 125,000 | ||||
Debt instrument outstanding | 300,000 | $ 300,000 | |||
Debt, initial commitment | $ 100,000 | ||||
Debt instrument, description | The Company can elect a LIBOR rate based on various tenors, and is currently incurring interest based on an underlying three-month LIBOR rate, which was last elected in January 2016. | ||||
Debt, additional availability | $ 25,000 | ||||
Proceeds from issuance of debt | $ 300,000 | $ 62,500 | |||
Debt, discount percentage | 2.00% | 1.00% | |||
Debt instrument, interest rate, effective | 8.50% | 8.50% | |||
Debt instrument interest rate | 7.50% | 7.50% | |||
Secured second lien term loan [Member] | Prior to First Anniversary [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Prepayment premium | 102.00% | 102.00% | |||
Secured second lien term loan [Member] | After First Anniversary but Prior to Second Anniversary [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Prepayment premium | 101.00% | 101.00% | |||
Secured second lien term loan [Member] | After Second Anniversary [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Prepayment premium | 100.00% | 100.00% | |||
Secured second lien term loan [Member] | Interest Rate Floor [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument interest rate | 1.00% | 1.00% |
Borrowings (13% Senior Notes du
Borrowings (13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit) (Details) - USD ($) $ in Thousands | Oct. 08, 2014 | Apr. 11, 2014 | Dec. 17, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||||||
Gain on extinguishment of debt | $ (3,054) | $ 151 | $ 3,696 | |||
Amortization of deferred credit | (487) | (3,164) | ||||
Repayment of senior notes including redemption expenses | 50,057 | $ 50,060 | ||||
Long-term Debt | $ 321,576 | $ 328,565 | ||||
13% Senior Notes due 2016 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Repayments of senior debt | $ 48,481 | $ 48,481 | ||||
Gain on extinguishment of debt | 3,205 | 3,696 | ||||
Extinguishment of debt amount | 50,057 | |||||
Redemption expenses | 1,576 | 1,576 | ||||
Deferred credit | (4,780) | (5,275) | ||||
Amortization of deferred credit | 4,780 | |||||
Payment for accrued interest on redemption of debt | 193 | |||||
Repayment of senior notes including redemption expenses | 50,057 | |||||
Long-term Debt | $ 53,261 | $ 53,756 |
Borrowings (Schedule of Borrowi
Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Principal components: | ||
Total principal outstanding | $ 340,000 | $ 335,000 |
Secured second lien term loan, unamortized deferred financing costs | (11,435) | (13,424) |
Total carrying value of borrowings | 328,565 | 321,576 |
Senior Secured Revolving Credit Facility [Member] | ||
Principal components: | ||
Total principal outstanding | 40,000 | 35,000 |
Secured second lien term loan [Member] | ||
Principal components: | ||
Total principal outstanding | $ 300,000 | $ 300,000 |
Derivative Instruments and He44
Derivative Instruments and Hedging Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | $ 19,943 | $ 26,601 |
Current assets - Fair market value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 19,943 | 26,588 |
Current assets - Fair market value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 1,262 | |
Current liabilities - Fair value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (1,242) | |
Current liabilities - Fair value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (7) | |
Balance Sheet Current [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 19,943 | 27,850 |
Liability Fair Value | (1,249) | |
Net Derivative Fair Value | 19,943 | 26,601 |
Balance Sheet Current [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | $ 19,943 | 25,346 |
Balance Sheet Current [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | $ 1,255 |
Derivative Instruments and He45
Derivative Instruments and Hedging Activities (Derivative Netting Adjustments) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: Fair value of hedging contracts [Member] | ||
Offsetting Assets and Liabilities [Line Items] | ||
Derivative asset, fair value, gross asset | $ 19,943 | $ 27,850 |
Derivative Assets | $ 19,943 | 27,850 |
Current liabilities: Fair value of hedging contracts [Member] | ||
Offsetting Assets and Liabilities [Line Items] | ||
Derivative liability, fair value, gross liability | 1,249 | |
Derivative Liabilities | $ 1,249 |
Derivative Instruments and He46
Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Net gain (loss) on fair value adjustments | $ (6,658) | $ 27,650 | $ (2,730) |
Total gain (loss) on derivative contracts | 28,358 | 31,736 | (1,360) |
Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gain (loss) on derivative contracts | 28,358 | 31,736 | (1,360) |
Crude Oil [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Net gain (loss) on settlements | 33,299 | 4,170 | 1,518 |
Net gain (loss) on fair value adjustments | (5,403) | 26,383 | (2,960) |
Total gain (loss) on derivative contracts | 27,896 | 30,553 | (1,442) |
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Net gain (loss) on settlements | 1,717 | (84) | (148) |
Net gain (loss) on fair value adjustments | (1,255) | 1,267 | 230 |
Total gain (loss) on derivative contracts | $ 462 | $ 1,183 | $ 82 |
Derivative Instruments and He47
Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Not Designated as Hedging Instrument [Member] | 2 Months Ended | 12 Months Ended |
Feb. 29, 2016MMBTU$ / MMBTU$ / bblMBbls | Dec. 31, 2015$ / bblMBbls | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 182 | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 120 | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 65 | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 46.50 | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 55 | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 37.50 | |
Collar Contracts Combined With Short Puts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 40.33 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 182 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 182 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 65 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 46.50 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 55 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 37.50 | |
Collar Contracts Combined With Short Puts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 40.33 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 65 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 46.50 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 55 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 37.50 | |
Collar Contracts Combined With Short Puts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 40.33 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 65 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 46.50 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 55 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 37.50 | |
Collar Contracts Combined With Short Puts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 40.33 | |
Swap Contracts Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 182 | |
Average swap price | 58.23 | |
Swap Contracts Three Months Ended March 31, 2016 [Member] | Natural Gas [Member] | Swap [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MMBTU | 360 | |
Average swap price | $ / MMBTU | 2.52 | |
Swap Contracts Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 182 | |
Average swap price | 58.23 | |
Swap Contracts Three Months Ended June 30, 2016 [Member] | Natural Gas [Member] | Swap [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MMBTU | 546 | |
Average swap price | $ / MMBTU | 2.52 | |
Swap Contracts Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Average swap price | 58.23 | |
Swap Contracts Three Months Ended September 30, 2016 [Member] | Natural Gas [Member] | Swap [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MMBTU | 552 | |
Average swap price | $ / MMBTU | 2.52 | |
Swap Contracts Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Average swap price | 58.23 | |
Swap Contracts Three Months Ended December 31, 2016 [Member] | Natural Gas [Member] | Swap [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MMBTU | 552 | |
Average swap price | $ / MMBTU | 2.52 | |
Swap Contracts Differentials Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 364 | |
Swap Contracts Differentials Three Months Ended March 31, 2016 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Average swap price | 0.17 | |
Swap Contracts Differentials Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 364 | |
Swap Contracts Differentials Three Months Ended June 30, 2016 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Average swap price | 0.17 | |
Swap Contracts Differentials Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 368 | |
Swap Contracts Differentials Three Months Ended September 30, 2016 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Average swap price | 0.17 | |
Swap Contracts Differentials Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 368 | |
Swap Contracts Differentials Three Months Ended December 31, 2016 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Average swap price | 0.17 | |
Short Call Contracts Three Months March 31, 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 165 | |
Strike price | 50 | |
Short Call Contracts Three Months June 30, 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 167 | |
Strike price | 50 | |
Short Call Contracts Three Months September 30, 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 169 | |
Strike price | 50 | |
Short Short Call Contracts Three Months December 31, 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 169 | |
Strike price | 50 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Assets | ||
Derivative Assets, Current | $ 19,943 | $ 27,850 |
Derivative Liabilities | ||
Derivative Liabilities, Current | (1,249) | |
Fair Value, Net Asset | 19,943 | 26,601 |
Level 2 [Member] | ||
Derivative Liabilities | ||
Fair Value, Net Asset | 19,943 | 26,601 |
Current assets - Fair market value of derivatives [Member] | ||
Derivative Assets | ||
Derivative Assets, Current | 19,943 | 27,850 |
Current assets - Fair market value of derivatives [Member] | Level 2 [Member] | ||
Derivative Assets | ||
Derivative Assets, Current | $ 19,943 | 27,850 |
Current liabilities - Fair value of derivatives [Member] | ||
Derivative Liabilities | ||
Derivative Liabilities, Current | (1,249) | |
Current liabilities - Fair value of derivatives [Member] | Level 2 [Member] | ||
Derivative Liabilities | ||
Derivative Liabilities, Current | $ (1,249) |
Employee Benefit Plans (Narrati
Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands | May. 12, 2011 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | May. 14, 2015 | Dec. 31, 2011 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Defined contribution plan, employer contribution amount | $ 999 | $ 1,017 | $ 923 | |||
Market-based RSUs [Member] | Vesting Minimum [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Share-based compensation arrangement vesting rights, percentage | 0.00% | |||||
Market-based RSUs [Member] | Vesting Maximum [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Share-based compensation arrangement vesting rights, percentage | 200.00% | |||||
Cash-settleable RSU awards [Member] | Vesting Minimum [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Share-based compensation arrangement vesting rights, percentage | 0.00% | |||||
Cash-settleable RSU awards [Member] | Vesting Maximum [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Share-based compensation arrangement vesting rights, percentage | 200.00% | |||||
2011 Plan [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Number of shares authorized | 2,300,000 | 4,300,000 | 5,141,000 | 3,141,000 | ||
Increase in number of shares authorized and reserved for issuance | 841,000 | 2,000,000 | ||||
Number of shares available for grant | 2,926,545 |
Share-Based Compensation (Narra
Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Cash-settled restricted stock unit awards | $ 10,128 | $ 3,856 | |
Payments to settle vested liability share-based awards | $ 3,925 | $ 2,052 | $ 239 |
Stock options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of years company issued no stock options | 3 years | ||
Issued, shares | 0 | ||
Vested, shares | 0 | ||
Forfeited, shares | 0 | ||
Exercised, shares | 0 | ||
Expired, shares | 15,000 | ||
Outstanding, shares | 15,000 | 30,000 | 52,000 |
Exercisable, shares | 15,000 | 30,000 | 52,000 |
Outstanding, end of year, weighted average exercise price per option | $ 14.37 | $ 14.04 | $ 13.75 |
Share-based payment award outstanding aggregate intrinsic value | $ 0 | $ 0 | $ 0 |
Outstanding options weighted-average remaining contract life per unit | 1 year 3 months 18 days | 1 year 3 months 18 days | 2 years 8 months 12 days |
RSU RSU equity awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average period over which expense is expected to be recognized | 1 year 6 months | ||
Vested in period | 1,012,000 | ||
Cash-settleable RSU awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average period over which expense is expected to be recognized | 1 year 9 months 18 days | ||
Unvested RSUs [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average period over which expense is expected to be recognized | 1 year 9 months 18 days | ||
Non-Market Based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payments to settle vested liability share-based awards | $ 545 | $ 559 | |
Vested in period | 72,108 | 58,000 | |
Market-based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payments to settle vested liability share-based awards | $ 1,241 | ||
Vested in period | 853,673 | 523,000 | |
2011 Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares available for grant | 2,926,545 | ||
Vesting in 2014 [Member] | Market-based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payments to settle vested liability share-based awards | $ 3,599 | ||
Vesting in 2015 [Member] | Market-based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payments to settle vested liability share-based awards | 3,319 | ||
Vesting in 2016 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Cash-settled restricted stock unit awards | $ 9,807 | ||
Vesting Minimum [Member] | Cash-settleable RSU awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement vesting rights, percentage | 0.00% | ||
Vesting Minimum [Member] | Non-Market Based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement vesting rights, percentage | 150.00% | ||
Vesting Minimum [Member] | Market-based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement vesting rights, percentage | 150.00% | ||
Vesting Maximum [Member] | Cash-settleable RSU awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement vesting rights, percentage | 200.00% | ||
Vesting Maximum [Member] | Non-Market Based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement vesting rights, percentage | 200.00% | ||
Vesting Maximum [Member] | Market-based Cash-settleable RSU Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement vesting rights, percentage | 200.00% |
Share-Based Compensation (Share
Share-Based Compensation (Share-Based Compensation Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense - Equity-based | $ 4,063 | $ 4,493 | $ 4,194 |
Share-based compensation expense - Liability-based | 11,437 | 6,918 | 5,347 |
Share-based compensation - capitalized oil and gas properties | 6,201 | 4,176 | 3,791 |
RSU RSU equity awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense - Equity-based | 3,797 | 4,223 | 3,975 |
Cash-settleable RSU awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense - Liability-based | 11,437 | 6,918 | 5,347 |
401(k) contributions in shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense - Equity-based | 266 | 270 | 219 |
General and Administrative Expense [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
share-based compensation | $ 9,299 | $ 7,235 | $ 5,751 |
Share-Based Compensation (Unrec
Share-Based Compensation (Unrecognized Compensation Expense Expected to be Recognized in Future Periods) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
RSU RSU equity awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Nonvested awards, total compensation cost not yet recognized, share-based awards other than options | $ 5,208 | $ 3,979 | $ 5,331 |
Cash-settleable RSU awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Nonvested awards, total compensation cost not yet recognized, share-based awards other than options | $ 4,728 | $ 4,977 | $ 7,669 |
Share-Based Compensation (Cash-
Share-Based Compensation (Cash-Settleable RSU Awards) (Details) - Cash-settleable RSU awards [Member] - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Cash-Settleable Compensation Arrangement by Cash-based Arrangements Award, Liability, Current and Noncurrent | $ 15,005 | $ 11,031 |
Current Liabilities [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Cash-Settleable Compensation Arrangement by Cash-based Arrangements Award, Liability, Current | 10,128 | 3,856 |
Non-current liabilities [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Cash-Settleable Compensation Arrangement by Cash-based Arrangements Award, Liability, Noncurrent | $ 4,877 | $ 7,175 |
Share-Based Compensation (Sched
Share-Based Compensation (Schedule of Unvested Restricted Stock Units Activity) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Fair value of shares vested | $ 5,425 | ||
RSU RSU equity awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |||
Outstanding at the beginning of the period | 1,868 | ||
Granted | 560 | 333 | 944 |
Vested | (1,012) | ||
Outstanding at the end of the period | 1,416 | 1,868 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Outstanding at the beginning of the period, Grant Date Fair Value per Share | $ 5.40 | ||
Granted, grant date fair value per share | 8.98 | $ 9.67 | $ 3.82 |
Vested, grant date fair value per share | 5.36 | ||
Outstanding at the end of the period, grant date fair value per share | $ 6.94 | $ 5.40 | |
Weighted average period over which expense is expected to be recognized | 1 year 6 months | ||
Fair value of shares vested | $ 4,338 | $ 2,689 | |
Market-based RSUs [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |||
Granted | 126 |
Share-Based Compensation (Sch55
Share-Based Compensation (Schedule of Cash-Settleable Vesting Period RSU Awards) (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2015shares | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs base units outstanding | 755 |
Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 256 |
Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 1,254 |
Vesting in 2016 [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs base units outstanding | 332 |
Vesting in 2016 [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 45 |
Vesting in 2016 [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 619 |
Vesting in 2017 [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs base units outstanding | 231 |
Vesting in 2017 [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 19 |
Vesting in 2017 [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 443 |
Vesting in 2018 [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs base units outstanding | 25 |
Vesting in 2018 [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 25 |
Vesting in 2018 [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 25 |
Other [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs base units outstanding | 167 |
Other [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 167 |
Other [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Cash-settleable RSUs potential units vesting | 167 |
Equity Transactions (Narrative)
Equity Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | Nov. 16, 2015 | Mar. 13, 2015 | Sep. 15, 2014 | Feb. 29, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Class of Stock [Line Items] | |||||||
Preferred stock dividend | $ 7,895 | $ 7,895 | $ 4,627 | ||||
Stock issued during period (in shares) | 12,000,000 | 9,000,000 | 12,500,000 | ||||
Shares price issued | $ 8.40 | $ 6.55 | $ 9 | ||||
Net proceeds from issuance of common stock public offering | $ 109,913 | $ 65,644 | $ 122,514 | ||||
Over-Allotment Option [Member] | |||||||
Class of Stock [Line Items] | |||||||
Stock issued during period (in shares) | 1,800,000 | 1,350,000 | 1,875,000 | ||||
Series A Preferred Stock [Member] | |||||||
Class of Stock [Line Items] | |||||||
Preferred Stock, Dividend Rate, Percentage | 10.00% | ||||||
Preferred stock, liquidation preference (in dollars per share) | $ 50 | $ 50 | |||||
Preferred Stock, Dividend Rate, Per-Dollar-Amount, Per Annum | $ 5 | ||||||
Preferred stock dividend | $ 7,895 | $ 7,895 | $ 4,627 | ||||
Series A Preferred Stock [Member] | Subsequent Event [Member] | |||||||
Class of Stock [Line Items] | |||||||
Conversion of Stock, Shares Converted | 120,000 | ||||||
Common Stock | |||||||
Class of Stock [Line Items] | |||||||
Value of a share of common stock | $ 8.34 | ||||||
Common stock shares to be issued for each share of preferred stock upon conversion | 6 | ||||||
Common Stock | Subsequent Event [Member] | |||||||
Class of Stock [Line Items] | |||||||
Conversion of Stock, Shares Issued | 719,000 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Taxes [Abstract] | |||
Statutory income tax rate, percent | 35.00% | 35.00% | 35.00% |
Deferred tax assets, valuation allowance | $ 108,843 |
Income Taxes (Deferred Tax Asse
Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax asset | ||
Federal net operating loss carryforward | $ 107,935 | $ 86,629 |
Statutory depletion carryforward | 8,843 | 8,876 |
Alternative minimum tax credit carryforward | 208 | 208 |
Asset retirement obligations | 630 | 1,003 |
Other | 8,241 | 6,621 |
Deferred tax asset before valuation allowance | 125,857 | 103,337 |
Deferred tax liability | ||
Oil and natural gas properties | 6,488 | 54,723 |
Other | 10,526 | 10,140 |
Total deferred tax liability | 17,014 | 64,863 |
Net deferred tax asset before valuation allowance | 108,843 | 38,474 |
Less: Valuation allowance | $ (108,843) | |
Total deferred tax asset | $ 38,474 |
Income Taxes (Federal Operating
Income Taxes (Federal Operating Loss Carryforwards) (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Operating Loss Carryforwards [Line Items] | |
Federal NOL carryforwards | $ 308,385 |
2016-2021 [Member] | |
Operating Loss Carryforwards [Line Items] | |
Federal NOL carryforwards | 13,892 |
2022-2024 [Member] | |
Operating Loss Carryforwards [Line Items] | |
Federal NOL carryforwards | 101,495 |
2025-2027 [Member] | |
Operating Loss Carryforwards [Line Items] | |
Federal NOL carryforwards | 39,714 |
2028-2030 [Member] | |
Operating Loss Carryforwards [Line Items] | |
Federal NOL carryforwards | 32,111 |
2031-2035 [Member] | |
Operating Loss Carryforwards [Line Items] | |
Federal NOL carryforwards | $ 121,173 |
Income Taxes (Income Tax Reconc
Income Taxes (Income Tax Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Components of income tax rate reconciliation | |||
Income tax expense computed at the statutory federal income tax rate | 35.00% | 35.00% | 35.00% |
Percentage depletion carryforward | (8.00%) | ||
State taxes net of federal benefit | 1.00% | 1.00% | 4.00% |
Restricted stock and stock options | 5.00% | ||
Section 162(m) | (1.00%) | 2.00% | 6.00% |
Valuation allowance | (54.00%) | ||
Effective income tax rate | (19.00%) | 38.00% | 42.00% |
Components of income tax expense | |||
Current state income tax expense | $ 326 | ||
Deferred federal income tax (benefit) expense | $ (69,087) | $ 22,373 | 2,652 |
Deferred state income tax (benefit) expense | (1,282) | 761 | 126 |
Valuation allowance | 108,843 | ||
Total income tax expense | $ 38,474 | $ 23,134 | $ 3,104 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Change in Asset Retirement Obligation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Asset retirement obligations at beginning of period | $ 6,674 | $ 6,732 | |||
Accretion expense | 660 | 826 | $ 1,785 | ||
Liabilities incurred | 165 | 638 | |||
Liabilities assumed | 140 | ||||
Liabilities settled | (2,964) | (2,130) | |||
Revisions to estimate | 572 | 468 | |||
Asset retirement obligations at end of period | $ 6,674 | $ 6,732 | $ 6,732 | $ 5,107 | $ 6,674 |
Less: current asset retirement obligations | (790) | (4,747) | |||
Long-term asset retirement obligations at the end of the period | 4,317 | 1,927 | |||
Restricted Investments | |||||
Restricted investments | $ 3,309 | $ 3,810 |
Supplemental Information on O62
Supplemental Information on Oil and Natural Gas Properties (unaudited) (Proved Undeveloped Reserves) (Narrative) (Details) $ in Thousands | 2 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Feb. 26, 2016item | Dec. 31, 2015USD ($)MBoe | Sep. 30, 2015USD ($) | Dec. 31, 2015USD ($)itemMBoe | Dec. 31, 2014USD ($)itemMBoe | Dec. 31, 2013MBoe | Dec. 31, 2012MBoe | |
Reserve Quantities [Line Items] | |||||||
Write-down of oil and natural gas properties | $ | $ 121,134 | $ 87,301 | $ 208,435 | ||||
Proved Developed and Undeveloped Reserve, Net (Energy) | 54,271 | 54,271 | 32,824 | 14,857 | 14,072 | ||
Proved Developed and Proved Undeveloped Reserves, Percentage Change Between Periods | 65.00% | 121.00% | 6.00% | ||||
Proved undeveloped reserves, percentage change between periods | 75.00% | 98.00% | 1.00% | ||||
Proved undeveloped reserves | 25,654 | 25,654 | 14,623 | 7,387 | 7,337 | ||
Proved undeveloped reserves extensions discoveries and additions | 13,774 | 10,125 | 5,168 | ||||
Proved undeveloped reserves reclassification to proved developed production | (2,742) | ||||||
Proved undeveloped reserves conversion to proved developed reserves, percentage transferred | 19.00% | 24.00% | 51.00% | ||||
Proved undeveloped reserves conversion to proved developed reserves total cost | $ | $ 55,933 | $ 34,619 | |||||
Reclassification of proved undeveloped production reserves to horizontal probable | 1,757 | 3,724 | |||||
Proved undeveloped reserves sales of minerals in place | 1,132 | 1,297 | |||||
Proved Undeveloped Reserves Sales Of Minerals In Place, Percentage | 18.00% | ||||||
Permian Basin [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Number of wells drilled during the period | item | 36 | 34 | |||||
Number of wells drilled during the period, net | item | 27.1 | 28.7 | |||||
Subsequent Event [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Number of horizontal wells drilled | item | 5 | ||||||
Number of completed horizontal wells | item | 2 | ||||||
Number of horizontal wells in progress | item | 5 |
Supplemental Information on O63
Supplemental Information on Oil and Natural Gas Properties (unaudited) (Capitalized Costs Relating to Oil and Natural Gas Activities) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2015USD ($)$ / Boe | Dec. 31, 2014USD ($)$ / Boe | Dec. 31, 2013USD ($)$ / Boe | |
Evaluated Properties | |||||
Beginning of period balance | $ 2,077,985 | $ 1,701,577 | $ 1,497,010 | ||
Capitalized G&A | 10,529 | 10,071 | 10,014 | ||
Property acquisition costs | 26,726 | 94,541 | 10,885 | ||
Exploration costs | 81,320 | 118,251 | 147,164 | ||
Development costs | 138,663 | 153,545 | 36,504 | ||
End of period balance | $ 2,335,223 | 2,335,223 | 2,077,985 | 1,701,577 | |
Unevaluated Properties | |||||
Beginning of period balance | 142,525 | 43,222 | 68,776 | ||
Property acquisition costs | 5,520 | 128,342 | 2,259 | ||
Exploration costs | 4,576 | 11,177 | 10,767 | ||
Capitalized interest | 10,459 | 4,295 | 4,410 | ||
Transfers to evaluated | (30,899) | (44,511) | (42,990) | ||
End of period balance | 132,181 | 132,181 | 142,525 | 43,222 | |
Accumulated depreciation, depletion and amortization: | |||||
Beginning of period balance | 1,478,355 | 1,420,612 | 1,296,265 | ||
Provision charged to expense | 69,228 | 56,663 | 42,251 | ||
Write-down of oil and natural gas properties | 121,134 | $ 87,301 | 208,435 | ||
Sale of mineral interests | 1,080 | 82,096 | |||
End of period balance | $ 1,756,018 | $ 1,756,018 | $ 1,478,355 | $ 1,420,612 | |
Depletion expense per physical unit of production | $ / Boe | 19.74 | 27.51 | 31.12 | ||
Lease expense per physical unit of production | $ / Boe | 7.71 | 10.85 | 14 | ||
Minimum [Member] | |||||
Accumulated depreciation, depletion and amortization: | |||||
Unevaluated property costs expected evaluation period range | 3 years | ||||
Maximum [Member] | |||||
Accumulated depreciation, depletion and amortization: | |||||
Unevaluated property costs expected evaluation period range | 5 years |
Supplemental Information on O64
Supplemental Information on Oil and Natural Gas Properties (unaudited) (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) | 12 Months Ended | ||
Dec. 31, 2015MBoeMMcfMBbls | Dec. 31, 2014MBoeMMcfMBbls | Dec. 31, 2013MBoeMMcfMBbls | |
Proved developed and undeveloped reserves: | |||
Beginning of period, MBOE proved developed | MBoe | 18,201 | 7,470 | 6,735 |
End of period, MBOE proved developed | MBoe | 28,617 | 18,201 | 7,470 |
Beginning of periodc, MBOE proved developed | MBoe | 14,623 | 7,387 | 7,337 |
End of period, MBOE proved developed | MBoe | 25,654 | 14,623 | 7,387 |
Crude Oil [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of period | MBbls | 25,733 | 11,898 | 10,780 |
Revisions to previous estimates | MBbls | (1,632) | (243) | (2,540) |
Purchase of reserves in place | MBbls | 2,932 | 3,223 | 150 |
Sale of reserves in place | MBbls | (23) | (3,294) | |
Extensions and discoveries | MBbls | 19,127 | 12,547 | 7,713 |
Production | MBbls | (2,789) | (1,692) | (911) |
End of period | MBbls | 43,348 | 25,733 | 11,898 |
Beginning of period, proved developed | MBbls | 14,006 | 5,960 | 4,955 |
End of period, proved developed | MBbls | 22,257 | 14,006 | 5,960 |
Beginning of period, proved undeveloped | MBbls | 11,727 | 5,938 | 5,825 |
End of period, proved undeveloped | MBbls | 21,091 | 11,727 | 5,938 |
Natural Gas [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of period | MMcf | 42,548 | 17,751 | 19,753 |
Revisions to previous estimates | MMcf | 4,870 | (215) | (5,351) |
Purchase of reserves in place | MMcf | 2,915 | 8,591 | 317 |
Sale of reserves in place | MMcf | (105) | (4,576) | |
Extensions and discoveries | MMcf | 19,621 | 18,641 | 10,619 |
Production | MMcf | (4,312) | (2,220) | (3,011) |
End of period | MMcf | 65,537 | 42,548 | 17,751 |
Beginning of period, proved developed | MMcf | 25,171 | 9,059 | 10,680 |
End of period, proved developed | MMcf | 38,157 | 25,171 | 9,059 |
Beginning of period, proved undeveloped | MMcf | 17,377 | 8,692 | 9,073 |
End of period, proved undeveloped | MMcf | 27,380 | 17,377 | 8,692 |
Supplemental Information on O65
Supplemental Information on Oil and Natural Gas Properties (unaudited) (Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure) (Details) | 12 Months Ended | ||
Dec. 31, 2015$ / Mcfe$ / Boe | Dec. 31, 2014$ / Mcfe$ / Boe | Dec. 31, 2013$ / Mcfe$ / Boe | |
Natural Gas [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average 12-month price, net of differentials | $ / Mcfe | 2.73 | 6.38 | 5.45 |
Crude Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average 12-month price, net of differentials | $ / Boe | 47.25 | 86.30 | 92.16 |
Supplemental Information on O66
Supplemental Information on Oil and Natural Gas Properties (unaudited) (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract] | ||||||
Future cash inflows | $ 2,227,463 | $ 2,492,178 | $ 1,193,299 | |||
Production | (827,555) | (873,469) | (357,005) | |||
Development and net abandonment | (239,100) | (288,081) | (155,667) | |||
Future net inflows before income taxes | 1,160,808 | 1,330,628 | 680,627 | |||
Future income taxes | (164,490) | (68,239) | ||||
Future net cash flows | 1,160,808 | 1,166,138 | 612,388 | |||
10% discount factor | (589,918) | (586,596) | (328,442) | |||
Standardized measure of discounted future net cash flows | $ 579,542 | $ 283,946 | $ 231,148 | $ 570,890 | $ 579,542 | $ 283,946 |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||||
Standardized measure at the beginning of the period | 579,542 | 283,946 | 231,148 | |||
Sales and transfers, net of production costs | (110,476) | (120,518) | (78,661) | |||
Net change in sales and transfer prices, net of production costs | (286,660) | (156,066) | (46,088) | |||
Net change due to purchases and sales of in place reserves | 37,616 | 111,331 | (145,711) | |||
Extensions, discoveries, and improved recovery, net of future production and development costs incurred | 184,469 | 299,192 | 212,431 | |||
Changes in future development cost | 108,216 | 186,605 | 153,983 | |||
Revisions of quantity estimates | (12,625) | (7,673) | (68,958) | |||
Accretion of discount | 62,968 | 30,114 | 25,010 | |||
Net change in income taxes | 35,407 | (32,940) | 1,751 | |||
Changes in production rates, timing and other | (27,567) | (14,449) | (959) | |||
Aggregate change | (8,652) | 295,596 | 52,798 | |||
Standardized measure at the end of the period | $ 570,890 | $ 579,542 | $ 283,946 |
Other (Narrative) (Details)
Other (Narrative) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2016$ / d | Dec. 31, 2015USD ($)contract | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | |
Operating Leases And Other Property Plant And Equipment [Line Items] | |||||
Rig termination fee | $ 3,075 | ||||
Proceeds from sale of equipment | $ 114 | $ 527 | |||
Impairment of other property and equipment held for sale | $ 1,707 | $ 1,177 | |||
Gain on sale of equipment | $ 1,080 | ||||
Subsequent Event [Member] | |||||
Operating Leases And Other Property Plant And Equipment [Line Items] | |||||
Operating lease payable amount per day for placing rig on standby | $ / d | 15,000 | ||||
Horizontal Drilling [Member] | |||||
Operating Leases And Other Property Plant And Equipment [Line Items] | |||||
Number of contracts | contract | 2 | ||||
Extended contract expiration terms | The Cactus 2 Rig was initially contracted for a term of two years in April 2014. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In March 2015, the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018, respectively. | ||||
Operating leases, term of contract | 2 years |
Summarized Quarterly Financia68
Summarized Quarterly Financial Information (unaudited) (Schedule of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Summarized Quarterly Financial Information [Abstract] | |||||||||||||||
Total revenues | $ 33,563 | $ 34,316 | $ 39,242 | $ 30,391 | $ 38,418 | $ 39,657 | $ 40,502 | $ 33,285 | $ 137,512 | $ 151,862 | $ 102,569 | ||||
Income (loss) from operations | (118,542) | [1] | (83,910) | [1] | 6,231 | [1] | (12,889) | [1] | 7,983 | 11,562 | 12,080 | 6,645 | (209,110) | 38,270 | 10,664 |
Net income (loss) | (113,170) | [1] | (111,805) | [1] | (4,967) | [1] | (10,197) | [1] | 18,962 | 12,201 | 4,740 | 1,863 | (240,139) | 37,766 | 4,304 |
Income (loss) available to common shares | $ (115,144) | $ (113,779) | $ (6,940) | $ (12,171) | $ 16,988 | $ 10,227 | $ 2,767 | $ (111) | $ (248,034) | $ 29,871 | $ (323) | ||||
Basic income (loss) per share | $ (1.58) | $ (1.72) | $ (0.11) | $ (0.21) | $ 0.31 | $ 0.24 | $ 0.07 | $ 0 | $ (3.77) | $ 0.67 | $ (0.01) | ||||
Diluted income (loss) per share | $ (1.58) | $ (1.72) | $ (0.11) | $ (0.21) | $ 0.30 | $ 0.23 | $ 0.07 | $ 0 | $ (3.77) | $ 0.65 | $ (0.01) | ||||
Write-down of oil and natural gas properties | $ 121,134 | $ 87,301 | $ 208,435 | ||||||||||||
[1] | Loss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and gas properties of $87,301 and $121,134, respectively. |