Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2016 | Oct. 28, 2016 | |
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-Q | |
Document Period End Date | Sep. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 161,041,320 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 325,885 | $ 1,224 |
Accounts receivable | 56,172 | 39,624 |
Fair value of derivatives | 3,502 | 19,943 |
Other current assets | 1,712 | 1,461 |
Total current assets | 387,271 | 62,252 |
Oil and natural gas properties, full-cost accounting method: | ||
Evaluated properties | 2,593,798 | 2,335,223 |
Less accumulated depreciation, depletion, amortization and impairment | (1,901,102) | (1,756,018) |
Net oil and natural gas properties | 692,696 | 579,205 |
Unevaluated properties | 393,875 | 132,181 |
Total oil and natural gas properties | 1,086,571 | 711,386 |
Other property and equipment, net | 12,816 | 7,700 |
Restricted investments | 3,329 | 3,309 |
Deferred financing costs | 3,431 | 3,642 |
Fair value of derivatives | 57 | |
Acquisition deposit | 32,700 | |
Other assets, net | 1,429 | 305 |
Total assets | 1,527,604 | 788,594 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 99,026 | 70,970 |
Accrued interest | 5,950 | 5,989 |
Cash-settleable restricted stock unit awards | 8,269 | 10,128 |
Asset retirement obligations | 3,529 | 790 |
Deferred tax liability | 42 | |
Fair value of derivatives | 7,786 | |
Total current liabilities | 124,602 | 87,877 |
Senior secured revolving credit facility | 40,000 | |
Secured second lien term loan, net of unamortized deferred financing costs | 290,085 | 288,565 |
Asset retirement obligations | 1,934 | 4,317 |
Cash-settleable restricted stock unit awards | 7,042 | 4,877 |
Fair value of derivatives | 2,936 | |
Other long-term liabilities | 286 | 200 |
Total liabilities | 426,885 | 425,836 |
Stockholders' equity: | ||
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 and 1,578,948 shares outstanding, respectively | 15 | 16 |
Common stock, $0.01 par value, 300,000,000 and 150,000,000 shares authorized, respectively; 161,036,233 and 80,087,148 shares outstanding, respectively | 1,610 | 801 |
Capital in excess of par value | 1,535,661 | 702,970 |
Accumulated deficit | (436,567) | (341,029) |
Total stockholders' equity | 1,100,719 | 362,758 |
Total liabilities and stockholders' equity | $ 1,527,604 | $ 788,594 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Sep. 30, 2016 | Dec. 31, 2015 |
Stockholders' equity: | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 300,000,000 | 150,000,000 |
Common stock, shares outstanding | 161,036,233 | 80,087,148 |
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 | 1,458,948 | 1,578,948 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Operating revenues: | ||||
Total operating revenues | $ 55,927 | $ 34,316 | $ 131,770 | $ 103,949 |
Operating expenses: | ||||
Lease operating expenses | 9,961 | 7,194 | 24,229 | 20,728 |
Production taxes | 3,478 | 2,583 | 8,153 | 7,800 |
Depreciation, depletion and amortization | 17,303 | 16,704 | 49,318 | 52,395 |
General and administrative | 7,891 | 4,302 | 19,755 | 22,167 |
Accretion expense | 187 | 142 | 762 | 485 |
Write-down of oil and natural gas properties | 87,301 | 95,788 | 87,301 | |
Rig termination fee | 3,641 | |||
Acquisition expense | 456 | 2,410 | ||
Total operating expenses | 39,276 | 118,226 | 200,415 | 194,517 |
Income (loss) from operations | 16,651 | (83,910) | (68,645) | (90,568) |
Other (income) expense: | ||||
Interest expense, net of capitalized amounts | 831 | 5,603 | 10,502 | 15,567 |
(Gain) loss on derivative contracts | (5,135) | (23,283) | 11,281 | (17,463) |
Other income, net | (122) | (92) | (299) | (177) |
Total other (income) expense | (4,426) | (17,772) | 21,484 | (2,073) |
Income (loss) before income taxes | 21,077 | (66,138) | (90,129) | (88,495) |
Income tax (benefit) expense | (62) | 45,667 | (62) | 38,474 |
Net income (loss) | 21,139 | (111,805) | (90,067) | (126,969) |
Preferred stock dividends | (1,824) | (1,974) | (5,471) | (5,921) |
Income (loss) available to common stockholders | $ 19,315 | $ (113,779) | $ (95,538) | $ (132,890) |
Income (loss) per common share: | ||||
Basic | $ 0.14 | $ (1.72) | $ (0.85) | $ (2.10) |
Diluted | $ 0.14 | $ (1.72) | $ (0.85) | $ (2.10) |
Shares used in computing income (loss) per common share: | ||||
Basic | 136,983 | 66,277 | 112,925 | 63,265 |
Diluted | 137,483 | 66,277 | 112,925 | 63,265 |
Crude Oil [Member] | ||||
Operating revenues: | ||||
Total operating revenues | $ 49,095 | $ 30,582 | $ 117,093 | $ 94,584 |
Natural Gas And Natural Gas Liquids [Member] | ||||
Operating revenues: | ||||
Total operating revenues | $ 6,832 | $ 3,734 | $ 14,677 | $ 9,365 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Cash flows from operating activities: | ||
Net loss | $ (90,067) | $ (126,969) |
Adjustments to reconcile net loss to cash provided by operating activities: | ||
Depreciation, depletion and amortization | 50,560 | 52,583 |
Write-down of oil and natural gas properties | 95,788 | 87,301 |
Accretion expense | 762 | 485 |
Amortization of non-cash debt related items | 2,371 | 2,342 |
Deferred income tax (benefit) expense | (62) | 38,474 |
Net loss on derivatives, net of settlements | 27,105 | 7,635 |
Non-cash expense related to equity share-based awards | (253) | (300) |
Change in the fair value of liability share-based awards | 6,045 | 4,759 |
Payments to settle asset retirement obligations | (895) | (3,047) |
Changes in operating assets and liabilities: | ||
Accounts receivable | (16,444) | (7,278) |
Other current assets | (251) | 31 |
Current liabilities | 19,815 | 6,455 |
Acquisition deposit | (32,700) | |
Change in other long-term liabilities | 86 | 100 |
Change in other assets, net | (1,671) | 421 |
Payments to settle vested liability share-based awards related to early retirements | (3,538) | |
Payments to settle vested liability share-based awards | (10,300) | (3,925) |
Net cash provided by operating activities | 49,889 | 55,529 |
Cash flows from investing activities: | ||
Capital expenditures | (122,698) | (175,699) |
Acquisitions | (302,057) | (2,849) |
Proceeds from sales of mineral interests and equipment | 22,923 | 348 |
Net cash used in investing activities | (401,832) | (178,200) |
Cash flows from financing activities: | ||
Borrowings on senior secured revolving credit facility | 217,000 | 130,000 |
Payments on senior secured revolving credit facility | (257,000) | (66,000) |
Issuance of common stock, net | 722,715 | 65,546 |
Payment of preferred stock dividends | (5,471) | (5,921) |
Payment of deferred financing costs | (640) | |
Net cash provided by financing activities | 676,604 | 123,625 |
Net change in cash and cash equivalents | 324,661 | 954 |
Balance, beginning of period | 1,224 | 968 |
Balance, end of period | $ 325,885 | $ 1,922 |
Description of Business and Bas
Description of Business and Basis of Presentation | 9 Months Ended |
Sep. 30, 2016 | |
Description of Business and Basis of Presentation [Abstract] | |
Description of Business and Basis of Presentation | Note 1 - Description of Business 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. 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 in the Midland Basin. 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 its existing acreage and acquisition of additional locations through working interest acquisitions, 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 interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 . The balance sheet at December 31, 2015 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2016 . In the opinion of management, the accompanying unaudited 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 may have been reclassified to conform to current year presentation. Recently issued accounting policies In March 2016, the Financial Accounting Standards Board issued accounting standards update No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures. In August 2016, the Financial Accounting Standards Board issued accounting standards update No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures. Recently adopted accounting policies In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which eliminates the current 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. As of September 30, 2016 , the Company adopted this ASU, which does not have a material impact on its financial state ments. |
Oil and Natural Gas Properties
Oil and Natural Gas Properties | 9 Months Ended |
Sep. 30, 2016 | |
Oil and Natural Gas Properties [Abstract] | |
Oil and Natural Gas Properties | Note 2 – 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. 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 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 September 30, 2016 , the average realized prices used in determining the estimated future net cash flows from proved reserves were $ 38.92 per barrel of oil and $2.53 per Mcf of natural gas. For the three months ended September 30, 2016 no write-down of oil and natural gas properties was recognized as a result of the ceiling test limitation. For the nine months ended September 30, 2016 , the Company recognized a write-down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. |
Acquisitions
Acquisitions | 9 Months Ended |
Sep. 30, 2016 | |
Acquisitions [Abstract] | |
Acquisitions | Note 3 - Acquisitions 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. 2016 acquisitions On August 3, 2016, the Company entered into a definitive purchase and sale agreement for the acquisition of an addition al 4.0% working interest ( 3.0% net revenue interest) in the Casselman-Bohannon fields for total cash consideration o f $13,000 , excluding customary purchase price adjustments. Following the completion of this acquisition the Company will own approximately 75.3% working interest ( 58.5% net revenue interest) in the Casselman-Bohannon fields. The following table summarizes the estimated acquisition date fair values of the net assets to be acquired in the acquisition: Evaluated oil and natural gas properties $ 6,492 Unevaluated oil and natural gas properties 6,508 Net assets acquired $ 13,000 On May 26, 2016, the Company completed the acquisition of 17,298 gross ( 14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $ 220,000 and 9,333,333 shares of common stock for a total purchase price of $ 329,573 , excluding customary purchase price adjust ments (the “Big Star Transaction”). The Company acquired an 81% average working interest ( 61% average net revenue interest) in the properties acquired in the Big Star Transaction. The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material. The following table summarizes the estimated acquisition date fair values of the net assets to be acquired in the acquisition: Evaluated oil and natural gas properties $ 96,194 Unevaluated oil and natural gas properties 233,387 Asset retirement obligations (8) Net assets acquired $ 329,573 The following unaudited summary pro forma financial information fo r the three and nine months ended September 30, 2016 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 Big Star Transaction 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 Big Star Transaction occurred as of January 1, 2015. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including those pertaining to revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, write-down of oil and natural gas properties, accretion expense, interest expense and capitalized interest. Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Revenues $ 55,927 $ 41,501 $ 140,937 $ 119,561 Income from operations 16,651 (17,644) (68,753) (25,339) Income available to common stockholders 19,315 (43,720) (88,886) (55,896) Net income per common share: Basic $ 0.14 $ (0.43) $ (0.79) $ (0.57) Diluted $ 0.14 $ (0.43) $ (0.79) $ (0.57) From the date of the acquisition through the period ende d September 30, 2016, the properties asso ciated with the Big Star Transaction have been comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties. On May 16, 2016, the Company completed the following transactions (collectively, the “AMI Transaction”) for an aggregate net cash purchase price of $ 33,012 , excluding customary purchase price adjustments. Key elements of the AMI Transaction include: · Formation of an area of mutual interest with TRP Energy, LLC (“TRP”) in western Reagan County, Texas, through the joint acquisition from a private party of 4,745 net acres (with a 55% share to Callon) north of the Garrison Draw field; and · Callon’s simultaneous sale of a 27.5 % interest in the Garrison Draw field to TRP. The following table summarizes the acquisition date fair values of the net assets acquired, including customary purchase price adjustments: Evaluated oil and natural gas properties $ 15,951 Unevaluated oil and natural gas properties 17,069 Asset retirement obligations (8) Net assets acquired $ 33,012 On January 18, 2016, the Company completed the acquisition of an additional 4.9% working interest ( 3.7% net revenue interest) in the Casselman-Bohannon fields for an aggregate cash purchase price of $ 10,183 , including customary purchase price adjustments. The following table summarizes the acquisition date fair values of the net assets acquired, including customary purchase price adjustments: Evaluated oil and natural gas properties $ 5,527 Unevaluated oil and natural gas properties 4,656 Net assets acquired $ 10,183 Subsequent event On October 20, 2016, the Company completed the acquisition of 6,904 gross ( 5,952 net) acres primarily located in Howard County, Texas fr om P l ymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for t otal cash consideration of $340,686 , exclu ding customary purchase pric e adjustments (the “Plymouth Transaction ”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired an 82% average working interest ( 62% average net revenue interest) in the properties acquired in the Plymouth Transaction . In September 2016, in connection with the execution of the purchase and sale agreement for the Plymouth Transaction, the Company paid a deposit in the amount of $ 32,700 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of September 30, 2016. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Note 4 - Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share: (share amounts in thousands) Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Net income (loss) $ 21,139 $ (111,805) $ (90,067) $ (126,969) Preferred stock dividends (1,824) (1,974) (5,471) (5,921) Income (loss) available to common stockholders $ 19,315 $ (113,779) $ (95,538) $ (132,890) Weighted average shares outstanding 136,983 66,277 112,925 63,265 Dilutive impact of restricted stock 500 — — — Weighted average shares outstanding for diluted income (loss) per share 137,483 66,277 112,925 63,265 Basic income (loss) per share $ 0.14 $ (1.72) $ (0.85) $ (2.10) Diluted income (loss) per share $ 0.14 $ (1.72) $ (0.85) $ (2.10) Stock options (a) 15 15 15 15 Restricted stock (a) 25 159 25 159 (a) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive . |
Borrowings
Borrowings | 9 Months Ended |
Sep. 30, 2016 | |
Borrowings [Abstract] | |
Borrowings | Note 5 - Borrowings The Company’s borrowings consisted of the following at: September 30, 2016 December 31, 2015 Principal components Senior secured revolving credit facility $ — $ 40,000 Secured second lien term loan 300,000 300,000 Total principal outstanding 300,000 340,000 Secured second lien term loan, unamortized deferred financing costs (9,915) (11,435) Total carrying value of borrowings $ 290,085 $ 328,565 Senior secured revolving credit facility (the “Credit Facility”) 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 participants include several institutional lenders. 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 September 30, 2016 , the Credit Facility’s borrowing base was $385,000 . The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Effecti ve July 13, 2016, the Credit Facility’s borrowing base was increased to $ 385,000 and the Com pany’s capacity to hedge oil and natural gas volumes was effectively increased with a change in the capacity calculation to a percentage of total proved reserves from proved producing reserves. In addition, the interest rate for borrowings under the Credit Facility was increased 0.25% across all tiers of the pricing grid, resulting in a range of interest costs equal to LIBOR plus 2.00% to 3.00% . There were no modifications to other terms or covenants of the Credit Facility. As of September 30, 2016 , there was no balance outstanding on the Credit Facility. For the quarter ended September 30, 2016 , the Credit Facility had a weighted-average interest rate of 2.92% , calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00% , 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. Secured second lien term loan (the “Term Loan” ) On October 8, 2014, the Company entered into the Term Loan with an aggregate amount of up to $300,000 and a maturity date of October 8, 2021 . The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. The Term Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount would be (i) 102% of principal if the prepayment event occurred prior to October 8, 2016, (ii) 101% of principal if the prepayment event occurred on or after October 8, 2016, but before October 8, 2017, and (iii) 100% of principal for prepayments made on or after October 8, 2017. The Term Loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. As of September 30, 2016 , the balance outstanding on the Term 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 elected a LIBOR rate based on various tenors, and was incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2016 . Restrictive covenants The Company’s Credit Facility and Term 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 September 30, 2016 . Subsequent events On October 3, 2016, the Company closed the sale of $ 400,000 aggregate principal amount of 6.125% senior unsecured notes due 2024 (the “S enior Notes”) at an issue price of 100% of the aggregate principal amount of the Senior Notes. The Notes will mature on October 1, 2024 , unless redeemed in accordance with their terms prior to such date. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $ 391,270 . The Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. Interest on the Senior Notes is payable semi-annually. On October 11, 2016, the Term Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the Senior Notes, which is expected to result in a loss on early extinguishment of debt of $ 12,851 (inclusive of $ 3,000 in prepayment fees and $9,851 of unamortized debt issuance costs). |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Derivative Instruments and Hedging Activities | Note 6 - Derivative 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 con tracts under master agreements with 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 sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statements of operations. The following table reflects the fair value of the Company’s derivative instruments for the periods presented: Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 09/30/2016 12/31/2015 09/30/2016 12/31/2015 09/30/2016 12/31/2015 Natural gas Current Fair value of derivatives $ 29 $ — $ (233) $ — $ (204) $ — Natural gas Non-current Fair value of derivatives 3 — — — 3 — Oil Current Fair value of derivatives 3,473 19,943 (7,553) — (4,080) 19,943 Oil Non-current Fair value of derivatives 54 — (2,936) — (2,882) — Totals $ 3,559 $ 19,943 $ (10,722) $ — $ (7,163) $ 19,943 As previously discusse d, 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: September 30, 2016 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives $ 3,591 $ (89) $ 3,502 Long-term assets: Fair value of derivatives 57 — 57 Current liabilities: Fair value of derivatives (7,875) 89 (7,786) Long-term liabilities: Fair value of derivatives $ (2,936) $ — $ (2,936) 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 periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Oil derivatives Net gain on settlements $ 4,252 $ 9,399 $ 15,467 $ 23,863 Net gain (loss) on fair value adjustments 699 13,758 (26,904) (6,787) Total gain (loss) $ 4,951 $ 23,157 $ (11,437) $ 17,076 Natural gas derivatives Net gain (loss) on settlements $ (161) $ 390 $ 357 $ 1,235 Net gain (loss) on fair value adjustments 345 (264) (201) (848) Total gain $ 184 $ 126 $ 156 $ 387 Total gain (loss) on derivative contracts $ 5,135 $ 23,283 $ (11,281) $ 17,463 Derivative positions Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2016 : For the Remainder of For the Full Year of Oil contracts 2016 2017 Swap contracts (WTI) Total volume (MBbls) 184 — Weighted average price per Bbl $ 58.23 $ — Swap contracts combined with short puts (WTI, enhanced swaps) Total volume (MBbls) — 730 Weighted average price per Bbl Swap $ — $ 44.50 Short put option $ — $ 30.00 Collar contracts combined with short puts (WTI, three-way collars) Volume (MBbls) 184 — Weighted average price per Bbl Ceiling (short call option) $ 65.00 $ — Floor (long put option) $ 55.00 $ — Short put option $ 40.33 $ — Collar contracts (WTI, two-way collars) Total volume (MBbls) 184 438 Weighted average price per Bbl Ceiling (short call) $ 46.50 $ 59.05 Floor (long put) $ 37.50 $ 47.50 Call option contracts (short position) Total volume (MBbls) — 670 Weighted average price per Bbl Call strike price $ — $ 50.00 Swap contracts (Midland basis differentials) Volume (MBbls) 368 — Weighted average price per Bbl $ 0.17 $ — Natural gas contracts Swap contracts (Henry Hub) Total volume (BBtu) 552 — Weighted average price per MMBtu $ 2.52 $ — Collar contracts combined with short puts (Henry Hub, three-way collars) Total volume (BBtu) — 1,460 Weighted average price per MMBtu Ceiling (short call option) $ — $ 3.71 Floor (long put option) $ — $ 3.00 Short put option $ — $ 2.50 Subsequent event The following derivative contract was executed subsequent to September 30, 2016 : For the Remainder of For the Remainder of Oil contracts 2016 2017 Collar contracts (WTI, two-way collars) Total volume (MBbls) — 1,095 Weighted average price per Bbl Ceiling (short call option) $ — $ 57.79 Floor (long put option) $ — $ 47.50 |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | Note 7 - Fair Value 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 : September 30, 2016 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 3,559 $ — $ 3,559 Liabilities Derivative financial instruments Fair value of derivatives — (10,722) — (10,722) Total net assets $ — $ (7,163) $ — $ (7,163) December 31, 2015 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 19,943 $ — $ 19,943 Liabilities Derivative financial instruments Fair value of derivatives — — — — Total net assets $ — $ 19,943 $ — $ 19,943 Assets and liabilities measured at fair value on a nonrecurring basis Acquisitions. As discussed in Note 3 , the Company completed four acquisitions during the nine months ended September 30, 2016 . 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 natural gas forward prices. The fair value measurements were based on L evel 2 and L evel 3 inputs. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2016 | |
Income Taxes [Abstract] | |
Income Taxes | Note 8 - Income Taxes The Company typically 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. As a result of the write-down of oil and natural gas properties in the latter part of 2015 and first half of 2016, the Company 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 $139,633 as of September 30, 2016 . |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2016 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | Note 9 - Asset Retirement Obligations The table below summarizes the Company’s asset retirement obligations activity for the nine months ended September 30, 2016 : Asset retirement obligations at January 1, 2016 $ 5,107 Accretion expense 762 Liabilities incurred 12 Liabilities settled (807) Revisions to estimate 389 Asset retirement obligations at end of period 5,463 Less: Current asset retirement obligations (3,529) Long-term asset retirement obligations at September 30, 2016 $ 1,934 Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at September 30, 2016 as long-term restricted investments were $3,329 . These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedica ted to pay future abandonment costs. |
Equity Transactions
Equity Transactions | 9 Months Ended |
Sep. 30, 2016 | |
Equity Transactions [Abstract] | |
Equity Transactions | Note 10 - Equity 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 $1,824 and $1,974 for the three months ended September 30, 2016 and 2015 , respectively, and $5,471 and $5,921 for the nine months ended September 30, 2016 and 2015 , respectively. The Preferred Stock has no stated maturity and is not 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 in cash, plus any accrued and unpaid dividends to the redemption date. Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, 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 such 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 September 30, 2016 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $ 15.70 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 3.2 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. On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of September 30, 2016 , the Company had 1,458,948 shares of its Preferred Stock issued and outstanding. Common stock On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $ 94,973 . Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes. On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $ 205,869 . Proceeds from the offering were used to fund the May 2016 Big Star Transaction and AMI Transaction, described in Note 3. On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 3 , at an assumed offering price of $ 11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date. On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $ 421,923 . Proceeds from the offering were used to substantially fund the Plymouth Transaction , described in Note 3. |
Other
Other | 9 Months Ended |
Sep. 30, 2016 | |
Other [Abstract] | |
Other | Note 11 - Other Operating leases As of September 30, 2016 , the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”). The contract terms of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining 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 placed its Cactus 1 Rig on standby and was required to pay a “standby” day rate of $ 15,000 per day, pursuant to the terms of the agreement, allowing the Company to retain the option to return the rig to service under the contract terms. In August 2016, the Company returned its Cactus 1 Rig to service. Subsequent event In October 2016 the Company entered into a contract for a horizontal drilling rig (the “Cactus 3 Rig”). The contract term will begin January 2017 through June 2017 with a day rate of $16,000 per day. |
Acquisitions (Tables)
Acquisitions (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Howard County, Texas [Member] | Big Star Transaction [Member] | |
Fair Value of Net Assets Acquired | Evaluated oil and natural gas properties $ 96,194 Unevaluated oil and natural gas properties 233,387 Asset retirement obligations (8) Net assets acquired $ 329,573 |
Unaudited Summary Pro Forma Financial Information | Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Revenues $ 55,927 $ 41,501 $ 140,937 $ 119,561 Income from operations 16,651 (17,644) (68,753) (25,339) Income available to common stockholders 19,315 (43,720) (88,886) (55,896) Net income per common share: Basic $ 0.14 $ (0.43) $ (0.79) $ (0.57) Diluted $ 0.14 $ (0.43) $ (0.79) $ (0.57) |
Western Reagan County, Texas [Member] | AMI Transaction [Member] | |
Fair Value of Net Assets Acquired | Evaluated oil and natural gas properties $ 15,951 Unevaluated oil and natural gas properties 17,069 Asset retirement obligations (8) Net assets acquired $ 33,012 |
Casselman-Bohannon Fields [Member] | January 18, 2016 Acquisitions [Member] | |
Fair Value of Net Assets Acquired | Evaluated oil and natural gas properties $ 5,527 Unevaluated oil and natural gas properties 4,656 Net assets acquired $ 10,183 |
Casselman-Bohannon Fields [Member] | August 3, 2016 Acquisitions [Member] | |
Fair Value of Net Assets Acquired | Evaluated oil and natural gas properties $ 6,492 Unevaluated oil and natural gas properties 6,508 Net assets acquired $ 13,000 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earnings Per Share | (share amounts in thousands) Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Net income (loss) $ 21,139 $ (111,805) $ (90,067) $ (126,969) Preferred stock dividends (1,824) (1,974) (5,471) (5,921) Income (loss) available to common stockholders $ 19,315 $ (113,779) $ (95,538) $ (132,890) Weighted average shares outstanding 136,983 66,277 112,925 63,265 Dilutive impact of restricted stock 500 — — — Weighted average shares outstanding for diluted income (loss) per share 137,483 66,277 112,925 63,265 Basic income (loss) per share $ 0.14 $ (1.72) $ (0.85) $ (2.10) Diluted income (loss) per share $ 0.14 $ (1.72) $ (0.85) $ (2.10) Stock options (a) 15 15 15 15 Restricted stock (a) 25 159 25 159 Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive . |
Borrowings (Tables)
Borrowings (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Borrowings [Abstract] | |
Schedule of Borrowings | September 30, 2016 December 31, 2015 Principal components Senior secured revolving credit facility $ — $ 40,000 Secured second lien term loan 300,000 300,000 Total principal outstanding 300,000 340,000 Secured second lien term loan, unamortized deferred financing costs (9,915) (11,435) Total carrying value of borrowings $ 290,085 $ 328,565 |
Derivative Instruments and He20
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Fair Value of Derivative Instruments | Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 09/30/2016 12/31/2015 09/30/2016 12/31/2015 09/30/2016 12/31/2015 Natural gas Current Fair value of derivatives $ 29 $ — $ (233) $ — $ (204) $ — Natural gas Non-current Fair value of derivatives 3 — — — 3 — Oil Current Fair value of derivatives 3,473 19,943 (7,553) — (4,080) 19,943 Oil Non-current Fair value of derivatives 54 — (2,936) — (2,882) — Totals $ 3,559 $ 19,943 $ (10,722) $ — $ (7,163) $ 19,943 |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | September 30, 2016 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives $ 3,591 $ (89) $ 3,502 Long-term assets: Fair value of derivatives 57 — 57 Current liabilities: Fair value of derivatives (7,875) 89 (7,786) Long-term liabilities: Fair value of derivatives $ (2,936) $ — $ (2,936) 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 |
Schedule of Gain or Loss on Derivative Contracts | Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Oil derivatives Net gain on settlements $ 4,252 $ 9,399 $ 15,467 $ 23,863 Net gain (loss) on fair value adjustments 699 13,758 (26,904) (6,787) Total gain (loss) $ 4,951 $ 23,157 $ (11,437) $ 17,076 Natural gas derivatives Net gain (loss) on settlements $ (161) $ 390 $ 357 $ 1,235 Net gain (loss) on fair value adjustments 345 (264) (201) (848) Total gain $ 184 $ 126 $ 156 $ 387 Total gain (loss) on derivative contracts $ 5,135 $ 23,283 $ (11,281) $ 17,463 |
Schedule of Outstanding Oil and Natural Gas Derivative Contracts | For the Remainder of For the Full Year of Oil contracts 2016 2017 Swap contracts (WTI) Total volume (MBbls) 184 — Weighted average price per Bbl $ 58.23 $ — Swap contracts combined with short puts (WTI, enhanced swaps) Total volume (MBbls) — 730 Weighted average price per Bbl Swap $ — $ 44.50 Short put option $ — $ 30.00 Collar contracts combined with short puts (WTI, three-way collars) Volume (MBbls) 184 — Weighted average price per Bbl Ceiling (short call option) $ 65.00 $ — Floor (long put option) $ 55.00 $ — Short put option $ 40.33 $ — Collar contracts (WTI, two-way collars) Total volume (MBbls) 184 438 Weighted average price per Bbl Ceiling (short call) $ 46.50 $ 59.05 Floor (long put) $ 37.50 $ 47.50 Call option contracts (short position) Total volume (MBbls) — 670 Weighted average price per Bbl Call strike price $ — $ 50.00 Swap contracts (Midland basis differentials) Volume (MBbls) 368 — Weighted average price per Bbl $ 0.17 $ — Natural gas contracts Swap contracts (Henry Hub) Total volume (BBtu) 552 — Weighted average price per MMBtu $ 2.52 $ — Collar contracts combined with short puts (Henry Hub, three-way collars) Total volume (BBtu) — 1,460 Weighted average price per MMBtu Ceiling (short call option) $ — $ 3.71 Floor (long put option) $ — $ 3.00 Short put option $ — $ 2.50 Subsequent event The following derivative contract was executed subsequent to September 30, 2016 : For the Remainder of For the Remainder of Oil contracts 2016 2017 Collar contracts (WTI, two-way collars) Total volume (MBbls) — 1,095 Weighted average price per Bbl Ceiling (short call option) $ — $ 57.79 Floor (long put option) $ — $ 47.50 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Measurements [Abstract] | |
Fair Value of Assets and Liabilities Measured on Recurring Basis | September 30, 2016 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 3,559 $ — $ 3,559 Liabilities Derivative financial instruments Fair value of derivatives — (10,722) — (10,722) Total net assets $ — $ (7,163) $ — $ (7,163) December 31, 2015 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 19,943 $ — $ 19,943 Liabilities Derivative financial instruments Fair value of derivatives — — — — Total net assets $ — $ 19,943 $ — $ 19,943 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Asset Retirement Obligations [Abstract] | |
Schedule of Change in Asset Retirement Obligation | Asset retirement obligations at January 1, 2016 $ 5,107 Accretion expense 762 Liabilities incurred 12 Liabilities settled (807) Revisions to estimate 389 Asset retirement obligations at end of period 5,463 Less: Current asset retirement obligations (3,529) Long-term asset retirement obligations at September 30, 2016 $ 1,934 |
Oil and Natural Gas Properties
Oil and Natural Gas Properties (Narrative) (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2015USD ($) | Sep. 30, 2016USD ($)$ / Mcfe$ / bbl | Sep. 30, 2015USD ($) | |
Write-down of oil and natural gas properties | $ | $ 87,301 | $ 95,788 | $ 87,301 |
Crude Oil [Member] | |||
Prices used in determining estimated future net cash flows from proved reserves | $ / bbl | 38.92 | ||
Natural Gas [Member] | |||
Prices used in determining estimated future net cash flows from proved reserves | $ / Mcfe | 2.53 |
Acquisitions (Narrative) (Detai
Acquisitions (Narrative) (Details) $ in Thousands | Oct. 20, 2016USD ($)a | Aug. 03, 2016USD ($) | May 26, 2016USD ($)ashares | May 16, 2016USD ($)a | Jan. 18, 2016USD ($) | Sep. 30, 2016USD ($) |
Business Acquisition [Line Items] | ||||||
Acquisition deposit | $ 32,700 | |||||
Plymouth Transaction [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Acquisition deposit | $ 32,700 | |||||
Howard County, Texas [Member] | Big Star Transaction [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | $ 220,000 | |||||
Aggregate purchase price | $ 329,573 | |||||
Shares of common stock issued in acquisition | shares | 9,333,333 | |||||
Gas and oil area, developed and undeveloped, gross | a | 17,298 | |||||
Gas and oil area, developed and undeveloped, net | a | 14,089 | |||||
Working interest | 81.00% | |||||
Net revenue interest | 61.00% | |||||
Howard County, Texas [Member] | Plymouth Transaction [Member] | Subsequent Event [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | $ 340,686 | |||||
Gas and oil area, developed and undeveloped, gross | a | 6,904 | |||||
Gas and oil area, developed and undeveloped, net | a | 5,952 | |||||
Working interest | 82.00% | |||||
Net revenue interest | 62.00% | |||||
Casselman-Bohannon Fields [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | $ 13,000 | |||||
Aggregate purchase price | $ 13,000 | $ 10,183 | ||||
Working interest | 75.30% | |||||
Net revenue interest | 58.50% | |||||
Casselman-Bohannon Fields [Member] | Additional Acquisition [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | $ 10,183 | |||||
Working interest | 4.00% | 4.90% | ||||
Net revenue interest | 3.00% | 3.70% | ||||
Western Reagan County, Texas [Member] | AMI Transaction [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | $ 33,012 | |||||
Aggregate purchase price | $ 33,012 | |||||
Western Reagan County, Texas [Member] | AMI Transaction [Member] | TRP Energy, LLC [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Gas and oil area, developed and undeveloped, net | a | 4,745 | |||||
Percentage of ownership interest acquired | 55.00% | |||||
Sale of ownership interest, percent | 27.50% |
Acquisitions (Fair Value of Net
Acquisitions (Fair Value of Net Assets Acquired ) (Details) - USD ($) $ in Thousands | Aug. 03, 2016 | May 26, 2016 | May 16, 2016 | Jan. 18, 2016 |
Howard County, Texas [Member] | Big Star Transaction [Member] | ||||
Business Acquisition [Line Items] | ||||
Asset retirement obligations | $ (8) | |||
Net assets acquired | 329,573 | |||
Howard County, Texas [Member] | Big Star Transaction [Member] | Evaluated Oil and Natural Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | 96,194 | |||
Howard County, Texas [Member] | Big Star Transaction [Member] | Unevaluated Oil and Natural Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | $ 233,387 | |||
Casselman-Bohannon Fields [Member] | ||||
Business Acquisition [Line Items] | ||||
Net assets acquired | $ 13,000 | $ 10,183 | ||
Casselman-Bohannon Fields [Member] | Evaluated Oil and Natural Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | 6,492 | 5,527 | ||
Casselman-Bohannon Fields [Member] | Unevaluated Oil and Natural Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | $ 6,508 | $ 4,656 | ||
Western Reagan County, Texas [Member] | AMI Transaction [Member] | ||||
Business Acquisition [Line Items] | ||||
Asset retirement obligations | $ (8) | |||
Net assets acquired | 33,012 | |||
Western Reagan County, Texas [Member] | AMI Transaction [Member] | Evaluated Oil and Natural Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | 15,951 | |||
Western Reagan County, Texas [Member] | AMI Transaction [Member] | Unevaluated Oil and Natural Gas Properties [Member] | ||||
Business Acquisition [Line Items] | ||||
Oil and natural gas properties | $ 17,069 |
Acquisitions (Unaudited Pro For
Acquisitions (Unaudited Pro Forma Financial Information) (Details) - Howard County, Texas [Member] - Big Star Transaction [Member] - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Business Acquisition [Line Items] | ||||
Revenues | $ 55,927 | $ 41,501 | $ 140,937 | $ 119,561 |
Income from operations | 16,651 | (17,644) | (68,753) | (25,339) |
Income available to common stockholders | $ 19,315 | $ (43,720) | $ (88,886) | $ (55,896) |
Net income per common share Basic | $ 0.14 | $ (0.43) | $ (0.79) | $ (0.57) |
Net income per common share Diluted | $ 0.14 | $ (0.43) | $ (0.79) | $ (0.57) |
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 | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Earnings Per Share, Basic and Diluted | |||||
Net income (loss) | $ 21,139 | $ (111,805) | $ (90,067) | $ (126,969) | |
Preferred stock dividends | (1,824) | (1,974) | (5,471) | (5,921) | |
Income (loss) available to common stockholders | $ 19,315 | $ (113,779) | $ (95,538) | $ (132,890) | |
Weighted average shares outstanding | 136,983 | 66,277 | 112,925 | 63,265 | |
Weighted average shares outstanding for diluted income (loss) per share | 137,483 | 66,277 | 112,925 | 63,265 | |
Basic income (loss) per share | $ 0.14 | $ (1.72) | $ (0.85) | $ (2.10) | |
Diluted income (loss) per share | $ 0.14 | $ (1.72) | $ (0.85) | $ (2.10) | |
Options [Member] | |||||
Earnings Per Share, Basic and Diluted | |||||
Excluded from the diluted EPS calculation because their effect would be anti-dilutive | [1] | 15 | 15 | 15 | 15 |
Restricted Stock [Member] | |||||
Earnings Per Share, Basic and Diluted | |||||
Dilutive impact | 500 | ||||
Excluded from the diluted EPS calculation because their effect would be anti-dilutive | [1] | 25 | 159 | 25 | 159 |
[1] | Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive |
Borrowings (Credit Facility) (N
Borrowings (Credit Facility) (Narrative) (Details) - USD ($) $ in Thousands | Jul. 13, 2016 | Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 |
Line of Credit Facility [Line Items] | ||||
Debt instrument outstanding | $ 300,000 | $ 300,000 | $ 340,000 | |
Senior Secured Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 500,000 | 500,000 | ||
Current borrowing capacity | $ 385,000 | $ 385,000 | $ 385,000 | |
Increase in interest rate on credit facility | 0.25% | |||
Interest rate at period end (as a percent) | 2.92% | 2.92% | ||
Debt instrument outstanding | $ 0 | $ 0 | $ 40,000 | |
Unused capacity, commitment fee (as a percent) | 0.50% | |||
Debt instrument maturity date | Mar. 11, 2019 | |||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt instrument interest rate | 2.00% | |||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | LIBOR [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt instrument interest rate | 2.00% | |||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt instrument interest rate | 3.00% | |||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | LIBOR [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt instrument interest rate | 3.00% |
Borrowings (Term Loans and Seni
Borrowings (Term Loans and Senior Notes) (Narrative) (Details) - USD ($) | Oct. 11, 2016 | Oct. 03, 2016 | Oct. 08, 2014 | Sep. 30, 2016 | Dec. 31, 2015 |
Line of Credit Facility [Line Items] | |||||
Debt instrument outstanding | $ 300,000,000 | $ 340,000,000 | |||
Unamortized deferred financing costs | 9,915,000 | 11,435,000 | |||
Secured Second Lien Term Loan [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument outstanding | $ 300,000,000 | $ 300,000,000 | |||
Debt instrument, description | The prepayment amount would be (i) 102% of principal if the prepayment event occurred prior to October 8, 2016, (ii) 101% of principal if the prepayment event occurred on or after October 8, 2016, but before October 8, 2017, and (iii) 100% of principal for prepayments made on or after October 8, 2017. The Term Loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. | ||||
Proceeds from issuance of debt | $ 300,000,000 | ||||
Debt instrument, interest rate, effective | 8.50% | ||||
Floor rate | 1.00% | ||||
Debt instrument interest rate | 7.50% | ||||
Debt instrument maturity date | Oct. 8, 2021 | ||||
Secured Second Lien Term Loan [Member] | Prior to First Anniversary [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Prepayment Premium Percentage | 102.00% | ||||
Secured Second Lien Term Loan [Member] | After First Anniversary but Prior to Second Anniversary [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Prepayment Premium Percentage | 101.00% | ||||
Secured Second Lien Term Loan [Member] | After Second Anniversary [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Prepayment Premium Percentage | 100.00% | ||||
6.125% Senior Unsecured Notes Due 2024 [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument maturity date | Oct. 1, 2024 | ||||
Subsequent Event [Member] | 6.125% Senior Unsecured Notes Due 2024 [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument aggregate principal amount | $ 400,000,000 | ||||
Debt instrument, interest rate, stated (as a percent) | 6.125% | ||||
Loss on early extinguishment of debt | $ 12,851,000 | ||||
Net proceeds from issuance of senior unsecured notes | $ 391,270,000 | ||||
Debt instrument, prepayment fees | 3,000,000 | ||||
Percentage of aggregate principal amount in which issuance price is applied | 100.00% | ||||
Unamortized deferred financing costs | $ 9,851,000 |
Borrowings (Schedule of Borrowi
Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Principal components: | ||
Total principal outstanding | $ 300,000 | $ 340,000 |
Secured second lien term loan, unamortized deferred financing costs | (9,915) | (11,435) |
Total carrying value of borrowings | 290,085 | 328,565 |
Senior Secured Revolving Credit Facility [Member] | ||
Principal components: | ||
Total principal outstanding | 0 | 40,000 |
Secured Second Lien Term Loan [Member] | ||
Principal components: | ||
Total principal outstanding | $ 300,000 | $ 300,000 |
Derivative Instruments and He31
Derivative Instruments and Hedging Activities (Fair Value of Derivative Instruments) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | $ 3,559 | $ 19,943 |
Liability Fair Value | (10,722) | |
Net Derivative Fair Value | (7,163) | 19,943 |
Non-Current Assets Fair Market Value Of Derivatives [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 54 | |
Non-Current Assets Fair Market Value Of Derivatives [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 3 | |
Non-current liabilities - Fair value of derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (2,936) | |
Non-current liabilities - Fair value of derivatives [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (2,936) | |
Current assets - Fair value of derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 3,502 | 19,943 |
Current assets - Fair value of derivatives [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 3,473 | 19,943 |
Current assets - Fair value of derivatives [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Fair Value | 29 | |
Current liabilities - Fair value of derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (7,786) | |
Current liabilities - Fair value of derivatives [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (7,553) | |
Current liabilities - Fair value of derivatives [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Fair Value | (233) | |
Balance Sheet Current [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | (4,080) | $ 19,943 |
Balance Sheet Current [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | (204) | |
Balance Sheet Non Current [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | (2,882) | |
Balance Sheet Non Current [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Net Derivative Fair Value | $ 3 |
Derivative Instruments and He32
Derivative Instruments and Hedging Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Offsetting Assets and Liabilities [Line Items] | ||
Derivative Assets | $ 3,559 | $ 19,943 |
Derivative Liabilities | (10,722) | |
Current assets - Fair value of derivatives [Member] | ||
Offsetting Assets and Liabilities [Line Items] | ||
Derivative asset, fair value, gross asset | 3,591 | 19,943 |
Derivative asset, fair value, gross liability | (89) | |
Derivative Assets | 3,502 | $ 19,943 |
Long-term assets: Fair value of derivatives [Member] | ||
Offsetting Assets and Liabilities [Line Items] | ||
Derivative asset, fair value, gross asset | 57 | |
Derivative Assets | 57 | |
Current liabilities - Fair value of derivatives [Member] | ||
Offsetting Assets and Liabilities [Line Items] | ||
Derivative liability, fair value, gross liability | (7,875) | |
Derivative liability, fair value, gross asset | 89 | |
Derivative Liabilities | (7,786) | |
Non-current liabilities - Fair value of derivatives [Member] | ||
Offsetting Assets and Liabilities [Line Items] | ||
Derivative liability, fair value, gross liability | (2,936) | |
Derivative Liabilities | $ (2,936) |
Derivative Instruments and He33
Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Net gain (loss) on fair value adjustments | $ (27,105) | $ (7,635) | ||
Total gain (loss) on derivative contracts | $ 5,135 | $ 23,283 | (11,281) | 17,463 |
Crude Oil [Member] | Not Designated as Hedging Instrument [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Net gain (loss) on settlements | 4,252 | 9,399 | 15,467 | 23,863 |
Net gain (loss) on fair value adjustments | 699 | 13,758 | (26,904) | (6,787) |
Total gain (loss) on derivative contracts | 4,951 | 23,157 | (11,437) | 17,076 |
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Net gain (loss) on settlements | (161) | 390 | 357 | 1,235 |
Net gain (loss) on fair value adjustments | 345 | (264) | (201) | (848) |
Total gain (loss) on derivative contracts | $ 184 | $ 126 | $ 156 | $ 387 |
Derivative Instruments and He34
Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) MMBTU in Thousands | 1 Months Ended | 9 Months Ended |
Nov. 02, 2016$ / bblMBbls | Sep. 30, 2016MMBTU$ / MMBTU$ / bblMBbls | |
Swap Contracts (WTI) for Remainder of 2016 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Average swap price | 58.23 | |
Swap Contracts Combined with Short Puts (WTI, Enhanced Swaps) for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 30 | |
Swap Contracts Combined with Short Puts (WTI, Enhanced Swaps) for Full Year of 2017 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 730 | |
Strike price | 44.50 | |
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) For Remainder of 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) For Remainder of 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 65 | |
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) For Remainder of 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 55 | |
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) For Remainder of 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 40.33 | |
Collar Contracts (WTI, Two-Way Collars) for Remainder of 2016 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 184 | |
Collar Contracts (WTI, Two-Way Collars) for Remainder of 2016 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 46.50 | |
Collar Contracts (WTI, Two-Way Collars) for Remainder of 2016 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 37.50 | |
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 438 | |
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 1,095 | |
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Strike price | 59.05 | |
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 57.79 | |
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Strike price | 47.50 | |
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member] | ||
Derivative [Line Items] | ||
Strike price | 47.50 | |
Collar Contracts Combined with Short Puts (Henry Hub, Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Total volume | MMBTU | 1,460 | |
Collar Contracts Combined with Short Puts (Henry Hub, Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Average swap price | $ / MMBTU | 3.71 | |
Collar Contracts Combined with Short Puts (Henry Hub, Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Put Option [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Average swap price | $ / MMBTU | 3 | |
Collar Contracts Combined with Short Puts (Henry Hub, Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Put Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Average swap price | $ / MMBTU | 2.50 | |
Short Call Option Contracts for Full Year of 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 670 | |
Strike price | 50 | |
Swap Contracts (Midland Basis Differentials) for Remainder of 2016 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Total volume | MBbls | 368 | |
Average swap price | 0.17 | |
Swap Contracts (Henry Hub) for Remainder of 2016 [Member] | Natural Gas [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Total volume | MMBTU | 552 | |
Average swap price | $ / MMBTU | 2.52 |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) | 9 Months Ended |
Sep. 30, 2016item | |
Fair Value Measurements [Abstract] | |
Number of acquisitions completed | 4 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Derivative Assets | ||
Derivative Asset | $ 3,559 | $ 19,943 |
Derivative Liabilities | ||
Derivative Liabilities | (10,722) | |
Total net assets | (7,163) | 19,943 |
Level 2 [Member] | ||
Derivative Assets | ||
Derivative Asset | 3,559 | 19,943 |
Derivative Liabilities | ||
Derivative Liabilities | (10,722) | |
Total net assets | $ (7,163) | $ 19,943 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Income Taxes [Abstract] | |
Statutory income tax rate, percent | 35.00% |
Deferred tax assets, valuation allowance | $ 139,633 |
Cummulative loss incurred, period | 3 years |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Change in Asset Retirement Obligation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Asset retirement obligations at beginning of period | $ 5,107 | ||||
Accretion expense | $ 187 | $ 142 | 762 | $ 485 | |
Liabilities incurred | 12 | ||||
Liabilities settled | (807) | ||||
Revisions to estimate | 389 | ||||
Asset retirement obligations at end of period | 5,463 | $ 5,107 | $ 5,107 | ||
Less: current asset retirement obligations | (3,529) | (790) | |||
Long-term asset retirement obligations at the end of the period | 1,934 | 4,317 | |||
Restricted Investments | |||||
Restricted investments | $ 3,329 | $ 3,309 |
Equity Transactions (Narrative)
Equity Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | Sep. 06, 2016 | May 26, 2016 | Apr. 25, 2016 | Mar. 09, 2016 | Feb. 04, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 |
Class of Stock [Line Items] | ||||||||||
Preferred stock redemption, description | The Preferred Stock has no stated maturity and is not 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 in cash, plus any accrued and unpaid dividends to the redemption date. | |||||||||
Preferred stock dividend | $ 1,824 | $ 1,974 | $ 5,471 | $ 5,921 | ||||||
Proceeds from issuance of common stock | $ 722,715 | $ 65,546 | ||||||||
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 | $ 50 | |||||||
Preferred Stock, Dividend Rate, Per-Dollar-Amount, Per Annum | 5 | |||||||||
Preferred stock, redemption price per share | $ 50 | $ 50 | ||||||||
Preferred stock dividend | $ 1,824 | |||||||||
Preferred Stock, Shares Issued | 1,458,948 | 1,458,948 | ||||||||
Preferred stock, shares outstanding | 1,458,948 | 1,458,948 | 1,578,948 | |||||||
Value of a share of common stock | $ 15.70 | $ 15.70 | ||||||||
Conversion ratio of preferred stock to common stock | 3.2 | |||||||||
Conversion of stock, shares converted | 120,000 | |||||||||
Common Stock | ||||||||||
Class of Stock [Line Items] | ||||||||||
Shares of common stock issued in public offering | 29,900,000 | 25,300,000 | 15,250,000 | |||||||
Proceeds from issuance of common stock | $ 205,869 | $ 94,973 | ||||||||
Conversion of stock, shares issued | 719,000 | |||||||||
Common Stock | Assumed Offering Price [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Sales price of shares issued | $ 11.74 | |||||||||
Common Stock | Big Star Transaction [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Shares of common stock issued in acquisition | 9,333,333 | |||||||||
Common Stock | Plymouth Transaction [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Proceeds from issuance of common stock | $ 421,923 |
Other (Narrative) (Details)
Other (Narrative) (Details) $ / d in Thousands | 1 Months Ended | 9 Months Ended | |
Oct. 31, 2016$ / d | Jan. 31, 2016$ / d | Sep. 30, 2016contract | |
Operating Leases And Other Property Plant And Equipment [Line Items] | |||
Operating lease payable amount per day for placing rig on standby | 15 | ||
Horizontal Drilling Rig [Member] | |||
Operating Leases And Other Property Plant And Equipment [Line Items] | |||
Number of contracts | contract | 2 | ||
Extended contract expiration terms | The contract terms of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. | ||
Horizontal Drilling Rig [Member] | Subsequent Event [Member] | |||
Operating Leases And Other Property Plant And Equipment [Line Items] | |||
Rig rental payment rate per day | 16 | ||
Rig rental contract start date | January 2,017 | ||
Rig rental contract end date | June 2,017 |