Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Mar. 07, 2016 | Jun. 30, 2015 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Gastar Exploration Inc. | ||
Trading Symbol | GST | ||
Entity Central Index Key | 1,431,372 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 233.9 | ||
Entity Common Stock, Shares Outstanding | 81,837,275 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 50,074 | $ 11,008 |
Accounts receivable, net of allowance for doubtful accounts of $0, respectively | 14,302 | 30,841 |
Commodity derivative contracts | 15,534 | 19,687 |
Prepaid expenses | 5,056 | 2,083 |
Total current assets | 84,966 | 63,619 |
Oil and natural gas properties, full cost method of accounting: | ||
Unproved properties, excluded from amortization | 92,609 | 128,274 |
Proved properties | 1,286,373 | 1,124,367 |
Total natural gas and oil properties | 1,378,982 | 1,252,641 |
Furniture and equipment | 3,068 | 3,010 |
Total property, plant and equipment | 1,382,050 | 1,255,651 |
Accumulated depreciation, depletion and amortization | (1,053,116) | (563,351) |
Total property, plant and equipment, net | 328,934 | 692,300 |
OTHER ASSETS: | ||
Commodity derivative contracts | 9,335 | 7,815 |
Deferred charges, net | 2,358 | 2,586 |
Advances to operators and other assets | 331 | 9,474 |
Other | 4,944 | 0 |
Total other assets | 16,968 | 19,875 |
TOTAL ASSETS | 430,868 | 775,794 |
CURRENT LIABILITIES: | ||
Accounts payable | 2,029 | 28,843 |
Revenue payable | 5,985 | 9,122 |
Accrued interest | 3,730 | 3,528 |
Accrued drilling and operating costs | 2,010 | 5,977 |
Advances from non-operators | 167 | 1,820 |
Commodity derivative premium payable | 3,194 | 2,481 |
Asset retirement obligation | 89 | 82 |
Other accrued liabilities | 6,764 | 3,175 |
Total current liabilities | 23,968 | 55,028 |
LONG-TERM LIABILITIES: | ||
Long-term debt | 517,849 | 360,303 |
Commodity derivative contracts | 451 | 0 |
Commodity derivative premium payable | 2,788 | 4,702 |
Asset retirement obligation | 5,997 | 5,475 |
Total long-term liabilities | $ 527,085 | $ 370,480 |
Commitments and contingencies (Note 14) | ||
STOCKHOLDERS' EQUITY: | ||
Common stock | $ 80 | $ 78 |
Additional paid-in capital | 571,947 | 568,440 |
Accumulated deficit | (692,274) | (218,294) |
Total stockholders' equity | (120,185) | 350,286 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | 430,868 | 775,794 |
Series A Preferred Stock | ||
STOCKHOLDERS' EQUITY: | ||
Preferred stock | 41 | 41 |
Series B Preferred Stock | ||
STOCKHOLDERS' EQUITY: | ||
Preferred stock | $ 21 | $ 21 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts receivable, net of allowance for doubtful accounts | $ 0 | $ 0 |
Preferred stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 275,000,000 | 275,000,000 |
Common stock, shares issued | 80,024,218 | 78,632,810 |
Common stock, shares outstanding | 80,024,218 | 78,632,810 |
Series A Preferred Stock | ||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares issued | 4,045,000 | 4,045,000 |
Preferred stock, shares outstanding | 4,045,000 | 4,045,000 |
Liquidation Preference | $ 25 | $ 25 |
Series B Preferred Stock | ||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares issued | 2,140,000 | 2,140,000 |
Preferred stock, shares outstanding | 2,140,000 | 2,140,000 |
Liquidation Preference | $ 25 | $ 25 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
REVENUES: | |||
Oil and condensate | $ 58,668 | $ 82,820 | $ 36,480 |
Natural gas | 16,901 | 47,647 | 40,416 |
NGLs | 7,136 | 21,382 | 15,611 |
Total oil and condensate, natural gas and NGLs revenues | 82,705 | 151,849 | 92,507 |
Gain (loss) on commodity derivatives contracts | 24,589 | 19,569 | (4,752) |
Total revenues | 107,294 | 171,418 | 87,755 |
EXPENSES: | |||
Production taxes | 2,877 | 6,733 | 4,651 |
Lease operating expenses | 23,728 | 19,323 | 9,456 |
Transportation, treating and gathering | 2,187 | 3,679 | 4,006 |
Depreciation, depletion and amortization | 62,887 | 46,180 | 32,449 |
Impairment of natural gas and oil properties | 426,878 | 0 | 0 |
Accretion of asset retirement obligation | 502 | 506 | 468 |
General and administrative expense | 17,069 | 16,485 | 16,961 |
Litigation settlement expense | 0 | 0 | 1,000 |
Total expenses | 536,128 | 92,906 | 68,991 |
INCOME (LOSS) FROM OPERATIONS | (428,834) | 78,512 | 18,764 |
OTHER INCOME (EXPENSE): | |||
Gain on acquisition of assets at fair value, net of income taxes | 0 | 0 | 27,670 |
Interest expense | (30,686) | (27,571) | (13,168) |
Investment and other income | 13 | 19 | 48 |
Foreign transaction loss | 0 | (7) | (14) |
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES | (459,507) | 50,953 | 33,300 |
Income tax benefit | 0 | 0 | (16,042) |
NET INCOME (LOSS) | (459,507) | 50,953 | 49,342 |
Dividends on preferred stock | (14,473) | (14,424) | (9,378) |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ (473,980) | $ 36,529 | $ 39,964 |
NET INCOME (LOSS) PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS: | |||
Basic (in dollars per share) | $ (6.11) | $ 0.58 | $ 0.66 |
Diluted (in dollars per share) | $ (6.11) | $ 0.55 | $ 0.63 |
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | |||
Basic (shares) | 77,511,677 | 63,270,733 | 60,220,115 |
Diluted (shares) | 77,511,677 | 66,492,589 | 63,618,401 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity (Deficit) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Series A Preferred StockPreferred Stock | Series B Preferred StockPreferred Stock |
Balance at beginning of period at Dec. 31, 2012 | $ 126,536 | $ 316,346 | $ 104,937 | $ (294,787) | $ 40 | $ 0 |
Balance at beginning of period (in shares) at Dec. 31, 2012 | 66,432,609 | 3,951,254 | 0 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of preferred stock | 50,181 | 50,160 | $ 21 | |||
Issuance of preferred stock (shares) | 6,906 | 2,140,000 | ||||
Repurchase of shares of common stock | (9,753) | $ (9,753) | ||||
Repurchase of common stock (shares) | (6,781,768) | |||||
Reclassification of par value of common stock | $ (306,532) | 306,532 | ||||
Issuance of restricted stock | 0 | |||||
Issuance of restricted stock (shares) | 2,288,179 | |||||
Forfeitures of restricted stock | (334) | (334) | ||||
Forfeitures of restricted stock (shares) | (737,362) | |||||
Exercise of stock options, net of forfeitures (shares) | 10,000 | |||||
Stock based compensation | 3,435 | 3,435 | ||||
Preferred stock dividends | (9,378) | (9,378) | ||||
Net income (loss) | 49,342 | 49,342 | ||||
Balance at end of period at Dec. 31, 2013 | 210,029 | $ 61 | 464,730 | (254,823) | $ 40 | $ 21 |
Balance at end of period (in shares) at Dec. 31, 2013 | 61,211,658 | 3,958,160 | 2,140,000 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of preferred stock | 2,066 | 2,065 | $ 1 | |||
Issuance of preferred stock (shares) | 86,840 | |||||
Issuance of shares - cash, net of offering costs | 101,319 | $ 17 | 101,302 | |||
Issuance of shares - cash, net of offering costs (shares) | 17,000,000 | |||||
Issuance of shares - performance based units vesting, net of forfeitures (shares) | 472,189 | |||||
Issuance of restricted stock | 0 | |||||
Issuance of restricted stock (shares) | 601,473 | |||||
Forfeitures of restricted stock | (4,562) | (4,562) | ||||
Forfeitures of restricted stock (shares) | (659,227) | |||||
Exercise of stock options, net of forfeitures | $ 15 | 15 | ||||
Exercise of stock options, net of forfeitures (shares) | 7,500 | 6,717 | ||||
Stock based compensation | $ 4,890 | 4,890 | ||||
Preferred stock dividends | (14,424) | (14,424) | ||||
Net income (loss) | 50,953 | 50,953 | ||||
Balance at end of period at Dec. 31, 2014 | $ 350,286 | $ 78 | 568,440 | (218,294) | $ 41 | $ 21 |
Balance at end of period (in shares) at Dec. 31, 2014 | 78,632,810 | 4,045,000 | 2,140,000 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of shares - cash, net of offering costs (shares) | 0 | |||||
Issuance of shares - performance based units vesting, net of forfeitures | $ 1 | (1) | ||||
Issuance of shares - performance based units vesting, net of forfeitures (shares) | 497,636 | |||||
Issuance of restricted stock | $ 0 | $ 1 | (1) | |||
Issuance of restricted stock (shares) | 1,426,604 | |||||
Forfeitures of restricted stock | (1,472) | (1,472) | ||||
Forfeitures of restricted stock (shares) | (532,832) | |||||
Stock based compensation | 4,981 | 4,981 | ||||
Preferred stock dividends | (14,473) | (14,473) | ||||
Net income (loss) | (459,507) | (459,507) | ||||
Balance at end of period at Dec. 31, 2015 | $ (120,185) | $ 80 | $ 571,947 | $ (692,274) | $ 41 | $ 21 |
Balance at end of period (in shares) at Dec. 31, 2015 | 80,024,218 | 4,045,000 | 2,140,000 |
Consolidated Statement of Stoc6
Consolidated Statement of Stockholders' Equity (Deficit) (Parenthetical) $ in Thousands | 12 Months Ended |
Dec. 31, 2014USD ($) | |
Statement Of Stockholders Equity [Abstract] | |
Issuance of shares- cash, offering costs | $ 4,931 |
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) | $ (459,507) | $ 50,953 | $ 49,342 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Depreciation, depletion and amortization | 62,887 | 46,180 | 32,449 | |
Impairment of natural gas and oil properties | 426,878 | 0 | 0 | |
Stock-based compensation | 4,981 | 4,890 | 3,435 | |
Total (gain) loss on commodity derivatives contracts | (24,589) | (19,569) | 4,752 | |
Cash settlements of matured commodity derivative contracts, net | 24,910 | (4,901) | 5,892 | |
Cash premiums paid for commodity derivatives contracts | (45) | (185) | (152) | |
Amortization of deferred financing costs | [1],[2] | 3,584 | 3,067 | 2,322 |
Accretion of asset retirement obligation | 502 | 506 | 468 | |
Settlement of asset retirement obligation | (83) | (588) | (66) | |
Gain on acquisition of assets at fair value | 0 | 0 | (27,670) | |
Deferred tax benefit | 0 | 0 | (16,042) | |
Changes in operating assets and liabilities: | ||||
Accounts receivable | 19,333 | (12,524) | (8,431) | |
Prepaid expenses | (2,973) | (938) | (48) | |
Accounts payable and accrued liabilities | (4,606) | (2,566) | 1,563 | |
Net cash provided by operating activities | 51,272 | 64,325 | 47,814 | |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||
Development and purchase of oil and natural gas properties | (148,182) | (155,631) | (95,343) | |
Advances to operators | (2,302) | (61,067) | (22,213) | |
Acquisition of oil and natural gas properties - refund (expenditure) | (45,575) | 4,209 | (251,096) | |
Proceeds from sale of oil and natural gas properties | 47,314 | 5,530 | 112,201 | |
Use of proceeds from non-operators | (1,653) | (7,439) | (8,281) | |
Purchase of furniture and equipment | (58) | (319) | (766) | |
Net cash used in investing activities | (150,456) | (214,717) | (265,498) | |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||
Proceeds from issuance of common shares, net of issuance costs | 0 | 101,319 | 0 | |
Repurchase of common stock | 0 | 0 | (9,753) | |
Proceeds from revolving credit facility | 196,000 | 103,000 | 19,000 | |
Repayment of revolving credit facility | (41,000) | (58,000) | (117,000) | |
Proceeds from issuance of senior secured notes, net of discount | 0 | 0 | 312,279 | |
Proceeds from issuance of preferred stock, net of issuance costs | 0 | 2,064 | 50,183 | |
Dividends on preferred stock | (14,473) | (14,424) | (9,378) | |
Deferred financing charges | (805) | (405) | (3,785) | |
Tax withholding related to restricted stock and PBU vestings | (1,472) | (4,562) | (334) | |
Other | 0 | 15 | (36) | |
Net cash provided by financing activities | 138,250 | 129,007 | 241,176 | |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 39,066 | (21,385) | 23,492 | |
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 11,008 | 32,393 | 8,901 | |
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ 50,074 | $ 11,008 | $ 32,393 | |
[1] | The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.” | |||
[2] | The years ended December 31, 2015, 2014 and 2013 include $2.5 million, $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes. |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2015 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Description of Business | 1. Gastar Exploration Inc. (“Gastar” or the “Company”) is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Gastar’s principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar has developed the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and is drilling other prospective formations on the same acreage, primarily the Meramec Shale (Middle Mississippi Lime), while Gastar plans to also test the Woodford Shale, along with emerging prospective plays in the shallow Oswego formation and in the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec. These formations comprise what is commonly referred to as the STACK Play. In West Virginia, Gastar has developed liquids-rich natural gas in the Marcellus Shale and has drilled and completed two successful dry gas Utica Shale/Point Pleasant well on its acreage. On February 19, 2016, the Company entered into an agreement to sell substantially all of its assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign (the “Appalachian Basin Sale”). The transaction is expected to close on or before March 31, 2016, with an effective date of January 1, 2016 and will be considered a significant disposition, thus resulting in changes to the Company’s financial position, statement of operations and cash flows. On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” At December 31, 2013, Gastar Exploration, Inc. was a holding company and substantially all of its operations were conducted through, and substantially all of its assets were held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Subsequently, on January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc. as part of a reorganization to eliminate the holding company corporate structure. Pursuant to the merger agreement, shares of Gastar Exploration, Inc.'s common stock were converted into an equal number of shares of common stock of Gastar Exploration USA, Inc. and Gastar Exploration USA, Inc. changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc., together with its subsidiary, owns and continues to conduct business in substantially the same manner as was being conducted by Gastar Exploration, Inc. and its subsidiaries prior to the merger. All references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration Inc. and its subsidiary. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) and its wholly-owned subsidiaries, all references to “Parent” refer solely to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.). |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies Basis of Presentation The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with U.S. GAAP. The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 18. “Supplemental Oil and Gas Disclosures.” All 2013 statement of operations, statement of stockholders’ equity and statement of cash flows balances are those of Gastar Exploration, Inc. Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. On January 29, 2016, the Company, together with the parties thereto, entered into Limited Waiver and Amendment No. 7 to Second Amended and Restated Credit Agreement (“Amendment No. 7”). Pursuant to Amendment No. 7, the Company obtained (i) a waiver until March 10, 2016 of any potential defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility and (ii) a permanent waiver of any defaults of the restricted payment covenant under the Revolving Credit Facility resulting from (a) cash distributions paid on December 31, 2015 in respect of its Series A Preferred Stock and its Series B Preferred Stock and (b) the issuance on January 28, 2016, as a dividend on the Company’ common stock, of the right to purchase Series C Junior Participating Preferred Stock pursuant to the Company’s Rights Agreement dated as of January 18, 2016 as part of the Company’s previously disclosed tax benefits preservation plan. The Revolving Credit Facility was also amended to permit the Company to make dividends and distributions of preferred equity interests or rights to purchase certain preferred equity interests. The entry into Amendment No. 7 permitted the Company to pay monthly cash dividends on its Series A Preferred Stock and its Series B Preferred Stock on February 1, 2016. On February 19, 2016, the Company entered into an agreement to sell substantially all of its assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign. The transaction is expected to close on or before March 31, 2016, with an effective date of January 1, 2016. On March 9, 2016, the Company, together with the parties thereto, entered into Waiver and Amendment No. 8 to Second Amended and Restated Credit Agreement (“Amendment No. 8”). Pursuant to Amendment No. 8, the Company obtained the following relief with respect to its financial covenant compliance: (i) a permanent waiver of the defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility; (ii) relief from compliance with its leverage ratio through the fiscal quarter ending March 31, 2017, but the Company must maintain a maximum leverage ratio of not greater than 4.0 to 1.0 for each fiscal quarter ending on or after June 30, 2017; (iii) an adjustment to the interest coverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 1.10 to 1.00 and for each fiscal quarter ending on or after June 30, 2017 to 2.50 to 1.00; and (iv) an adjustment to its senior secured leverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 2.50 to 1.00 provided that during such period the Company may subtract all cash on hand in calculating the senior secured leverage ratio for such periods and for each fiscal quarter ending on or after June 30, 2017, to 2.00 to 1.00 provided that during such period the Company may only subtract up to $5 million of cash on hand in calculating the senior secured leverage ratio for such periods. As consideration for the financial covenant relief provided for in Amendment No. 8, the Revolving Credit Facility was also amended to, among other things: (i) set the interest margin at (a) 4.0% per annum for Eurodollar rate borrowings and (b) 3.0% per annum for borrowings based on the reference rate; (ii) reduce the borrowing base from $200.0 million to $180.0 million until the earlier of the closing of the Appalachian Basin Sale or April 10, 2016, at which point the borrowing base will automatically be reduced to $100.0 million and require borrowings in excess of such amount to be immediately repaid; (iii) require additional automatic reductions of the borrowing base in connection with asset sales in excess of $5.0 million or the termination of any hedge agreements governing hedges with a settlement date on or after July 1, 2016; (iv) provide for an additional interim borrowing base redetermination in August 2016; (v) require the consent of the lenders to any asset sales in excess of $5.0 million; and (vi) restrict the Company after March 2016 from making any distributions or paying any cash dividends to the holders of its preferred equity, including its outstanding shares of Series A and Series B Preferred Stock. Principles of Consolidation The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation. Use of estimates in Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with U.S. 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 revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties. Cash and Cash Equivalents The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $50.1 million and $11.0 million as of December 31, 2015 and 2014, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss. Accounts Receivable Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. The Company believes that all current year accounts receivables are deemed collectible and thus, no allowance for doubtful accounts deemed necessary. A summary of the activity related to the allowance for doubtful accounts is as follows: For the years ended December 31, 2015 2014 2013 (in thousands) Allowance for doubtful accounts, beginning of year $ — $ 507 $ 546 Expense — — — Reductions/write-offs — (507 ) (39 ) Allowance for doubtful accounts, end of year $ — $ — $ 507 Oil and Natural Gas Properties The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations. In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization. The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2015 and 2014 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered. The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted. Asset Retirement Obligation Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations. Furniture and Equipment Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years. Capitalized Interest The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The Notes and Revolving Credit Facility were included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2015. Currently, the Company only capitalizes interest on the Notes. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $3.9 million, $4.3 million and $3.3 million for 2015, 2014 and 2013, respectively. Fair Value of Financial Instruments The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value. Deferred Financing Costs Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense. Deferred financing costs will be presented as a direct reduction to the carrying amount of the related debt liability beginning in 2016. The following table indicates deferred charges and related accumulated amortization as of the dates indicated: As of December 31, 2015 2014 Deferred charges $ 4,474 $ 3,664 Accumulated amortization (2,116 ) (1,078 ) Deferred charges, net $ 2,358 $ 2,586 Derivative Instruments and Hedging Activity The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.” The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in gain (loss) on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in gain (loss) on commodity derivatives contracts in the Company’s consolidated statement of operations. Stock-Based Compensation The Company reports compensation expense for restricted common stock, performance based units (“PBUs”) and stock options granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. Stock-based compensation cost for restricted shares is estimated at the grant date based on the award's fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award's fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. Forfeitures of unvested stock options and restricted common shares are calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. For 2015, 2014 and 2013, the Company used forfeiture rates in determining compensation expense of 17.5%, 25.5% and 14.0%, respectively. Treasury Stock Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase. Revenue Recognition The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company's NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company's wet gas production. The Company's reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2015, 2014 and 2013. The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production. The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet. Deferred Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time. Comprehensive Income Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income attributable to common stockholders as presented in the consolidated statements of operations equals comprehensive income. Earnings or Loss per Share Basic earnings or loss per share is computed on the basis of the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of unvested restricted shares and PBUs. Co-participation Operations The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities. Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S. Foreign Currency Exchange The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction. All of the Company’s operations are conducted in U.S. dollars. The Company owns immaterial non-operating working interests in two natural gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012. Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations. Recent Accounting Developments The following recently issued accounting pronouncements have been adopted or may impact us in future periods: Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards (IFRS). IAS 1, . This guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period and can be applied either prospectively or retrospectively to all periods presented. The Company does not expect the adoption of this guidance to materially impact its consolidated financial statements. Business Combinations. In September 2015, the FASB issued updated guidance as part of its simplification initiative that requires that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, depletion and amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The update is effective for public business entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements, other than balance sheet reclassification. Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property Plant And Equipment [Abstract] | |
Property, Plant and Equipment | 3. Property, Plant and Equipment The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of Oklahoma, Pennsylvania and West Virginia. The Company's total property, plant and equipment consists of the following: December 31, 2015 2014 (in thousands) Oil and natural gas properties, full cost method of accounting: Unproved properties $ 92,609 $ 128,274 Proved properties 1,286,373 1,124,367 Total oil and natural gas properties 1,378,982 1,252,641 Furniture and equipment 3,068 3,010 Total property and equipment 1,382,050 1,255,651 Impairment of proved natural gas and oil properties (764,817 ) (337,939 ) Accumulated depreciation, depletion and amortization (288,299 ) (225,412 ) Total accumulated depreciation, depletion and amortization (1,053,116 ) (563,351 ) Total property and equipment, net $ 328,934 $ 692,300 Included in the Company's oil and natural gas properties are asset retirement costs of $2.4 million as of December 31, 2015 and 2014, respectively. The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: December 31, 2015 2014 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 1,533 $ 29,193 Acreage acquisition costs 82,560 91,362 Capitalized interest 8,516 7,719 Total unproved properties excluded from amortization $ 92,609 $ 128,274 For the years ended December 31, 2015 and 2014, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in the Appalachian Basin, the Company reclassified $14.4 million of unproved properties to proved properties for the year ended December 31, 2015. For the year ended December 31, 2014, the Company reclassified $3.3 million of Marcellus East unproved properties to proved properties. The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company’s capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense for such period. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation is determined using a mandatory trailing 12-month unweighted arithmetic average of the first-day-of-the-month commodities pricing and costs in effect at the end of the period, each of which are held constant indefinitely (absent specific contracts with respect to future prices and costs) with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month commodities prices are adjusted for basis and quality differentials in determining the present value of the proved reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials: 2015 Total December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.59 $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 50.28 $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 426,878 $ 144,760 $ 181,966 $ 100,152 $ — 2014 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 4.35 $ 4.24 $ 4.10 $ 3.99 West Texas Intermediate oil price (per Bbl) (1) $ 94.99 $ 99.08 $ 100.11 $ 98.30 Impairment recorded (pre-tax) (in thousands) $ — $ — $ — $ — $ — 2013 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 3.67 $ 3.61 $ 3.44 $ 2.95 West Texas Intermediate oil price (per Bbl) (1) $ 96.78 $ 91.69 $ 88.13 $ 89.17 Impairment recorded (pre-tax) (in thousands) $ — $ — $ — $ — $ — (1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices. The Company could potentially incur further ceiling test impairments in 2016 assuming commodities prices do not increase. While it is difficult to project future impairment charges in light of numerous variables involved, the following analysis using basic assumptions is provided to illustrate the impact of lower commodities pricing on impairment charges and proved reserves volumes. The benchmark 12-month average price applicable to first quarter 2016 proved reserves under SEC rules decreased to $46.26 per barrel for crude oil and $2.40 per Mcf for natural gas. The Company’s estimated proved reserve volumes were 55.9 MMBoe at December 31, 2015 using the SEC-mandated historical twelve-month unweighted average pricing at such date. If such reserves estimates were made using the further reduced twelve-month average benchmark prices forecast for first quarter 2016 as described in the foregoing paragraph and without regard to cost savings, reserve additions or other further revisions to reserves other than as a result of such pricing changes, the Company’s internally estimated proved reserves as of December 31, 2015, excluding the impact of recent sales, would decrease primarily as a result of the loss of proved undeveloped locations and tail-end volumes which would not be economically producible at such lower prices. The Company’s proved reserves estimates and their estimated discounted value and standardized measure will also be impacted by changes in lease operating costs, future development costs, production, exploration and development activities. Appalachian Basin Sale On February 19, 2016, the Company entered into an agreement to sell substantially all of its assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign. The transaction is expected to close on or before March 31, 2016, with an effective date of January 1, 2016. Husky Acquisition On October 14, 2015, the Company entered into a definitive purchase and sale agreement to acquire additional working and net revenue interests in 103 gross (10.2 net) producing wells and certain undeveloped acreage in the STACK Play and Hunton Limestone formations in its existing AMI from its AMI co-participant Husky Ventures, Inc. (“Husky”), Silverstar of Nevada, Inc., Maximus Exploration, LLC and Atwood Acquisitions, LLC for approximately $43.3 million, which includes a $4.3 million deposit into escrow pending the resolution of title defects by the seller and the purchase of overrides recorded in other assets at December 31, 2015, and the conveyance of approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers, subject to certain adjustments and customary closing conditions (the “Husky Acquisition”). The transaction closed on December 16, 2015 with an effective date of July 1, 2015. In connection with the acquisition, the AMI participation agreements with the Company’s AMI co-participant were dissolved. Pursuant to the purchase and sale agreement, as amended, on December 16, 2015, the Company completed the Husky Acquisition for an adjusted purchase price of $42.1 million. Upon completion of the initial purchase price allocation, as of December 16, 2015, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $1.1 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Husky Acquisition assets resulted in a fair market valuation of $44.6 million. As the fair market valuation varied less than 6% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation. The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Husky Acquisition (in thousands): Consideration: Cash consideration $ 42,085 Conveyance of undeveloped acreage — Total purchase price $ 42,085 Estimated Fair Value of Assets Acquired: Unproved properties $ 27,875 Proved properties 15,592 Other (1,382 ) Total assets acquired $ 42,085 Husky Acquisition Unaudited Pro Forma Operating Results The following unaudited pro forma results for the years ended December 31, 2015 and 2014 show the effect on the Company's consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Years Ended December 31, 2015 2014 (in thousands, except (Unaudited) Revenues $ 115,147 $ 186,591 Net (Loss) Income $ (470,874 ) $ 46,370 (Loss) Income per share: Basic $ (6.07 ) $ 0.73 Diluted $ (6.07 ) $ 0.70 The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Husky Acquisition occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information. The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Husky Acquisition are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes. For the Year Ended December 31, 2015 (in thousands) Revenues $ 132 Excess of revenues over direct operating expenses $ 130 Mid-Continent Divestiture On July 6, 2015, the Company sold certain non-core assets comprised of 38 gross (16.7 net) producing wells and approximately 29,500 gross (19,200 net) acres in Kingfisher County, Oklahoma for an adjusted purchase price of $46.5 million. The sale is reflected as a reduction to the full cost pool and the Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool. Chesapeake Acquisition On March 28, 2013, Gastar USA entered into a Purchase and Sale Agreement by and among the Chesapeake Parties and Gastar USA (the “Chesapeake Purchase Agreement”). Pursuant to the Chesapeake Purchase Agreement, Gastar USA was to acquire approximately 157,000 net acres of Oklahoma oil and gas leasehold interests from the Chesapeake Parties, including production from interests in 206 producing wells located in Oklahoma (the “Chesapeake Assets”). The Chesapeake Purchase Agreement contained customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the Chesapeake Purchase Agreement. On June 7, 2013, the parties to the Chesapeake Purchase Agreement entered into an Amendment to Purchase and Sale Agreement, dated June 7, 2013, in order to revise the description of the properties to be acquired and to evidence the withdrawal of Arcadia Resources, L.P. and Jamestown Resources, L.L.C. from the Chesapeake Purchase Agreement. Pursuant to the Chesapeake Purchase Agreement, as amended, on June 7, 2013, Gastar USA completed the acquisition of the Chesapeake Assets for a final adjusted purchase price of $69.4 million. Upon completion of the initial purchase price allocation, as of June 7, 2013, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $2.1 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Chesapeake Assets resulted in a fair market valuation of $113.1 million. With the completion of the asset valuation during the fourth quarter of 2013, the Company recorded the deferred tax attributes associated with the transaction. As a result of incorporating the final valuation information into the purchase price allocation, a bargain purchase gain of $27.7 million, net of $16.0 million of income tax expense, was recognized in the accompanying consolidated statements of operations for the year ended December 31, 2013. The bargain purchase gain was primarily attributable to the non-strategic nature of the divestiture to the seller, coupled with favorable economic trends in the industry and the geographic region in which the Chesapeake Assets are located. The Company believes the estimates used in the fair market valuation and purchase price allocation are reasonable and that the significant effects of the acquisition are properly reflected. The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Chesapeake acquisition (in thousands): Consideration: Cash consideration $ 69,371 Fair Value of Liabilities Assumed: Deferred tax liability 16,042 Total purchase price plus liabilities assumed $ 85,413 Estimated Fair Value of Assets Acquired: Unproved properties $ 86,327 Proved properties 26,756 Total assets acquired $ 113,083 Bargain purchase gain $ 27,670 Hunton Joint Venture AMI Election Effective July 1, 2013, Gastar USA's working interest partner in its original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that Gastar USA acquired pursuant to the Chesapeake Purchase Agreement for a total payment of $11.8 million, of which $133,000 was deemed to be a reimbursement of transaction and integration costs associated with the acquisition and was recorded as a reduction of general and administrative expense. Hunton Divestiture On July 2, 2013, Gastar USA entered into a purchase and sale agreement with Newfield, dated July 2, 2013, pursuant to which Newfield acquired approximately 76,000 net undeveloped acres of oil and gas leasehold interests in Kingfisher and Canadian Counties, Oklahoma from Gastar USA and Gastar USA acquired approximately 1,850 net acres of Oklahoma oil and gas leasehold interests from Newfield. The transaction closed on August 6, 2013 for a net cash purchase price of approximately $57.0 million, adjusted for an acquisition effective date of May 1, 2013. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool. WEHLU Acquisition On September 4, 2013, Gastar USA entered into a Purchase and Sale Agreement, dated September 4, 2013, by and among the Lime Rock Parties and Gastar USA (the “WEHLU Purchase Agreement”). Pursuant to the WEHLU Purchase Agreement, Gastar USA acquired a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of the West Edmond Hunton Lime Unit (“WEHLU”) located in Kingfisher, Logan and Oklahoma Counties, Oklahoma, all of which is held by production (“WEHLU Assets”). Pursuant to the WEHLU Purchase Agreement, Gastar USA completed the acquisition of the WEHLU Assets on November 15, 2013 for an adjusted cash purchase price of $177.8 million, (the “WEHLU Acquisition”). The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $286,000 of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the WEHLU Assets resulted in a fair market valuation of $176.8 million. As the fair market valuation varied less than 1% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation. The following table summarizes the estimated fair value of the assets acquired in connection with the WEHLU Acquisition (in thousands): Consideration: Cash consideration $ 177,778 Estimated Fair Value of Assets Acquired: Unproved properties $ 13,026 Proved properties 164,752 Total assets acquired $ 177,778 Chesapeake and WEHLU Acquisition Unaudited Pro Forma Operating Results The following unaudited pro forma results for the year ended December 31, 2013 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For (in (Unaudited) Revenues $ 132,721 Net Loss $ (4,836 ) Loss per share: Basic $ (0.08 ) Diluted $ (0.08 ) The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Chesapeake and WEHLU Acquisitions occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information. The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Chesapeake and WEHLU Acquisitions are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes. Year Ended December 31, (in thousands) Revenues $ 11,292 Excess of revenues over direct operating expenses $ 7,591 Hilltop Area, East Texas Sale On April 19, 2013, Gastar Exploration Texas, LP (“Gastar Texas”) and Gastar USA entered into a Purchase and Sale Agreement by and among Gastar Texas, Gastar USA and Cubic Energy, Inc. (“Cubic Energy”) (the “East Texas Sale Agreement”). Pursuant to the East Texas Sale Agreement, as amended, on October 2, 2013, Cubic Energy acquired from Gastar Texas approximately 31,800 gross (16,300 net) acres of leasehold interests in the Hilltop area of East Texas in Leon and Robertson Counties, Texas, including production from interests in producing wells, for adjusted net proceeds of approximately $42.9 million. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool. Atinum Participation Agreement In September 2010, the Company entered into a participation agreement (the “Atinum Participation Agreement”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum”), a Korean investment firm. Pursuant to which the Company ultimately assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum” and, together with the Company, the “Atinum co-participants”), for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, the Company acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay the Company on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. The Atinum co-participants pursued an initial three-year development program that called for the drilling of a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, the Atinum co-participants agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells. At December 31, 2015, 74 gross operated horizontal Marcellus Shale wells and two gross operated horizontal Utica Shale wells were capable of production under the Atinum Participation Agreement. The Atinum Participation agreement expired on November 1, 2015. On February 19, 2016, the Company entered into an agreement to sell substantially all of its assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign. The transaction is expected to close on or before March 31, 2016, with an effective date of January 1, 2016. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 4. Long-Term Debt Second Amended and Restated Revolving Credit Facility On June 7, 2013, the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). At the Company's election, borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent (ii) the federal funds rate plus 50 basis points or (iii) LIBOR plus 1.0%. The applicable interest rate margin in the case of borrowings based on the reference rate is 3.0% and in the case of borrowings based on the Eurodollar rate is 4.0%. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity of November 14, 2017. The Revolving Credit Facility will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by the Company and its subsidiaries, excluding de minimis value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of the Company. The Revolving Credit Facility contains various covenants, including among others: · Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments; · Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted; · Maintenance of a maximum ratio of indebtedness to EBITDA of not greater than 4.0 to 1.0, subject to the modifications in Amendment No. 5 and Amendment No. 8 set forth below; and · Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0, subject to the modifications in Amendment No. 5 and Amendment No. 8 set forth below. All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others: · Failure to make payments; · Non-performance of covenants and obligations continuing beyond any applicable grace period; and · The occurrence of a change in control of the Company, as defined in the Revolving Credit Facility. On March 9, 2015, the Company, together with the parties thereto, entered into a Master Assignment, Agreement and Amendment No. 5 (“Amendment No. 5”) to Second Amended and Restated Credit Agreement. Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million, (ii) adjust the leverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016, to 5.25 to 1.00; for the fiscal quarter ending on September 30, 2016, to 5.00 to 1.00; for the fiscal quarter ending on December 31, 2016, to 4.75 to 1.00; for the fiscal quarter ending on March 31, 2017, to 4.25 to 1.00; and for each fiscal quarter ending on or after June 30, 2017, to 4.00 to 1.00, (iii) adjust the interest coverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016, to 2.00 to 1.00 and for each fiscal quarter ending on or after March 31, 2016, to 2.50 to 1.00, and (iv) add the senior secured leverage ratio covenant, such ratio not to exceed, (a) for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016, 2.25 to 1.00 and (b) for each fiscal quarter ending on or after June 30, 2016, 2.00 to 1.00 provided that this senior secured leverage ratio shall cease to apply commencing with the first fiscal quarter end occurring after June 30, 2016 for which the total leverage ratio is equal to or less than 4.00 to 1.00. On December 22, 2015, the Company, together with the parties thereto, entered into Amendment No. 6 to Second Amended and Restated Credit Agreement (“Amendment No. 6”). Amendment No. 6 amended the Revolving Credit Facility to permit the Company to exchange its outstanding Notes constituting Second Lien Debt under the Revolving Credit Facility for equity interests in the Company. On January 29, 2016, the Company, together with the parties thereto, entered into Limited Waiver and Amendment No. 7 to Second Amended and Restated Credit Agreement (“Amendment No. 7”). Pursuant to Amendment No. 7, the Company obtained (i) a waiver until March 10, 2016 of any potential defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility and (ii) a permanent waiver of any defaults of the restricted payment covenant under the Revolving Credit Facility resulting from (a) cash distributions paid on December 31, 2015 in respect of its Series A Preferred Stock and its Series B Preferred Stock and (b) the issuance on January 28, 2016, as a dividend on the Company’ common stock, of the right to purchase Series C Junior Participating Preferred Stock pursuant to the Company’s Rights Agreement dated as of January 18, 2016 as part of the Company’s previously disclosed tax benefits preservation plan. The Revolving Credit Facility was also amended to permit the Company to make dividends and distributions of preferred equity interests or rights to purchase certain preferred equity interests. The entry into Amendment No. 7 permitted the Company to pay monthly cash dividends on its Series A Preferred Stock and its Series B Preferred Stock on February 1, 2016. On March 9, 2016, the Company, together with the parties thereto, entered into Waiver and Amendment No. 8 to Second Amended and Restated Credit Agreement (“Amendment No. 8”). Pursuant to Amendment No. 8, the Company obtained the following relief with respect to its financial covenant compliance: (i) a permanent waiver of the defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility; (ii) relief from compliance with its leverage ratio through the fiscal quarter ending March 31, 2017, but the Company must maintain a maximum leverage ratio of not greater than 4.0 to 1.0 for each fiscal quarter ending on or after June 30, 2017; (iii) an adjustment to the interest coverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 1.10 to 1.00 and for each fiscal quarter ending on or after June 30, 2017 to 2.50 to 1.00; and (iv) an adjustment to an adjustment to its senior secured leverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 2.50 to 1.00 provided that during such period the Company may subtract all cash on hand in calculating the senior secured leverage ratio for such periods and for each fiscal quarter ending on or after June 30, 2017, to 2.00 to 1.00 provided that during such period the Company may only subtract up to $5 million of cash on hand in calculating the senior secured leverage ratio for such periods. As consideration for the financial covenant relief provided for in Amendment No. 8, the Revolving Credit Facility was also amended to, among other things: (i) set the interest margin at (a) 4.0% per annum for Eurodollar rate borrowings and (b) 3.0% per annum for borrowings based on the reference rate; (ii) reduce the borrowing base from $200.0 million to $180.0 million until the earlier of the closing of the Appalachian Basin Sale or April 10, 2016, at which point the borrowing base will automatically be reduced to $100.0 million and require borrowings in excess of such amount to be immediately repaid; (iii) require additional automatic reductions of the borrowing base in connection with asset sales in excess of $5.0 million or the termination of any hedge agreements governing hedges with a settlement date on or after July 1, 2016; (iv) provide for an additional interim borrowing base redetermination in August 2016; (v) require the consent of the lenders to any asset sales in excess of $5.0 million; and (vi) restrict the Company after March 2016 from making any distributions or paying any cash dividends to the holders of its preferred equity, including its outstanding shares of Series A and Series B Preferred Stock. Borrowing base re-determinations are scheduled semi-annually in May and November of each calendar year, although an additional scheduled redetermination will occur in August 2016, as set forth in Amendment No. 8. The Company and its lenders may each request one additional unscheduled re-determination during any six-month period between scheduled re-determinations. At December 31, 2015, the Revolving Credit Facility had a borrowing base of $200.0 million, with $200.0 million of borrowings outstanding. In connection with Amendment No. 8, the borrowing base was reduced from $200.0 million to $180.0 million, and will be further reduced to $100.0 million on the earlier of the closing of the Appalachian Basin Sale or April 10, 2016 and require borrowings in excess of such amount to be immediately repaid. Future increases in the borrowing base in excess of the original $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the Notes agreement (as discussed below in “Senior Secured Notes”). At December 31, 2015, the Company was not in compliance with the leverage ratio and senior secured leverage ratio under the Revolving Credit Facility. The Company has been granted a waiver in regards to such ratio covenant defaults at December 31, 2015, and in conjunction with such waiver, the Company was in compliance with all financial covenants under the Revolving Credit Facility at December 31, 2015. Senior Secured Notes The Company has $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. The Notes will mature on May 15, 2018. In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to the Company's unsecured indebtedness and effectively subordinated to the Company's and Guarantors' indebtedness under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation. The Indenture contains covenants that, among other things, limit the Company's ability and the ability of its subsidiaries to: · Transfer or sell assets or use asset sale proceeds; · Pay dividends or make distributions, redeem subordinated debt or make other restricted payments; · Make certain investments; incur or guarantee additional debt or issue preferred equity securities; · Create or incur certain liens on the Company's assets; · Incur dividend or other payment restrictions affecting future restricted subsidiaries; · Merge, consolidated or transfer all or substantially all of the Company's assets; · Enter into certain transactions with affiliates; and · Enter into certain sale and leaseback transactions. These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture. At December 31, 2015, the Notes reflected a balance of $317.8 million, net of unamortized discounts of $7.2 million, on the consolidated balance sheets. |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation | 5. Asset Retirement Obligation A summary of the activity related to the asset retirement obligation is as follows: For the years ended December 31, 2015 2014 2013 (in thousands) Asset retirement obligation, beginning of year $ 5,557 $ 6,063 $ 6,963 Liabilities incurred during period 302 305 3,416 Liabilities settled during period (37 ) (704 ) (126 ) Accretion expense 502 506 468 Revision in previous estimates and other 178 32 60 Deletions related to property disposals (416 ) (645 ) (4,718 ) Asset retirement obligation, end of year $ 6,086 $ 5,557 $ 6,063 As of December 31, 2015, the current portion of the Company's asset retirement obligation was $89,000 and was recorded in current liabilities on the consolidated balance sheet. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 6. The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 inputs. For the years ended December 31, 2015 and 2014, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in the Appalachian Basin, the Company reclassified $14.4 million of unproved properties to proved properties for the year ended December 31, 2015. For the year ended December 31, 2014, the Company reclassified $3.3 million of Marcellus East unproved properties to proved properties. As no other fair value measurements are required to be recognized on a non-recurring basis at December 31, 2015, no additional disclosures are provided at December 31, 2015. As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows: · Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds. · Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. · Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge oil, natural gas and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014: Fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 50,074 $ — $ — $ 50,074 Commodity derivative contracts — — 24,869 24,869 Liabilities: Commodity derivative contracts — — (451 ) (451 ) Total $ 50,074 $ — $ 24,418 $ 74,492 Fair value as of December 31, 2014 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 11,008 $ — $ — $ 11,008 Commodity derivative contracts — — 27,502 27,502 Liabilities: Commodity derivative contracts — — — — Total $ 11,008 $ — $ 27,502 $ 38,510 The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2015 and 2014. For the years ended December 31, 2015 2014 (in thousands) Balance at beginning of period $ 27,502 $ 3,764 Total gains included in earnings 24,589 19,569 Purchases 1,326 369 Issuances (1,313 ) — Settlements (1) (27,686 ) 3,800 Balance at end of period $ 24,418 $ 27,502 The amount of total (losses) gains for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2015 and 2014 $ (1,890 ) $ 23,902 (1) Included in gain (loss) on commodity derivatives contracts on the consolidated statement of operations. At December 31, 2015, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at December 31, 2015 was $377.5 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximated the current market rate (Level 2). The estimated fair value of the Company’s long-term debt at December 31, 2014 was $330.6 million based on quoted market prices of the Notes (Level 1). The Company has consistently applied the valuation techniques discussed above in all periods presented. The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivative Instruments and Hedging Activity.” |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activity | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activity | 7. The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in gain (loss) on commodity derivatives contracts. For the years ended December 31, 2015 and 2013, the Company reported losses of $1.9 million and $10.0 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the year ended December 31, 2014, the Company reported a gain of $23.9 million in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. As of December 31, 2015, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume (1) Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in Bbls) 2016 Costless three-way collar 275 100,650 $ 85.00 $ 65.00 $ 95.10 $ 96.50 2016 Costless three-way collar 330 120,780 $ 80.00 $ 65.00 $ 97.35 $ 97.80 2016 Costless three-way collar 450 164,700 $ 57.50 $ 42.50 $ 80.00 $ 96.25 2016 Put spread 550 201,300 $ 85.00 $ 65.00 $ — $ 96.50 2016 Put spread 300 109,800 $ 85.50 $ 65.50 $ — $ 97.80 2017 Costless three-way collar 280 102,200 $ 80.00 $ 65.00 $ 97.25 $ 96.25 2017 Costless three-way collar 242 88,330 $ 80.00 $ 60.00 $ 98.70 $ — 2017 Costless three-way collar 200 73,000 $ 60.00 $ 42.50 $ 85.00 $ — 2017 Put spread 500 182,500 $ 82.00 $ 62.00 $ — $ — 2017 Costless three-way collar 200 73,000 $ 57.50 $ 42.50 $ 76.13 $ 95.10 2018 (2) Put spread 425 103,275 $ 80.00 $ 60.00 $ — $ 97.35 (1) Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. (2) For the period January to August 2018. As of December 31, 2015, the following natural gas transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in MMBtu’s) 2016 (1) Producer three-way 2,500 762,500 $ — $ 3.00 $ 2.25 $ 3.65 2016 Protective spread 2,000 732,000 $ 4.11 $ — $ 3.25 $ — 2016 Producer three-way 2,000 732,000 $ — $ 4.00 $ 3.25 $ 4.58 2016 Producer three-way 5,000 1,830,000 $ — $ 3.40 $ 2.65 $ 4.10 2016 Basis swap (2) 2,500 915,000 $ (1.10 ) $ — $ — $ — 2016 Basis swap (2) 2,500 915,000 $ (1.02 ) $ — $ — $ — 2016 Basis swap (2) 2,500 915,000 $ (1.00 ) $ — $ — $ — 2016 (3) Producer three-way collar 7,500 682,500 $ — $ 3.00 $ 2.50 $ 4.00 2016 (4) Producer three-way collar 5,000 1,375,000 $ — $ 3.00 $ 2.35 $ 4.00 2017 Short call 10,000 3,650,000 $ — $ — $ — $ 4.75 2017 Basis swap (2) 2,500 912,500 $ (1.02 ) $ — $ — $ — 2017 Basis swap (2) 2,500 912,500 $ (1.00 ) $ — $ — $ — 2017 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 2018 Basis swap (2) 2,500 912,500 $ (1.02 ) $ — $ — $ — 2018 Basis swap (2) 2,500 912,500 $ (1.00 ) $ — $ — $ — 2018 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 (1) For the period January to October 2016. (2) Represents basis swaps at the sales point of TetcoM2. (3) For the period January to March 2016. (4) For the period April to December 2016. As of December 31, 2015, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price (in Bbls) 2016 Fixed price swap 500 183,000 $ 20.79 As of December 31, 2015, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features. In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period January 2016 through December 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated: For 2015 2014 (in thousands) Current commodity derivative premium put payable $ 3,194 $ 2,481 Long-term commodity derivative premium payable 2,788 4,702 Total unamortized put premium liabilities $ 5,982 $ 7,183 For the Years ended December 31, 2015 2014 (in thousands) Put premium liabilities, beginning balance $ 7,183 $ 7,145 Amortization of put premium liabilities (2,295 ) (145 ) Additional put premium liabilities 1,094 183 Put premium liabilities, ending balance $ 5,982 $ 7,183 The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2015: Amortization (in thousands) January to December 2016 $ 3,194 January to December 2017 1,819 January to December 2018 969 Total unamortized put premium liabilities $ 5,982 Additional Disclosures about Derivative Instruments and Hedging Activities The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value December 31, Balance Sheet Location 2015 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 15,534 $ 19,687 Commodity derivative contracts Other assets 9,335 7,815 Commodity derivative contracts Long-term liabilities (451 ) — Total derivatives not designated as hedging instruments $ 24,418 $ 27,502 Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31, Location of Gain (Loss) Recognized in Income on Derivatives 2015 2014 2013 (in thousands) Derivatives Commodity derivative contracts Gain (loss) on commodity derivatives contracts $ 24,589 $ 19,569 $ (4,752 ) Total $ 24,589 $ 19,569 $ (4,752 ) |
Capital Stock
Capital Stock | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders Equity Note [Abstract] | |
Capital Stock | 8. Capital Stock Common Stock On November 14, 2013, Parent changed its jurisdiction of incorporation to the State of Delaware and entered into new articles of incorporation pursuant to which 275,000,000 shares of Parent's common stock, par value $0.001 per share, are authorized for issuance. Prior to November 14, 2013, Parent’s articles of incorporation allowed Parent to issue an unlimited number of common shares without par value. At December 31, 2013 and 2012, all 750 shares of Gastar USA's common stock were held by Parent. On May 24, 2011, Gastar USA converted from a Michigan corporation to a Delaware corporation (the “Conversion”). Following the Conversion, Gastar USA’s Delaware certificate of incorporation allowed Gastar USA to issue 1,000 shares of common stock, without par value. In connection with the Conversion, the Parent’s 750 shares of common stock in the Michigan corporation were converted to 750 shares of common stock in the new Gastar USA Delaware corporation. On October 25, 2013, Gastar USA filed an Amended and Restated Certificate of Incorporation (the “A&R Certificate”) with the Secretary of State of the State of Delaware. Under the A&R Certificate, the capital stock authorized for issuance was increased from 1,000 shares of common stock, without par value, to 275,000,000 shares of common stock, par value $0.001 per share. On January 31, 2014, Parent entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Parent merged with and into Gastar USA, a direct subsidiary of Parent, as part of a reorganization to eliminate Parent's holding company corporate structure. Pursuant to the Merger Agreement, shares of Parent's common stock were converted into the right to receive an equal number of shares of common stock of Gastar USA, which together with its subsidiary, owns and continues to conduct business in substantially the same manner as it was being conducted by Parent and its subsidiaries immediately prior to the merger. On September 24, 2014, the Company sold 17,000,000 shares of its common stock in an underwritten public offering pursuant to the Company's effective Registration Statement on Form S-3 at a price of $6.25 per share, or $106.3 million before offering costs and expenses. The Company received approximately $101.3 million of proceeds from the offering, net of estimated offering costs and expenses of approximately $5.0 million. On May 7, 2015, the Company entered into an at-the-market issuance sales agreement with MLV & Co. LLC (the “Sales Agent”) to sell, from time to time through the Sales Agent, shares of the Company's common stock (the “ATM Program”). The shares will be issued pursuant to the Company's existing effective shelf registration statement on Form S-3, as amended (Registration No. 333-193832). The Company registered shares having an aggregate offering price of up to $50.0 million. During the year ended December 31, 2015, no shares were sold through the ATM program. Stockholder Rights Agreement On January 18, 2016, the Company’s Board of Directors adopted a stockholder rights plan (the “Rights Agreement”) pursuant to which the Company declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on January 28, 2016. Each Right entitles the holder, subject to the terms of the Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $6.96, subject to certain adjustments. The purpose of the Rights Agreement is to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The Rights generally become exercisable on the earlier of (i) ten business days after any person or group obtains beneficial ownership of 4.9% of the Company’s outstanding common stock (an “Acquiring Person”) or (ii) ten business days after commencement of a tender or exchange offer resulting in any person or group becoming an Acquiring Person. The exercise price payable, and the number of shares of Series C Preferred Stock or other securities or property issuable, upon exercise of the Rights are subject to adjustment from time to time to prevent dilution. In the event that, after a person or a group has become an Acquiring Person, the Company is acquired in a merger or other business combination transaction (or 50% or more of the Company’s assets or earning power are sold), proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then-current exercise price of the Right, that number of shares of common stock of the acquiring company having a market value at the time of that transaction equal to two times the exercise price. The Company may redeem the Rights in whole, but not in part, at any time before a person or group becomes an Acquiring Person at a price of $0.001 per Right, subject to adjustment. At any time after any person or group becomes an Acquiring Person, the Company may generally exchange each Right in whole or in part at an exchange ratio of two shares of common stock per outstanding Right, subject to adjustment. The Rights will expire on January 18, 2019 unless terminated on an earlier date pursuant to the terms of the Rights Agreement. The Series C Preferred Stock is not redeemable by the Company and has certain voting rights and dividend and liquidation privileges. Preferred Stock Pursuant to the Company’s certificate of incorporation, the Company has 40,000,000 shares of preferred stock authorized. The Company has designated 10,000,000 of such shares to constitute its 8.625% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 of such shares to constitute its 10.75% Series B Cumulative Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share. Series A Preferred Stock At December 31, 2015, there were 4,045,000 shares of Series A Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series A Preferred Stock ranks senior to the Company's common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. The Series A Preferred Stock cannot be converted into common stock, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends. There is no mandatory redemption of the Series A Preferred Stock. The Company pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the years ended December 31, 2015, 2014 and 2013, the Company paid dividends of $8.7 million, $8.7 million and $8.5 million, respectively. Effective March 9, 2016, the Revolving Credit Facility prohibits the payment of cash dividends on the Company’s preferred stock commencing April 2016. Dividends on the Series A and Series B Preferred Stock will accumulate regardless of whether any such dividends are declared. If the Company fails to pay full cash dividends in four calendar quarters, whether consecutive or non-consecutive, then the fixed rate of Series A and Series B Preferred Stock each increases by 2.00% and the holders, voting as a single class, will have the right to elect up to two directors to the board of directors of the Company. Series B Preferred Stock At December 31, 2015, there were 2,140,000 shares of the Series B Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock. Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company will have the option to redeem the Series B Preferred Stock within 90 days of the occurrence of the change in control, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If the Company does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into the Company's common stock based upon on an average common stock trading price then in effect but limited to an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption. There is no mandatory redemption of the Series B Preferred Stock. The Company pays cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the years ended December 31, 2015, 2014 and 2013, the Company paid dividends of $5.8 million, $5.8 million and $847,000, respectively. Effective March 9, 2016, the Revolving Credit Facility prohibits the payment of cash dividends on the Company’s preferred stock commencing April 2016. Dividends on the Series A and Series B Preferred Stock will accumulate regardless of whether any such dividends are declared. If the Company fails to pay full cash dividends in four calendar quarters, whether consecutive or non-consecutive, then the fixed rate of Series A and Series B Preferred Stock each increases by 2.00% and the holders, voting as a single class, will have the right to elect up to two directors to the board of directors of the Company. Other Share Issuances The following table provides information regarding the issuances and forfeitures of the Company's common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated: For the Years Ended December 31, 2015 2014 Other stock issuances: Shares of restricted common stock granted 1,426,604 601,473 Shares of restricted common stock vested 1,422,670 1,915,242 Shares of common stock issued pursuant to PBUs vested, net of forfeitures 497,636 472,189 Stock options exercised — 7,500 Shares of restricted common stock surrendered upon vesting/exercise (1) 413,333 612,612 Shares of restricted common stock forfeited 119,499 47,398 (1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period. In connection with the merger, Parent's 2006 Long-Term Stock Incentive Plan was assumed by Gastar Exploration Inc. and, effective as of the merger, was amended, restated and renamed the “Gastar Exploration Inc. Long-Term Incentive Plan” (as amended, the “LTIP”). On June 12, 2014, the Company's stockholders approved an amendment and restatement to the LTIP, effective April 24, 2014, to, among other things, increase the number of shares reserved for issuance under the LTIP by 3,000,000 shares. There were 2,877,599 shares available for issuance under the LTIP at December 31, 2015. Shares Reserved At December 31, 2015, the Company had 866,600 shares of common stock reserved for the exercise of stock options and 1,283,167 shares reserved for the settlement of PBUs. Shares Owned by Chesapeake Energy Corporation On March 28, 2013, the Company entered into a Settlement Agreement, dated March 28, 2013, between Chesapeake Exploration, L.L.C. and Chesapeake Energy Corporation (collectively, “Chesapeake”) and the Company, Gastar Texas and Gastar Texas, LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding shares of common stock of Parent held by Chesapeake Energy Corporation upon the closing of the stock repurchase and settlement on June 7, 2013. |
Equity Compensation Plans
Equity Compensation Plans | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Equity Compensation Plans | 9. Equity Compensation Plans Share-Based Compensation Plan The vesting period for recent restricted common stock grants has been from two to four years, but generally has been over three years, vesting annually from the date of grant in equal proportions. On June 12, 2014, the Company's stockholders approved the Amended and Restated Gastar Exploration Inc. Long-Term Incentive Plan (the “LTIP”). The LTIP permits us to issue stock options, stock appreciation rights, bonus stock awards and any other type of award (including performance-based units, or “PBU’s”), which are consistent with the LTIP’s purpose to directors, officers and employees of the Company and its subsidiaries. At December 31, 2015, 2,877,599 shares of common stock were available for future stock-based compensation grants under the LTIP. All shares of common stock issued upon the exercise of stock option grants or vesting of restricted stock grants and PBUs are authorized, issued by the Company and are fully paid and non-assessable. Stock Options There were no stock options granted during the years ended December 31, 2015, 2014 and 2013. However, in prior years, the Company issued stock options as a component of its equity compensation program and the fair value of such stock options grants were estimated using the Black-Scholes Merton valuation model. As of December 31, 2015, all stock options were vested. Stock Option Activity The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2015: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at December 31, 2014 866,600 $ 11.75 Granted — — Exercised — — Canceled/Expired — — Forfeited — — Outstanding at December 31, 2015 866,600 $ 11.75 Options vested and exercisable at December 31, 2015 866,600 $ 11.75 1.19 $ — There was no unrecognized expense as of December 31, 2015 for all outstanding options. Restricted Share Activity The Company has granted restricted shares of common stock which vest based upon continued service or certain other events. The vesting period for recent restricted common stock grants has been from one to three years, but generally has been over three years, except for grants to Company directors that vest in one year, vesting annually from the date of grant in equal proportions. The following table summarizes information related to restricted shares at December 31, 2015: Shares Weighted Average Fair Value per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding non-vested restricted shares at December 31, 2014 2,411,914 $ 2.79 Granted 1,426,604 2.40 Vested (1,422,670 ) 2.67 Forfeited (119,499 ) 2.58 Outstanding non-vested restricted shares at December 31, 2015 2,296,349 $ 2.63 1.23 $ 3,008 The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated: For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share data) Weighted average grant date fair value per restricted share $ 2.40 $ 5.85 $ 1.30 Total fair value of restricted shares vested $ 3,794 $ 3,497 $ 2,725 For the year ended December 31, 2015, the Company recognized $3.5 million of compensation expense associated with restricted share awards. Unrecognized compensation expense as of December 31, 2015 for all outstanding restricted share awards is $1.4 million and will be recognized over a weighted average period of 1.36 years. Performance Based Units Activity During 2015, 2014 and 2013, a portion of long-term incentive grants to Company management were in the form of PBUs. The PBUs represent a contractual right to receive shares of the Company's common stock, an amount of cash equal to the fair market value of a share of the Company's common stock, or a combination of shares of the Company's common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs vest equally and settlement is determined annually over a three year period. Any PBUs not vested at each measurement date will expire. Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of the Company's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the PBU award. The table below provides a summary of PBUs as of the date indicated: PBUs Fair per Unit Unvested PBUs at December 31, 2014 990,658 $ 3.19 Granted 741,146 3.01 Vested (448,637 ) 2.76 Forfeited — — Unvested PBUs at December 31, 2015 1,283,167 $ 3.24 For the year ended December 31, 2015, the Company recognized $1.5 million of compensation expense associated with the PBUs. As of December 31, 2015, the Company had $1.8 million of total unrecognized expense for the PBUs to be recognized over a weighted average period of 1.92 years. Stock-Based Compensation Expense For the years ended December 31, 2015, 2014 and 2013, the Company recorded stock-based compensation expense for restricted shares, PBUs, and stock options granted using the fair-value method of $5.0 million, $4.9 million and $3.4 million, respectively. All stock-based compensation costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense. As of December 31, 2015, the Company had approximately $3.2 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods: Amount (in thousands) 2016 $ 2,074 2017 1,075 2018 82 Total $ 3,231 |
Interest Expense
Interest Expense | 12 Months Ended |
Dec. 31, 2015 | |
Interest Expense [Abstract] | |
Interest Expense | 10. The following tables summarize the components of the Company's interest expense for the periods indicated: For the Years Ended December 31, 2015 2014 2013 (in thousands) Interest expense: Cash and accrued $ 30,981 $ 28,851 $ 14,130 Amortization of deferred financing costs (1)(2) 3,584 3,067 2,322 Capitalized interest (3,879 ) (4,347 ) (3,284 ) Total interest expense $ 30,686 $ 27,571 $ 13,168 (1) The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.” (2) The years ended December 31, 2015, 2014 and 2013 include $2.5 million, $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 11. Related Party Transactions Chesapeake Energy Corporation Chesapeake Energy Corporation acquired 6,781,768 of Parent’s common shares during 2005 to 2007 in a series of private placement transactions. On March 28, 2013, the Company entered into a Settlement Agreement between Chesapeake and the Company, Gastar Texas and Gastar Texas LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of Parent held by Chesapeake upon the closing of the stock repurchase and settlement on June 7, 2013. For more information, see Note 8. “Capital Stock - Shares Owned by Chesapeake Energy Corporation.” Also on March 28, 2013, the Company entered into the Chesapeake Purchase Agreement, pursuant to which Gastar USA acquired the Chesapeake Assets on June 7, 2013. For more information, see Note 3. “Property, Plant and Equipment - Chesapeake Acquisition.” As of December 31, 2015, Chesapeake Energy Corporation did not own any of the Company's outstanding common stock. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 12. Income Taxes The following table summarizes the components of the Company’s (loss) income before income taxes for the periods indicated: For the Year Ended December 31, 2015 2014 2013 (in thousands) United States $ (459,507 ) $ 50,953 $ 35,234 Foreign — — (1,934 ) Total income (loss) before income taxes $ (459,507 ) $ 50,953 $ 33,300 The Company did not report any current provision for income taxes for the years ended December 31, 2015, 2014 and 2013. The Company’s deferred income tax expense (benefit) consists of the following for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in thousands) Deferred: Federal $ — $ — $ (15,299 ) State — — (743 ) Foreign — — — Income tax expense (benefit) $ — $ — $ (16,042 ) The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated: For the Years Ended December 31, 2015 2014 2013 (in thousands) Expected income tax provision (benefit) at statutory rate $ (160,827 ) $ 17,833 $ 11,655 State tax, tax effected (7,799 ) 803 96 Stock-based compensation expense (benefit) 255 (1,291 ) 605 Tax effect of Canadian tax rate differences — — 193 Loss of Canadian tax attributes due to migration from Canada — — 19,825 Gain on acquisition of assets at fair value — — (9,685 ) Non-deductible costs of migration from Canada to U.S. — — 95 Other 17 38 (49 ) Other changes in valuation allowance 168,354 (17,383 ) (38,777 ) Actual income tax provision $ — $ — $ (16,042 ) The components of the Company’s U.S. deferred taxes are as follows: As of December 31, 2015 2014 (in thousands) Deferred tax asset (liability): Capital assets $ 10,485 $ (134,223 ) Stock-based compensation 4,243 4,504 Net operating loss carry forwards 187,963 164,056 Foreign tax credit carry forwards 50,681 50,681 Valuation allowance (253,372 ) (85,018 ) Net deferred tax asset $ — $ — The Company has approximately $512.0 million of net operating loss carry forwards as of December 31, 2015, which, if not utilized, will expire between 2030 and 2035. For U.S. federal income tax purposes, as of December 31, 2015, the Company has foreign tax credit carry forwards of $50.7 million, which, if not utilized, will expire in 2019. The utilization of the net operating loss carry forward and the foreign tax credit carry forward are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors. Effective November 14, 2013, the Company withdrew from Canada and re-incorporated in Delaware (the “Migration”). As a result of the Migration, the Company's Canadian tax attributes have effectively been forfeited. As all of the Canadian tax attributes were subject to a valuation allowance, the Migration from Canada to the U.S. did not result in any Canadian tax expense. Current authoritative guidance requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2015, the Company did not have any material unrecognized tax benefits that, if recognized, would affect the effective tax rate. The Company is subject to examination of income tax filings in the U.S. and various state jurisdictions for the periods 2010 and Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits. |
Earnings per Share
Earnings per Share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Earnings per Share | 13. Earnings per Share In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share and share data) Net income (loss) attributable to common stockholders $ (473,980 ) $ 36,529 $ 39,964 Weighted average shares of common stock outstanding - basic 77,511,677 63,270,733 60,220,115 Incremental shares from unvested restricted shares — 2,451,903 2,869,490 Incremental shares from outstanding stock options — 97,491 26,095 Incremental shares from outstanding PBUs — 672,462 502,701 Weighted average shares of common stock outstanding - diluted 77,511,677 66,492,589 63,618,401 Net income (loss) per share of common stock attributable to common stockholders: Basic $ (6.11 ) $ 0.58 $ 0.66 Diluted $ (6.11 ) $ 0.55 $ 0.63 Shares of common stock excluded from denominator as anti-dilutive: Unvested restricted shares 177,663 34,058 3,505 Unvested PBUs 17,589 — — Total 195,252 34,058 3,505 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 14. Commitments and Contingencies Contractual Obligations The Company leases its office facilities and certain office equipment under non-cancelable operating lease agreements with various termination dates, the latest of which is December 2018. For the years ended December 31, 2015, 2014 and 2013, office lease expense totaled approximately $687,000, $649,000 and $372,000, respectively. As of December 31, 2015, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: 2016 $ 660 2017 211 2018 176 $ 1,047 Litigation Gastar Exploration Ltd vs U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No. 2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage are $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Court of Appeals, which that court denied. The insurers then sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The insurers then filed in the Texas Supreme Court a motion for rehearing of their denied petition for review, which the court has denied. The case has now been remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of the portion of the Company's settlement of the ClassicStar Mare Lease Litigation that is covered by the insuring agreements. On July 28, 2015, the parties submitted briefs in support of their respective positions regarding the issues left to be resolved in the case and the requisite amount of time for such proceedings. On August 11, 2015, the court entered a docket control order establishing the week of March 7, 2016 as the tentative week for the case to go to trial. The court has since canceled that trial date to allow additional time to brief discovery- and coverage-related issues. Husky Ventures, Inc. vs. J. Russell Porter, Michael A. Gerlich, Michael McCown, Keith R. Blair, Henry J. Hansen and John M. Selser Sr. (Case No. CIV-15-637-R) United States District Court for the Western District of Oklahoma. On June 9, 2015, Husky Ventures, Inc. (“Husky”) filed this action against five of Gastar’s senior officers and our non-executive chairman of the board alleging that each of the defendants committed fraud by grossly understating the costs of certain oil and gas interests Gastar acquired that were outside a Mid-Continent AMI between Husky and Gastar while inflating the costs of interests simultaneously acquired within the AMI. Husky alleged this resulted in the defendants improperly shifting a disproportionate amount of acquisition costs away from Gastar and to Husky. Husky sought to recover actual damages alleged to be in excess of $2.0 million, as well as punitive damages and attorneys’ fees. In connection with Gastar’s entry into the purchase agreement in connection with the Husky Acquisition, Gastar, five of its senior officers, its non-executive chairman and Husky agreed to a mutual release of claims that Gastar and Husky made against each other in this matter as well as any claims the parties may have had against each other in connection with the AMI participation agreements. The claims the parties had filed against each other were therefore dismissed on October 16, 2015. Gastar Exploration Inc. v. Christopher McArthur (Cause No.: 2015-77605) 157th Judicial District Court, Harris County, Texas . On December 29, 2015, Gastar filed suit against Christopher McArthur (“McArthur”) in the District Court of Harris County, Texas. The lawsuit arises from a demand letter sent by McArthur to Gastar in which he claimed to be party to an agreement or contract with Gastar that entitled him to be paid $2.75 million for services rendered. In its lawsuit, Gastar denies that such an agreement or contract exists, that McArthur provided any services to Gastar or for Gastar’s benefit, and seeks a declaratory judgment that it did not enter into an agreement or contract with McArthur and that it does not owe any amounts to McArthur under the terms of any agreement or contract. Gastar also seeks to recover its attorneys’ fees. McArthur answered the lawsuit on February 8, 2016 by filing a general denial. Eagle Natrium LLC v. Gastar Exploration USA, Inc., Cause No. GD-14-7208, In the Court of Common Pleas of Allegheny County, Pennsylvania. On April 22, 2014, Eagle Natrium LLC (“Eagle”), a wholly-owned subsidiary of Axiall Corporation, filed a complaint against Gastar in the Court of Common Pleas of Allegheny County, Pennsylvania seeking to enjoin Gastar's hydraulic fracturing and completion operations on three wells drilled from Gastar's Goudy pad in Marshall County, West Virginia, or conducting any activity that poses a substantial risk of harm to Eagle's brine operations. Gastar is the operator of approximately 16,000 acres in Marshall County, West Virginia, including a 3,300 gross acre oil and gas lease adjacent to Eagle's facilities. Eagle operates a subsurface brine operation which it acquired from the lessor of Gastar's lease. Eagle has asserted its right to relief based on certain of the lessor's rights which were assigned to Eagle by the lessor solely as they relate to the brine and related facilities. The complaint alleges that the contemplated operations of Gastar, which include hydraulic fracturing, pose a danger to the subsurface brine operations of Eagle. All wells drilled to date on this lease, including the wells principally involved in the complaint, were previously approved pursuant to the terms of Gastar's lease. A hearing on the request for preliminary injunction was held over the course of two weeks. After considering the evidence presented at the hearing and the party's briefing, the court issued an order on October 21, 2014 denying the request for a preliminary injunction. On October 30, 2014, Eagle filed a nearly identical lawsuit against Gastar and the West Virginia Department of Environmental Protection (“WVDEP”) in the Circuit Court of Marshall County, West Virginia, requesting a temporary restraining order prohibiting Gastar from hydraulically fracturing the same wells that were the subject of the proceeding in Pennsylvania. That same day, the Court held a hearing and granted a temporary restraining order against Gastar and required that Eagle post an $800,000 bond. On December 24, 2014, Circuit Judge David W. Hummel dismissed Gastar from the lawsuit finding that Eagle was collaterally and judicially estopped from maintaining in West Virginia a lawsuit that was essentially identical to the prior lawsuit in Pennsylvania. After further briefing, Judge Hummel dismissed the claims against the WVDEP on December 29, 2014. After the dismissal of the West Virginia lawsuit, Gastar began completion operations and has since completed the three wells drilled from its Goudy pad that formed the basis of Eagle’s complaint. Gastar moved to dismiss the suit in Pennsylvania on account of mootness and has added a counterclaim seeking damages from Eagle as a result of the proceedings. Gastar sought attorney’s fees and damages in West Virginia, ultimately settling its claims for costs against Eagle by accepting $900,000. The West Virginia matter was therefore dismissed on December 3, 2015. Gastar Exploration USA, Inc., et al v. Williams Ohio Valley Midstream LLC (American Arbitration Association Matter No. 70-198-Y-00461-13) . On July 16, 2013, Gastar USA and two similarly situated co-claimants initiated an arbitration proceeding against Williams Ohio Valley Midstream LLC (“Williams OVM”). The claimants allege that Williams OVM has breached various agreements relating to the gathering, processing and marketing of natural gas, NGLs and condensate produced from properties that are owned in part by Gastar USA in the Marcellus Shale in Marshall and Wetzel Counties, West Virginia, and requested that an Arbitration Panel assess an unspecified amount of damages against Williams OVM for, among other claims, failure to timely construct certain gathering and processing facilities and maximize the net value of the condensate and NGLs produced as provided in the agreements. On August 7, 2013, Williams OVM filed an answering statement and counterclaim for damages in excess of $612,000 in the arbitration matter. On December 31, 2013, the parties informed the Arbitration Panel that they had reached an agreement in principle to settle their disputes. The disputes were subsequently settled, on a confidential basis, between both parties on June 17, 2014. Although there were some changes to the contracts, there were no changes to existing contractual fees. After production taxes and lease operating expense reimbursement benefit, the net arbitration settlement amount received by Gastar USA was approximately $8.6 million. Chesapeake Exploration L.L.C. (“Chesapeake Exploration”) and Chesapeake Energy Corp. (“Chesapeake Energy”) v. Gastar Exploration Ltd., Gastar Exploration Texas, LP, and Gastar Exploration Texas, LLC (No. 4:12-cv-2922), United States District Court for the Southern District of Texas, Houston Division. This lawsuit, filed on October 1, 2012, was resolved as part of an acquisition transaction which closed on June 7, 2013. Thereafter, the parties to the Chesapeake lawsuit filed stipulation of dismissal of prejudice, and on June 11, 2013, the court entered an order dismissing the case with prejudice. In connection with the resolution of the matter, the Company made an aggregate cash payment of approximately $80.0 million, comprised of approximately $69.4 million in property acquisition costs (subject to adjustment for an acquisition effective date of October 1, 2012), stock repurchase price of approximately $9.8 million and an additional $1.0 million for litigation settlement. The Company has been expensing legal defense costs on these proceedings as they are incurred. The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Commitments During December 2010, we, along with Atinum, entered into a gas purchase agreement with SEI Energy, LLC (“SEI”) with respect to our Marshall County, West Virginia production. The initial term of the gas purchase agreement was five years with the option to extend the term of the gas purchase agreement for an additional five year period. Our Marshall County, West Virginia production is dedicated to SEI for the term of the gas purchase agreement. During June 2014, the Company entered into an agreement to include the dedication of all of our Wetzel County, West Virginia production to SEI in addition to our Marshall County, West Virginia production. SEI will purchase all hydrocarbon production, including all natural gas, condensate and natural gas liquids. SEI has an agreement to utilize the Williams Ohio Valley Midstream LLC (“Williams") midstream facilities (formerly owned by Caiman Energy Midstream, LLC), including its 520.0 MMcf/d Fort Beeler processing plant or William's 200.0 MMcf/d Oak Grove processing plant located in Marshall County, West Virginia for transporting and processing. In order to secure access to the Williams facilities, we, Atinum and SEI dedicated all hydrocarbons purchased and produced in Marshall County, West Virginia for a term of ten years. Upon closing of the sale of the Company’s Marshall and Wetzel County, West Virginia properties, the Company will no longer utilize SEI and will have no further obligations under the SEI agreement. Restoration, Removal and Environmental Liabilities The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year. At December 31, 2015, the Company had total liabilities of $6.1 million related to asset retirement obligations of which $89,000 is recorded as short-term liabilities and $6.0 million is recorded as long-term liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 5, “Asset Retirement Obligation.” Indemnifications Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict. Employment Agreements The Company entered into employment agreements with its Chief Executive Officer and its Chief Financial Officer, effective February 24, 2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008 and April 10, 2012), respectively. The Company entered into an employment agreement with its Chief Operating Officer on June 19, 2014 and such agreement was terminated on February 1, 2016 in conjunction with the Chief Operating Officer’s retirement. The agreements set forth, among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions. The Company also has entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them to the fullest extent permitted by law against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to the beneficiary of such indemnification agreements. |
Concentration of Risk and Signi
Concentration of Risk and Significant Customers | 12 Months Ended |
Dec. 31, 2015 | |
Risks And Uncertainties [Abstract] | |
Concentration of Risk and Significant Customers | 15. Concentration of Risk and Significant Customers The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated: For the Years Ended December 31, 2015 2014 2013 Appalachian Basin 17 % 39 % 65 % Mid-Continent 83 % 61 % 26 % Hilltop Area, East Texas (1) — % — % 9 % (1) The Company’s working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013. The following table provides information regarding the Company’s significant customers whom accounted for more than 10% of the Company’s oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated: For the Years Ended December 31, 2015 2014 2013 SEI 22 % 50 % 56 % Sunoco 62 % 37 % 16 % SEI and Sunoco purchase the majority of the Company’s Mid-Continent production. There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that SEI or Sunoco were to cease purchasing and transporting our oil, condensate, natural gas and NGLS production, the Company’s ability to conduct normal operations would not be significantly restricted. SEI purchases the majority of the Company’s Appalachian Basin production. There are limited oil, condensate, natural gas and NGLs purchase and transportation alternatives currently available in Appalachia. If SEI was to cease purchasing and transporting the Company’s Appalachian Basin oil, condensate, natural gas and NGLs production and the Company was unable to obtain timely access to existing or future facilities on acceptable terms, or in the event of any significant change affecting these facilities, including delays in the commencement of operations of any new pipelines or the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise, the Company’s ability to conduct normal operations would be restricted. |
Statement of Cash Flows - Suppl
Statement of Cash Flows - Supplemental Information | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Statement Of Cash Flows – Supplemental Information | 16. Statement of Cash Flows – Supplemental Information The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements: For the Years Ended December 31, 2015 2014 2013 (in thousands) Cash paid for interest, net of capitalized amounts $ 26,859 $ 24,632 $ 7,341 Non-cash transactions: Capital expenditures (excluded from) included in accounts payable and accrued drilling costs $ (26,228 ) $ 12,777 $ 582 Capital expenditures included in accounts receivable — 4,077 (4,077 ) Asset retirement obligation included in oil and natural gas properties 526 221 (1,302 ) Asset retirement obligation for property disposals (416 ) (645 ) (4,354 ) Application of advances to operators 11,445 58,326 19,755 Other 5 (11 ) 47 |
Quarterly Consolidated Financia
Quarterly Consolidated Financial Data - Unaudited | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Consolidated Financial Data - Unaudited | 17. Quarterly Consolidated Financial Data – Unaudited The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2015 and 2014: 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 34,372 $ 21,928 $ 28,386 $ 22,608 Income (loss) from operations (1) 8,172 (107,462 ) (180,272 ) (149,272 ) Income (loss) before provision for income taxes 614 (114,395 ) (188,201 ) (157,525 ) Net income (loss) 614 (114,395 ) (188,201 ) (157,525 ) Dividend on preferred stock 3,618 3,619 3,618 3,618 Net loss attributable to common stockholders (3,004 ) (118,014 ) (191,819 ) (161,143 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Diluted $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Weighted average shares of common stock outstanding: Basic 77,114,826 77,611,167 77,628,120 77,685,049 Diluted 77,114,826 77,611,167 77,628,120 77,685,049 (1) 2014 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 32,327 $ 35,897 $ 41,746 $ 61,448 Income from operations 8,497 12,539 20,413 37,063 Income before provision for income taxes 1,611 5,627 13,425 30,290 Net income 1,611 5,627 13,425 30,290 Dividend on preferred stock 3,576 3,611 3,618 3,619 Net (loss) income attributable to common stockholders (1,965 ) 2,016 9,807 26,671 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (0.03 ) $ 0.03 $ 0.16 $ 0.35 Diluted $ (0.03 ) $ 0.03 $ 0.15 $ 0.34 Weighted average shares of common stock outstanding: Basic 58,204,532 58,702,982 60,006,903 75,994,979 Diluted 58,204,532 61,922,874 63,399,446 78,577,762 |
Supplemental Oil and Gas Disclo
Supplemental Oil and Gas Disclosures - Unaudited | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Disclosures - Unaudited | 18. Supplemental Oil and Gas Disclosures – Unaudited Capitalized Costs Relating to Oil and Natural Gas Producing Activities The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities in the U.S. for the periods indicated: As of December 31, 2015 2014 2013 (in thousands) Proved properties: $ 1,286,373 $ 1,124,367 $ 935,773 Total proved properties 1,286,373 1,124,367 935,773 Unproved properties: 92,609 128,274 96,220 Total unproved properties 92,609 128,274 96,220 Total oil and natural gas properties 1,378,982 1,252,641 1,031,993 Less: Impairment of proved oil and natural gas properties (764,817 ) (337,939 ) (337,939 ) Accumulated depreciation, depletion and amortization (286,020 ) (223,555 ) (177,790 ) Net capitalized costs $ 328,145 $ 691,147 $ 516,264 Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $2.4 million, $2.4 million and $3.4 million at December 31, 2015, 2014 and 2013, respectively. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and natural gas activities in the U.S. for the periods indicated: For the years ended December 31, 2015 2014 2013 (in thousands) Property acquisition Proved (1) $ 15,615 $ — $ 189,594 Unproved (2) 50,434 41,475 71,472 Exploration 53,290 127,384 36,893 Development 54,316 57,913 53,058 Total costs incurred $ 173,655 $ 226,772 $ 351,017 (1) The 2013 property acquisition costs exclude a downward adjustment of $2.6 million for fair value of acquisition. (2) The 2013 property acquisition costs exclude $46.3 million of adjustment for fair value of acquisition. Results of Operations for Oil and Natural Gas Producing Activities The following table sets forth the Company’s results of operations for oil and natural gas producing activities in the U.S. for the periods indicated: For the Year Ended December 31, 2015 2014 2013 (in thousands, except per Mcfe data) Oil, condensate, natural gas and NGLs sales, including commodity derivatives $ 107,294 $ 171,418 $ 87,755 Production expenses (28,792 ) (29,735 ) (18,113 ) Impairment of oil and natural gas properties (426,878 ) — — Depreciation, depletion and amortization (62,465 ) (45,765 ) (32,158 ) Results of producing activities $ (410,841 ) $ 95,918 $ 37,484 Depreciation, depletion and amortization per MBoe $ 12.67 $ 12.34 $ 9.94 The results of producing activities exclude interest charges and general corporate expenses. In accordance with current authoritative guidance, estimates of the Company’s proved reserves and future net revenues are made using benchmark prices, before lease adjustments, that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves: As of December 31, 2015 2014 Natural gas (per MMBtu): Henry Hub $ 2.59 $ 4.35 Oil (per Bbl): WTI spot $ 50.28 $ 94.99 These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas prices and oil prices, which have fluctuated significantly in recent years. Net Proved and Proved Developed Reserve Summary Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2015, 2014, and 2013. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped reserves are located only in the U.S. The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2015, 2014 and 2013: Change in Proved Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) Proved reserves as of December 31, 2012 3,394 131,010 4,922 30,152 2013 Activity: Extensions and discoveries (4) 4,385 52,750 2,306 15,483 Revisions of previous estimates (337 ) 8,114 714 1,729 Production (515 ) (13,366 ) (494 ) (3,237 ) Purchases in place 7,796 26,961 2,350 14,639 Sales in place (5 ) (24,759 ) — (4,132 ) Proved reserves as of December 31, 2013 14,718 180,710 9,798 54,634 2014 Activity: Extensions and discoveries (5) 13,137 121,672 9,394 42,810 Revisions of previous estimates 1,780 (2,465 ) 7,205 8,574 Production (975 ) (11,598 ) (800 ) (3,708 ) Sales in place (24 ) (1,314 ) (4 ) (247 ) Proved reserves as of December 31, 2014 28,636 287,005 25,593 102,063 2015 Activity: Extensions and discoveries (6) 4,777 14,114 2,244 9,374 Revisions of previous estimates (7) (8,962 ) (182,600 ) (13,873 ) (53,268 ) Production (1,425 ) (13,759 ) (1,212 ) (4,931 ) Purchases in place 1,270 4,965 873 2,971 Sales in place (94 ) (1,274 ) (26 ) (332 ) Proved reserves as of December 31, 2015 24,202 108,451 13,599 55,877 (1) Thousand barrels (2) Million cubic feet or million cubic feet equivalent, as applicable (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. ( 4 ) Of the 2013 extensions and discoveries, 74% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. ( 5 ) Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. ( 6 ) All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. ( 7 ) The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. Proved Developed and Undeveloped Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) December 31, 2013 Proved developed reserves 5,834 114,195 6,025 30,892 Proved undeveloped reserves 8,884 66,515 3,773 23,742 Total 14,718 180,710 9,798 54,634 December 31, 2014 Proved developed reserves 6,968 114,564 10,726 36,789 Proved undeveloped reserves 21,668 172,441 14,867 65,274 Total 28,636 287,005 25,593 102,063 December 31, 2015 Proved developed reserves 7,181 77,966 8,240 28,415 Proved undeveloped reserves 17,021 30,485 5,359 27,462 Total 24,202 108,451 13,599 55,877 (1) Thousand barrels (2) Million cubic feet or million cubic feet equivalent, as applicable (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. . Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented. For the years ended December 31, 2015, 2014 and 2013 future cash inflows were computed using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil (the “benchmark base prices”). For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations: For the Years Ended December 31, 2015 2014 2013 Natural gas, per MMBtu Henry Hub $ 2.59 $ 4.35 $ 3.67 Oil, per barrel: WTI spot $ 50.28 $ 94.99 $ 96.78 These benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows. The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized. A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves in the U.S. is presented below (in thousands): December 31, 2013: Future cash inflows $ 2,103,023 Future production costs (588,568 ) Future development costs (296,666 ) Future income taxes (215,502 ) Future net cash flows 1,002,287 10% annual discount for estimated timing of cash flows (486,458 ) Standardized measure of discounted future cash flows $ 515,829 December 31, 2014: Future cash inflows $ 3,855,227 Future production costs (1,048,554 ) Future development costs (611,602 ) Future income taxes (486,593 ) Future net cash flows 1,708,478 10% annual discount for estimated timing of cash flows (891,739 ) Standardized measure of discounted future cash flows $ 816,739 December 31, 2015: Future cash inflows $ 1,425,734 Future production costs (547,484 ) Future development costs (365,123 ) Future income taxes (1) — Future net cash flows 513,127 10% annual discount for estimated timing of cash flows (283,324 ) Standardized measure of discounted future cash flows $ 229,803 (1) No future taxes payable has been included in the determination of discounted future net cash flows for 2015 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows. Changes in Standardized Measure of Discounted Future Net Cash Flows The principal sources of changes in the standardized measure of future net cash flows are as follows (in thousands): December 31, 2012 $ 206,809 Extensions and discoveries, less related costs 196,448 Sale of natural gas and oil, net of production costs (74,394 ) Purchases of reserves in place 247,208 Sales of reserves in place (9,063 ) Revisions of previous quantity estimates 6,191 Net change in income tax (76,701 ) Net change in prices and production costs 79,820 Accretion of discount 1,211 Development costs incurred 23,567 Net change in estimated future development costs (97,461 ) Change in production rates (timing) and other 12,194 December 31, 2013 $ 515,829 Extensions and discoveries, less related costs 369,806 Sale of natural gas and oil, net of production costs (122,114 ) Sales of reserves in place (1,475 ) Revisions of previous quantity estimates 101,044 Net change in income tax (95,245 ) Net change in prices and production costs 59,786 Accretion of discount (3,996 ) Development costs incurred 37,461 Net change in estimated future development costs (1,276 ) Change in production rates (timing) and other (43,081 ) December 31, 2014 $ 816,739 Extensions and discoveries, less related costs 71,547 Sale of natural gas and oil, net of production costs (53,914 ) Purchases of reserves in place 9,937 Sales of reserves in place (4,853 ) Revisions of previous quantity estimates (324,036 ) Net change in income tax 171,946 Net change in prices and production costs (604,074 ) Accretion of discount 98,869 Development costs incurred 10,500 Net change in estimated future development costs 31,131 Change in production rates (timing) and other 6,011 December 31, 2015 $ 229,803 |
Summary of Significant Accoun26
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with U.S. GAAP. The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 18. “Supplemental Oil and Gas Disclosures.” All 2013 statement of operations, statement of stockholders’ equity and statement of cash flows balances are those of Gastar Exploration, Inc. |
Subsequent Events | Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. On January 29, 2016, the Company, together with the parties thereto, entered into Limited Waiver and Amendment No. 7 to Second Amended and Restated Credit Agreement (“Amendment No. 7”). Pursuant to Amendment No. 7, the Company obtained (i) a waiver until March 10, 2016 of any potential defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility and (ii) a permanent waiver of any defaults of the restricted payment covenant under the Revolving Credit Facility resulting from (a) cash distributions paid on December 31, 2015 in respect of its Series A Preferred Stock and its Series B Preferred Stock and (b) the issuance on January 28, 2016, as a dividend on the Company’ common stock, of the right to purchase Series C Junior Participating Preferred Stock pursuant to the Company’s Rights Agreement dated as of January 18, 2016 as part of the Company’s previously disclosed tax benefits preservation plan. The Revolving Credit Facility was also amended to permit the Company to make dividends and distributions of preferred equity interests or rights to purchase certain preferred equity interests. The entry into Amendment No. 7 permitted the Company to pay monthly cash dividends on its Series A Preferred Stock and its Series B Preferred Stock on February 1, 2016. On February 19, 2016, the Company entered into an agreement to sell substantially all of its assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign. The transaction is expected to close on or before March 31, 2016, with an effective date of January 1, 2016. On March 9, 2016, the Company, together with the parties thereto, entered into Waiver and Amendment No. 8 to Second Amended and Restated Credit Agreement (“Amendment No. 8”). Pursuant to Amendment No. 8, the Company obtained the following relief with respect to its financial covenant compliance: (i) a permanent waiver of the defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility; (ii) relief from compliance with its leverage ratio through the fiscal quarter ending March 31, 2017, but the Company must maintain a maximum leverage ratio of not greater than 4.0 to 1.0 for each fiscal quarter ending on or after June 30, 2017; (iii) an adjustment to the interest coverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 1.10 to 1.00 and for each fiscal quarter ending on or after June 30, 2017 to 2.50 to 1.00; and (iv) an adjustment to its senior secured leverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 2.50 to 1.00 provided that during such period the Company may subtract all cash on hand in calculating the senior secured leverage ratio for such periods and for each fiscal quarter ending on or after June 30, 2017, to 2.00 to 1.00 provided that during such period the Company may only subtract up to $5 million of cash on hand in calculating the senior secured leverage ratio for such periods. As consideration for the financial covenant relief provided for in Amendment No. 8, the Revolving Credit Facility was also amended to, among other things: (i) set the interest margin at (a) 4.0% per annum for Eurodollar rate borrowings and (b) 3.0% per annum for borrowings based on the reference rate; (ii) reduce the borrowing base from $200.0 million to $180.0 million until the earlier of the closing of the Appalachian Basin Sale or April 10, 2016, at which point the borrowing base will automatically be reduced to $100.0 million and require borrowings in excess of such amount to be immediately repaid; (iii) require additional automatic reductions of the borrowing base in connection with asset sales in excess of $5.0 million or the termination of any hedge agreements governing hedges with a settlement date on or after July 1, 2016; (iv) provide for an additional interim borrowing base redetermination in August 2016; (v) require the consent of the lenders to any asset sales in excess of $5.0 million; and (vi) restrict the Company after March 2016 from making any distributions or paying any cash dividends to the holders of its preferred equity, including its outstanding shares of Series A and Series B Preferred Stock. |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation. |
Use of estimates in Preparation of Financial Statements | Use of estimates in Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with U.S. 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 revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $50.1 million and $11.0 million as of December 31, 2015 and 2014, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss. |
Accounts Receivable | Accounts Receivable Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. The Company believes that all current year accounts receivables are deemed collectible and thus, no allowance for doubtful accounts deemed necessary. A summary of the activity related to the allowance for doubtful accounts is as follows: For the years ended December 31, 2015 2014 2013 (in thousands) Allowance for doubtful accounts, beginning of year $ — $ 507 $ 546 Expense — — — Reductions/write-offs — (507 ) (39 ) Allowance for doubtful accounts, end of year $ — $ — $ 507 |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations. In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization. The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2015 and 2014 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered. The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted. |
Asset Retirement Obligation | Asset Retirement Obligation Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations. |
Furniture and Equipment | Furniture and Equipment Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years. |
Capitalized Interest | Capitalized Interest The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The Notes and Revolving Credit Facility were included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2015. Currently, the Company only capitalizes interest on the Notes. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $3.9 million, $4.3 million and $3.3 million for 2015, 2014 and 2013, respectively. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense. Deferred financing costs will be presented as a direct reduction to the carrying amount of the related debt liability beginning in 2016. The following table indicates deferred charges and related accumulated amortization as of the dates indicated: As of December 31, 2015 2014 Deferred charges $ 4,474 $ 3,664 Accumulated amortization (2,116 ) (1,078 ) Deferred charges, net $ 2,358 $ 2,586 |
Derivative Instruments and Hedging Activity | Derivative Instruments and Hedging Activity The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.” The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in gain (loss) on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in gain (loss) on commodity derivatives contracts in the Company’s consolidated statement of operations. |
Stock-Based Compensation | Stock-Based Compensation The Company reports compensation expense for restricted common stock, performance based units (“PBUs”) and stock options granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. Stock-based compensation cost for restricted shares is estimated at the grant date based on the award's fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award's fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. Forfeitures of unvested stock options and restricted common shares are calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. For 2015, 2014 and 2013, the Company used forfeiture rates in determining compensation expense of 17.5%, 25.5% and 14.0%, respectively. |
Treasury Stock | Treasury Stock Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase. |
Revenue Recognition | Revenue Recognition The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company's NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company's wet gas production. The Company's reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2015, 2014 and 2013. The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production. The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet. |
Deferred Income Taxes | Deferred Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time. |
Comprehensive Income | Comprehensive Income Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income attributable to common stockholders as presented in the consolidated statements of operations equals comprehensive income. |
Earnings or Loss per Share | Earnings or Loss per Share Basic earnings or loss per share is computed on the basis of the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of unvested restricted shares and PBUs. |
Co-participation Operations | Co-participation Operations The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities. |
Industry Segment and Geographic Information | Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S. |
Foreign Currency Exchange | Foreign Currency Exchange The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction. All of the Company’s operations are conducted in U.S. dollars. The Company owns immaterial non-operating working interests in two natural gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012. Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations. |
Recent Accounting Developments | Recent Accounting Developments The following recently issued accounting pronouncements have been adopted or may impact us in future periods: Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards (IFRS). IAS 1, . This guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period and can be applied either prospectively or retrospectively to all periods presented. The Company does not expect the adoption of this guidance to materially impact its consolidated financial statements. Business Combinations. In September 2015, the FASB issued updated guidance as part of its simplification initiative that requires that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, depletion and amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The update is effective for public business entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements, other than balance sheet reclassification. Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018 and such proposal was subsequently adopted by the FASB in August 2015. The Company is currently evaluating the effect that adopting this guidance will have on its consolidated financial statements. |
Summary Of Significant Accoun27
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of the activity related to the allowance for doubtful accounts | A summary of the activity related to the allowance for doubtful accounts is as follows: For the years ended December 31, 2015 2014 2013 (in thousands) Allowance for doubtful accounts, beginning of year $ — $ 507 $ 546 Expense — — — Reductions/write-offs — (507 ) (39 ) Allowance for doubtful accounts, end of year $ — $ — $ 507 |
Schedule of deferred charges and accumulated amortization | The following table indicates deferred charges and related accumulated amortization as of the dates indicated: As of December 31, 2015 2014 Deferred charges $ 4,474 $ 3,664 Accumulated amortization (2,116 ) (1,078 ) Deferred charges, net $ 2,358 $ 2,586 |
Property, Plant And Equipment (
Property, Plant And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition [Line Items] | |
Property, Plant and Equipment | The Company's total property, plant and equipment consists of the following: December 31, 2015 2014 (in thousands) Oil and natural gas properties, full cost method of accounting: Unproved properties $ 92,609 $ 128,274 Proved properties 1,286,373 1,124,367 Total oil and natural gas properties 1,378,982 1,252,641 Furniture and equipment 3,068 3,010 Total property and equipment 1,382,050 1,255,651 Impairment of proved natural gas and oil properties (764,817 ) (337,939 ) Accumulated depreciation, depletion and amortization (288,299 ) (225,412 ) Total accumulated depreciation, depletion and amortization (1,053,116 ) (563,351 ) Total property and equipment, net $ 328,934 $ 692,300 |
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization | The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: December 31, 2015 2014 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 1,533 $ 29,193 Acreage acquisition costs 82,560 91,362 Capitalized interest 8,516 7,719 Total unproved properties excluded from amortization $ 92,609 $ 128,274 |
Schedule Of Relevant Assumptions Used In Ceiling Test Computations | 2015 Total December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.59 $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 50.28 $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 426,878 $ 144,760 $ 181,966 $ 100,152 $ — 2014 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 4.35 $ 4.24 $ 4.10 $ 3.99 West Texas Intermediate oil price (per Bbl) (1) $ 94.99 $ 99.08 $ 100.11 $ 98.30 Impairment recorded (pre-tax) (in thousands) $ — $ — $ — $ — $ — 2013 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 3.67 $ 3.61 $ 3.44 $ 2.95 West Texas Intermediate oil price (per Bbl) (1) $ 96.78 $ 91.69 $ 88.13 $ 89.17 Impairment recorded (pre-tax) (in thousands) $ — $ — $ — $ — $ — (1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices. |
Husky Acquisition | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Husky Acquisition (in thousands): Consideration: Cash consideration $ 42,085 Conveyance of undeveloped acreage — Total purchase price $ 42,085 Estimated Fair Value of Assets Acquired: Unproved properties $ 27,875 Proved properties 15,592 Other (1,382 ) Total assets acquired $ 42,085 |
Business Acquisition, Pro Forma Information | The following unaudited pro forma results for the years ended December 31, 2015 and 2014 show the effect on the Company's consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Years Ended December 31, 2015 2014 (in thousands, except (Unaudited) Revenues $ 115,147 $ 186,591 Net (Loss) Income $ (470,874 ) $ 46,370 (Loss) Income per share: Basic $ (6.07 ) $ 0.73 Diluted $ (6.07 ) $ 0.70 The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Husky Acquisition are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes. For the Year Ended December 31, 2015 (in thousands) Revenues $ 132 Excess of revenues over direct operating expenses $ 130 |
Chesapeake Assets | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Chesapeake acquisition (in thousands): Consideration: Cash consideration $ 69,371 Fair Value of Liabilities Assumed: Deferred tax liability 16,042 Total purchase price plus liabilities assumed $ 85,413 Estimated Fair Value of Assets Acquired: Unproved properties $ 86,327 Proved properties 26,756 Total assets acquired $ 113,083 Bargain purchase gain $ 27,670 |
WEHLU Purchase Agreement | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table summarizes the estimated fair value of the assets acquired in connection with the WEHLU Acquisition (in thousands): Consideration: Cash consideration $ 177,778 Estimated Fair Value of Assets Acquired: Unproved properties $ 13,026 Proved properties 164,752 Total assets acquired $ 177,778 |
Business Acquisition, Pro Forma Information | The following unaudited pro forma results for the year ended December 31, 2013 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For (in (Unaudited) Revenues $ 132,721 Net Loss $ (4,836 ) Loss per share: Basic $ (0.08 ) Diluted $ (0.08 ) The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Chesapeake and WEHLU Acquisitions are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes. Year Ended December 31, (in thousands) Revenues $ 11,292 Excess of revenues over direct operating expenses $ 7,591 |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | A summary of the activity related to the asset retirement obligation is as follows: For the years ended December 31, 2015 2014 2013 (in thousands) Asset retirement obligation, beginning of year $ 5,557 $ 6,063 $ 6,963 Liabilities incurred during period 302 305 3,416 Liabilities settled during period (37 ) (704 ) (126 ) Accretion expense 502 506 468 Revision in previous estimates and other 178 32 60 Deletions related to property disposals (416 ) (645 ) (4,718 ) Asset retirement obligation, end of year $ 6,086 $ 5,557 $ 6,063 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements, Recurring and Nonrecurring | The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014: Fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 50,074 $ — $ — $ 50,074 Commodity derivative contracts — — 24,869 24,869 Liabilities: Commodity derivative contracts — — (451 ) (451 ) Total $ 50,074 $ — $ 24,418 $ 74,492 Fair value as of December 31, 2014 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 11,008 $ — $ — $ 11,008 Commodity derivative contracts — — 27,502 27,502 Liabilities: Commodity derivative contracts — — — — Total $ 11,008 $ — $ 27,502 $ 38,510 |
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation | The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2015 and 2014. For the years ended December 31, 2015 2014 (in thousands) Balance at beginning of period $ 27,502 $ 3,764 Total gains included in earnings 24,589 19,569 Purchases 1,326 369 Issuances (1,313 ) — Settlements (1) (27,686 ) 3,800 Balance at end of period $ 24,418 $ 27,502 The amount of total (losses) gains for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2015 and 2014 $ (1,890 ) $ 23,902 (1) Included in gain (loss) on commodity derivatives contracts on the consolidated statement of operations. |
Derivative Instruments and He31
Derivative Instruments and Hedging Activity (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Information Regarding Deferred Put Premium Liabilities | The following table provides information regarding the deferred put premium liabilities for the periods indicated: For 2015 2014 (in thousands) Current commodity derivative premium put payable $ 3,194 $ 2,481 Long-term commodity derivative premium payable 2,788 4,702 Total unamortized put premium liabilities $ 5,982 $ 7,183 For the Years ended December 31, 2015 2014 (in thousands) Put premium liabilities, beginning balance $ 7,183 $ 7,145 Amortization of put premium liabilities (2,295 ) (145 ) Additional put premium liabilities 1,094 183 Put premium liabilities, ending balance $ 5,982 $ 7,183 |
Summary of Amortization of Deferred Put Premium Liabilities | The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2015: Amortization (in thousands) January to December 2016 $ 3,194 January to December 2017 1,819 January to December 2018 969 Total unamortized put premium liabilities $ 5,982 |
Summary of Information on the Location and Amounts of Derivative Fair Values and Derivative Gains and Losses | The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value December 31, Balance Sheet Location 2015 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 15,534 $ 19,687 Commodity derivative contracts Other assets 9,335 7,815 Commodity derivative contracts Long-term liabilities (451 ) — Total derivatives not designated as hedging instruments $ 24,418 $ 27,502 Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31, Location of Gain (Loss) Recognized in Income on Derivatives 2015 2014 2013 (in thousands) Derivatives Commodity derivative contracts Gain (loss) on commodity derivatives contracts $ 24,589 $ 19,569 $ (4,752 ) Total $ 24,589 $ 19,569 $ (4,752 ) |
Natural Gas | |
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions | As of December 31, 2015, the following natural gas transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in MMBtu’s) 2016 (1) Producer three-way 2,500 762,500 $ — $ 3.00 $ 2.25 $ 3.65 2016 Protective spread 2,000 732,000 $ 4.11 $ — $ 3.25 $ — 2016 Producer three-way 2,000 732,000 $ — $ 4.00 $ 3.25 $ 4.58 2016 Producer three-way 5,000 1,830,000 $ — $ 3.40 $ 2.65 $ 4.10 2016 Basis swap (2) 2,500 915,000 $ (1.10 ) $ — $ — $ — 2016 Basis swap (2) 2,500 915,000 $ (1.02 ) $ — $ — $ — 2016 Basis swap (2) 2,500 915,000 $ (1.00 ) $ — $ — $ — 2016 (3) Producer three-way collar 7,500 682,500 $ — $ 3.00 $ 2.50 $ 4.00 2016 (4) Producer three-way collar 5,000 1,375,000 $ — $ 3.00 $ 2.35 $ 4.00 2017 Short call 10,000 3,650,000 $ — $ — $ — $ 4.75 2017 Basis swap (2) 2,500 912,500 $ (1.02 ) $ — $ — $ — 2017 Basis swap (2) 2,500 912,500 $ (1.00 ) $ — $ — $ — 2017 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 2018 Basis swap (2) 2,500 912,500 $ (1.02 ) $ — $ — $ — 2018 Basis swap (2) 2,500 912,500 $ (1.00 ) $ — $ — $ — 2018 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 (1) For the period January to October 2016. (2) Represents basis swaps at the sales point of TetcoM2. (3) For the period January to March 2016. (4) For the period April to December 2016. |
Natural Gas Liquids | |
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions | As of December 31, 2015, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price (in Bbls) 2016 Fixed price swap 500 183,000 $ 20.79 |
Crude Oil | |
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions | As of December 31, 2015, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume (1) Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in Bbls) 2016 Costless three-way collar 275 100,650 $ 85.00 $ 65.00 $ 95.10 $ 96.50 2016 Costless three-way collar 330 120,780 $ 80.00 $ 65.00 $ 97.35 $ 97.80 2016 Costless three-way collar 450 164,700 $ 57.50 $ 42.50 $ 80.00 $ 96.25 2016 Put spread 550 201,300 $ 85.00 $ 65.00 $ — $ 96.50 2016 Put spread 300 109,800 $ 85.50 $ 65.50 $ — $ 97.80 2017 Costless three-way collar 280 102,200 $ 80.00 $ 65.00 $ 97.25 $ 96.25 2017 Costless three-way collar 242 88,330 $ 80.00 $ 60.00 $ 98.70 $ — 2017 Costless three-way collar 200 73,000 $ 60.00 $ 42.50 $ 85.00 $ — 2017 Put spread 500 182,500 $ 82.00 $ 62.00 $ — $ — 2017 Costless three-way collar 200 73,000 $ 57.50 $ 42.50 $ 76.13 $ 95.10 2018 (2) Put spread 425 103,275 $ 80.00 $ 60.00 $ — $ 97.35 (1) Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. (2) For the period January to August 2018. |
Capital Stock (Tables)
Capital Stock (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders Equity Note [Abstract] | |
Schedule of Issuances And Forfeitures Of Common Shares | The following table provides information regarding the issuances and forfeitures of the Company's common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated: For the Years Ended December 31, 2015 2014 Other stock issuances: Shares of restricted common stock granted 1,426,604 601,473 Shares of restricted common stock vested 1,422,670 1,915,242 Shares of common stock issued pursuant to PBUs vested, net of forfeitures 497,636 472,189 Stock options exercised — 7,500 Shares of restricted common stock surrendered upon vesting/exercise (1) 413,333 612,612 Shares of restricted common stock forfeited 119,499 47,398 (1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period. |
Equity Compensation Plans (Tabl
Equity Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable | The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2015: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at December 31, 2014 866,600 $ 11.75 Granted — — Exercised — — Canceled/Expired — — Forfeited — — Outstanding at December 31, 2015 866,600 $ 11.75 Options vested and exercisable at December 31, 2015 866,600 $ 11.75 1.19 $ — |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table summarizes information related to restricted shares at December 31, 2015: Shares Weighted Average Fair Value per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding non-vested restricted shares at December 31, 2014 2,411,914 $ 2.79 Granted 1,426,604 2.40 Vested (1,422,670 ) 2.67 Forfeited (119,499 ) 2.58 Outstanding non-vested restricted shares at December 31, 2015 2,296,349 $ 2.63 1.23 $ 3,008 |
Schedule of Share-based Compensation, Stock Options, Activity | The table below provides a summary of PBUs as of the date indicated: PBUs Fair per Unit Unvested PBUs at December 31, 2014 990,658 $ 3.19 Granted 741,146 3.01 Vested (448,637 ) 2.76 Forfeited — — Unvested PBUs at December 31, 2015 1,283,167 $ 3.24 |
Schedule of Unrecognized Compensation Cost, Nonvested Awards | As of December 31, 2015, the Company had approximately $3.2 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods: Amount (in thousands) 2016 $ 2,074 2017 1,075 2018 82 Total $ 3,231 |
Unvested restricted shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated: For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share data) Weighted average grant date fair value per restricted share $ 2.40 $ 5.85 $ 1.30 Total fair value of restricted shares vested $ 3,794 $ 3,497 $ 2,725 |
Interest Expense (Tables)
Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Interest Expense [Abstract] | |
Schedule Of Components Of Interest Expense | The following tables summarize the components of the Company's interest expense for the periods indicated: For the Years Ended December 31, 2015 2014 2013 (in thousands) Interest expense: Cash and accrued $ 30,981 $ 28,851 $ 14,130 Amortization of deferred financing costs (1)(2) 3,584 3,067 2,322 Capitalized interest (3,879 ) (4,347 ) (3,284 ) Total interest expense $ 30,686 $ 27,571 $ 13,168 (1) The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.” (2) The years ended December 31, 2015, 2014 and 2013 include $2.5 million, $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Contingency [Line Items] | |
Schedule of (Loss) Income before Income Taxes | The following table summarizes the components of the Company’s (loss) income before income taxes for the periods indicated: For the Year Ended December 31, 2015 2014 2013 (in thousands) United States $ (459,507 ) $ 50,953 $ 35,234 Foreign — — (1,934 ) Total income (loss) before income taxes $ (459,507 ) $ 50,953 $ 33,300 |
Schedule of Components of Deferred Income Tax Expense (Benefit) | The Company did not report any current provision for income taxes for the years ended December 31, 2015, 2014 and 2013. The Company’s deferred income tax expense (benefit) consists of the following for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in thousands) Deferred: Federal $ — $ — $ (15,299 ) State — — (743 ) Foreign — — — Income tax expense (benefit) $ — $ — $ (16,042 ) |
Schedule of Effective Income Tax Rate Reconciliation | The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated: For the Years Ended December 31, 2015 2014 2013 (in thousands) Expected income tax provision (benefit) at statutory rate $ (160,827 ) $ 17,833 $ 11,655 State tax, tax effected (7,799 ) 803 96 Stock-based compensation expense (benefit) 255 (1,291 ) 605 Tax effect of Canadian tax rate differences — — 193 Loss of Canadian tax attributes due to migration from Canada — — 19,825 Gain on acquisition of assets at fair value — — (9,685 ) Non-deductible costs of migration from Canada to U.S. — — 95 Other 17 38 (49 ) Other changes in valuation allowance 168,354 (17,383 ) (38,777 ) Actual income tax provision $ — $ — $ (16,042 ) |
US | |
Income Tax Contingency [Line Items] | |
Schedule of Deferred Tax Assets and Liabilities | The components of the Company’s U.S. deferred taxes are as follows: As of December 31, 2015 2014 (in thousands) Deferred tax asset (liability): Capital assets $ 10,485 $ (134,223 ) Stock-based compensation 4,243 4,504 Net operating loss carry forwards 187,963 164,056 Foreign tax credit carry forwards 50,681 50,681 Valuation allowance (253,372 ) (85,018 ) Net deferred tax asset $ — $ — |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share and share data) Net income (loss) attributable to common stockholders $ (473,980 ) $ 36,529 $ 39,964 Weighted average shares of common stock outstanding - basic 77,511,677 63,270,733 60,220,115 Incremental shares from unvested restricted shares — 2,451,903 2,869,490 Incremental shares from outstanding stock options — 97,491 26,095 Incremental shares from outstanding PBUs — 672,462 502,701 Weighted average shares of common stock outstanding - diluted 77,511,677 66,492,589 63,618,401 Net income (loss) per share of common stock attributable to common stockholders: Basic $ (6.11 ) $ 0.58 $ 0.66 Diluted $ (6.11 ) $ 0.55 $ 0.63 Shares of common stock excluded from denominator as anti-dilutive: Unvested restricted shares 177,663 34,058 3,505 Unvested PBUs 17,589 — — Total 195,252 34,058 3,505 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments And Contingencies Disclosure [Abstract] | |
Schedule of future minimum annual rental commitments | As of December 31, 2015, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: 2016 $ 660 2017 211 2018 176 $ 1,047 |
Concentration of Risk and Sig38
Concentration of Risk and Significant Customers (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Risks And Uncertainties [Abstract] | |
Schedules of Concentration of Risk, by Risk Factor | The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated: For the Years Ended December 31, 2015 2014 2013 Appalachian Basin 17 % 39 % 65 % Mid-Continent 83 % 61 % 26 % Hilltop Area, East Texas (1) — % — % 9 % (1) The Company’s working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013. The following table provides information regarding the Company’s significant customers whom accounted for more than 10% of the Company’s oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated: For the Years Ended December 31, 2015 2014 2013 SEI 22 % 50 % 56 % Sunoco 62 % 37 % 16 % |
Statement of Cash Flows - Sup39
Statement of Cash Flows - Supplemental Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Statement of Cash Flows Supplemental Information | The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements: For the Years Ended December 31, 2015 2014 2013 (in thousands) Cash paid for interest, net of capitalized amounts $ 26,859 $ 24,632 $ 7,341 Non-cash transactions: Capital expenditures (excluded from) included in accounts payable and accrued drilling costs $ (26,228 ) $ 12,777 $ 582 Capital expenditures included in accounts receivable — 4,077 (4,077 ) Asset retirement obligation included in oil and natural gas properties 526 221 (1,302 ) Asset retirement obligation for property disposals (416 ) (645 ) (4,354 ) Application of advances to operators 11,445 58,326 19,755 Other 5 (11 ) 47 |
Quarterly Consolidated Financ40
Quarterly Consolidated Financial Data - Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Quarterly Financial Information | The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2015 and 2014: 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 34,372 $ 21,928 $ 28,386 $ 22,608 Income (loss) from operations (1) 8,172 (107,462 ) (180,272 ) (149,272 ) Income (loss) before provision for income taxes 614 (114,395 ) (188,201 ) (157,525 ) Net income (loss) 614 (114,395 ) (188,201 ) (157,525 ) Dividend on preferred stock 3,618 3,619 3,618 3,618 Net loss attributable to common stockholders (3,004 ) (118,014 ) (191,819 ) (161,143 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Diluted $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Weighted average shares of common stock outstanding: Basic 77,114,826 77,611,167 77,628,120 77,685,049 Diluted 77,114,826 77,611,167 77,628,120 77,685,049 (1) 2014 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 32,327 $ 35,897 $ 41,746 $ 61,448 Income from operations 8,497 12,539 20,413 37,063 Income before provision for income taxes 1,611 5,627 13,425 30,290 Net income 1,611 5,627 13,425 30,290 Dividend on preferred stock 3,576 3,611 3,618 3,619 Net (loss) income attributable to common stockholders (1,965 ) 2,016 9,807 26,671 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (0.03 ) $ 0.03 $ 0.16 $ 0.35 Diluted $ (0.03 ) $ 0.03 $ 0.15 $ 0.34 Weighted average shares of common stock outstanding: Basic 58,204,532 58,702,982 60,006,903 75,994,979 Diluted 58,204,532 61,922,874 63,399,446 78,577,762 |
Supplemental Oil and Gas Disc41
Supplemental Oil and Gas Disclosures - Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Reserve Quantities [Line Items] | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure | The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities in the U.S. for the periods indicated: As of December 31, 2015 2014 2013 (in thousands) Proved properties: $ 1,286,373 $ 1,124,367 $ 935,773 Total proved properties 1,286,373 1,124,367 935,773 Unproved properties: 92,609 128,274 96,220 Total unproved properties 92,609 128,274 96,220 Total oil and natural gas properties 1,378,982 1,252,641 1,031,993 Less: Impairment of proved oil and natural gas properties (764,817 ) (337,939 ) (337,939 ) Accumulated depreciation, depletion and amortization (286,020 ) (223,555 ) (177,790 ) Net capitalized costs $ 328,145 $ 691,147 $ 516,264 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure | The following table sets forth costs incurred related to the Company’s oil and natural gas activities in the U.S. for the periods indicated: For the years ended December 31, 2015 2014 2013 (in thousands) Property acquisition Proved (1) $ 15,615 $ — $ 189,594 Unproved (2) 50,434 41,475 71,472 Exploration 53,290 127,384 36,893 Development 54,316 57,913 53,058 Total costs incurred $ 173,655 $ 226,772 $ 351,017 (1) The 2013 property acquisition costs exclude a downward adjustment of $2.6 million for fair value of acquisition. (2) The 2013 property acquisition costs exclude $46.3 million of adjustment for fair value of acquisition. |
Results of Operations for Oil and Gas Producing Activities Disclosure | The following table sets forth the Company’s results of operations for oil and natural gas producing activities in the U.S. for the periods indicated: For the Year Ended December 31, 2015 2014 2013 (in thousands, except per Mcfe data) Oil, condensate, natural gas and NGLs sales, including commodity derivatives $ 107,294 $ 171,418 $ 87,755 Production expenses (28,792 ) (29,735 ) (18,113 ) Impairment of oil and natural gas properties (426,878 ) — — Depreciation, depletion and amortization (62,465 ) (45,765 ) (32,158 ) Results of producing activities $ (410,841 ) $ 95,918 $ 37,484 Depreciation, depletion and amortization per MBoe $ 12.67 $ 12.34 $ 9.94 |
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure | For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations: For the Years Ended December 31, 2015 2014 2013 Natural gas, per MMBtu Henry Hub $ 2.59 $ 4.35 $ 3.67 Oil, per barrel: WTI spot $ 50.28 $ 94.99 $ 96.78 |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2015, 2014 and 2013: Change in Proved Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) Proved reserves as of December 31, 2012 3,394 131,010 4,922 30,152 2013 Activity: Extensions and discoveries (4) 4,385 52,750 2,306 15,483 Revisions of previous estimates (337 ) 8,114 714 1,729 Production (515 ) (13,366 ) (494 ) (3,237 ) Purchases in place 7,796 26,961 2,350 14,639 Sales in place (5 ) (24,759 ) — (4,132 ) Proved reserves as of December 31, 2013 14,718 180,710 9,798 54,634 2014 Activity: Extensions and discoveries (5) 13,137 121,672 9,394 42,810 Revisions of previous estimates 1,780 (2,465 ) 7,205 8,574 Production (975 ) (11,598 ) (800 ) (3,708 ) Sales in place (24 ) (1,314 ) (4 ) (247 ) Proved reserves as of December 31, 2014 28,636 287,005 25,593 102,063 2015 Activity: Extensions and discoveries (6) 4,777 14,114 2,244 9,374 Revisions of previous estimates (7) (8,962 ) (182,600 ) (13,873 ) (53,268 ) Production (1,425 ) (13,759 ) (1,212 ) (4,931 ) Purchases in place 1,270 4,965 873 2,971 Sales in place (94 ) (1,274 ) (26 ) (332 ) Proved reserves as of December 31, 2015 24,202 108,451 13,599 55,877 (1) Thousand barrels (2) Million cubic feet or million cubic feet equivalent, as applicable (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. ( 4 ) Of the 2013 extensions and discoveries, 74% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. ( 5 ) Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. ( 6 ) All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. ( 7 ) The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. Proved Developed and Undeveloped Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) December 31, 2013 Proved developed reserves 5,834 114,195 6,025 30,892 Proved undeveloped reserves 8,884 66,515 3,773 23,742 Total 14,718 180,710 9,798 54,634 December 31, 2014 Proved developed reserves 6,968 114,564 10,726 36,789 Proved undeveloped reserves 21,668 172,441 14,867 65,274 Total 28,636 287,005 25,593 102,063 December 31, 2015 Proved developed reserves 7,181 77,966 8,240 28,415 Proved undeveloped reserves 17,021 30,485 5,359 27,462 Total 24,202 108,451 13,599 55,877 (1) Thousand barrels (2) Million cubic feet or million cubic feet equivalent, as applicable (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. . |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves in the U.S. is presented below (in thousands): December 31, 2013: Future cash inflows $ 2,103,023 Future production costs (588,568 ) Future development costs (296,666 ) Future income taxes (215,502 ) Future net cash flows 1,002,287 10% annual discount for estimated timing of cash flows (486,458 ) Standardized measure of discounted future cash flows $ 515,829 December 31, 2014: Future cash inflows $ 3,855,227 Future production costs (1,048,554 ) Future development costs (611,602 ) Future income taxes (486,593 ) Future net cash flows 1,708,478 10% annual discount for estimated timing of cash flows (891,739 ) Standardized measure of discounted future cash flows $ 816,739 December 31, 2015: Future cash inflows $ 1,425,734 Future production costs (547,484 ) Future development costs (365,123 ) Future income taxes (1) — Future net cash flows 513,127 10% annual discount for estimated timing of cash flows (283,324 ) Standardized measure of discounted future cash flows $ 229,803 (1) No future taxes payable has been included in the determination of discounted future net cash flows for 2015 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows. |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows | The principal sources of changes in the standardized measure of future net cash flows are as follows (in thousands): December 31, 2012 $ 206,809 Extensions and discoveries, less related costs 196,448 Sale of natural gas and oil, net of production costs (74,394 ) Purchases of reserves in place 247,208 Sales of reserves in place (9,063 ) Revisions of previous quantity estimates 6,191 Net change in income tax (76,701 ) Net change in prices and production costs 79,820 Accretion of discount 1,211 Development costs incurred 23,567 Net change in estimated future development costs (97,461 ) Change in production rates (timing) and other 12,194 December 31, 2013 $ 515,829 Extensions and discoveries, less related costs 369,806 Sale of natural gas and oil, net of production costs (122,114 ) Sales of reserves in place (1,475 ) Revisions of previous quantity estimates 101,044 Net change in income tax (95,245 ) Net change in prices and production costs 59,786 Accretion of discount (3,996 ) Development costs incurred 37,461 Net change in estimated future development costs (1,276 ) Change in production rates (timing) and other (43,081 ) December 31, 2014 $ 816,739 Extensions and discoveries, less related costs 71,547 Sale of natural gas and oil, net of production costs (53,914 ) Purchases of reserves in place 9,937 Sales of reserves in place (4,853 ) Revisions of previous quantity estimates (324,036 ) Net change in income tax 171,946 Net change in prices and production costs (604,074 ) Accretion of discount 98,869 Development costs incurred 10,500 Net change in estimated future development costs 31,131 Change in production rates (timing) and other 6,011 December 31, 2015 $ 229,803 |
Key Natural Gas and Oil Prices | |
Reserve Quantities [Line Items] | |
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure | The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves: As of December 31, 2015 2014 Natural gas (per MMBtu): Henry Hub $ 2.59 $ 4.35 Oil (per Bbl): WTI spot $ 50.28 $ 94.99 |
Description Of Business (Narrat
Description Of Business (Narrative) (Details) $ in Thousands | Feb. 19, 2016USD ($) | Dec. 31, 2015USD ($)well | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Exploratory Wells Drilled [Line Items] | ||||
Proceeds from sale of oil and natural gas properties | $ 47,314 | $ 5,530 | $ 112,201 | |
Appalchian Basin | Subsequent Event | ||||
Exploratory Wells Drilled [Line Items] | ||||
Proceeds from sale of oil and natural gas properties | $ 80,000 | |||
Utica Shale and Point Pleasant | ||||
Exploratory Wells Drilled [Line Items] | ||||
Successful dry gas wells drilled | well | 2 |
Summary of Significant Accoun43
Summary of Significant Accounting Policies (Narrative) (Details) | Mar. 09, 2016USD ($) | Feb. 19, 2016USD ($) | Dec. 31, 2015USD ($)well | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jun. 30, 2017 | Jun. 30, 2016 | Apr. 10, 2016USD ($) | Dec. 31, 2012USD ($) |
Accounting Policies [Line Items] | |||||||||
Proceeds from sale of oil and natural gas properties | $ 47,314,000 | $ 5,530,000 | $ 112,201,000 | ||||||
Cash and cash equivalents | 50,074,000 | 11,008,000 | 32,393,000 | $ 8,901,000 | |||||
Allowance for doubtful accounts | $ 0 | 0 | 507,000 | $ 546,000 | |||||
Discount rate for oil and natural gas prices held constant | 10.00% | ||||||||
Capitalized interest | $ 3,900,000 | $ 4,300,000 | $ 3,300,000 | ||||||
Expected Forfeitures (percentage) | 17.50% | 25.50% | 14.00% | ||||||
Amendment No. 8 | |||||||||
Accounting Policies [Line Items] | |||||||||
Revolving credit facility borrowing base | $ 200,000,000 | ||||||||
Maximum | Furniture and equipment | |||||||||
Accounting Policies [Line Items] | |||||||||
Estimated useful lives | 7 years | ||||||||
Minimum | Furniture and equipment | |||||||||
Accounting Policies [Line Items] | |||||||||
Estimated useful lives | 3 years | ||||||||
Scenario Forecast | Amendment No. 8 | |||||||||
Accounting Policies [Line Items] | |||||||||
Leverage ratio | 2 | 2.50 | |||||||
Interest coverage ratio | 250.00% | 110.00% | |||||||
Revolving credit facility borrowing base | $ 100,000,000 | ||||||||
Scenario Forecast | Amendment No. 8 | Eurodollar | |||||||||
Accounting Policies [Line Items] | |||||||||
Applicable interest margin (percentage) | 4.00% | ||||||||
Scenario Forecast | Amendment No. 8 | Reference Rate | |||||||||
Accounting Policies [Line Items] | |||||||||
Applicable interest margin (percentage) | 3.00% | ||||||||
Scenario Forecast | Maximum | Amendment No. 8 | |||||||||
Accounting Policies [Line Items] | |||||||||
Leverage ratio | 4 | ||||||||
Canada | |||||||||
Accounting Policies [Line Items] | |||||||||
Number of gas wells | well | 2 | ||||||||
Subsequent Event | Amendment No. 8 | |||||||||
Accounting Policies [Line Items] | |||||||||
Revolving credit facility borrowing base | $ 180,000,000 | ||||||||
Threshold for automatic reductions of the borrowing base in connection with asset sales | 5,000,000 | ||||||||
Threshold for lenders consent requirement in connection with asset sales | $ 5,000,000 | ||||||||
Subsequent Event | Appalchian Basin | |||||||||
Accounting Policies [Line Items] | |||||||||
Proceeds from sale of oil and natural gas properties | $ 80,000,000 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies (Schedule of Allowance for Doubtful Accounts) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||
Allowance for doubtful accounts, beginning of year | $ 0 | $ 507,000 | $ 546,000 |
Expense | 0 | 0 | 0 |
Reductions/write-offs | (507,000) | (39,000) | |
Allowance for doubtful accounts, end of year | $ 0 | $ 0 | $ 507,000 |
Summary of Significant Accoun45
Summary of Significant Accounting Policies (Schedule of Deferred Financing Costs) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Policies [Abstract] | ||
Deferred charges | $ 4,474 | $ 3,664 |
Accumulated amortization | (2,116) | (1,078) |
Deferred charges, net | $ 2,358 | $ 2,586 |
Property, Plant And Equipment46
Property, Plant And Equipment (Schedule of Property Plant and Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Line Items] | ||
Proved properties | $ 1,286,373 | $ 1,124,367 |
Total oil and natural gas properties | 1,378,982 | 1,252,641 |
Total property and equipment | 1,382,050 | 1,255,651 |
Impairment of proved natural gas and oil properties | (764,817) | (337,939) |
Accumulated depreciation, depletion and amortization | (288,299) | (225,412) |
Total accumulated depreciation, depletion and amortization | (1,053,116) | (563,351) |
Total property, plant and equipment, net | 328,934 | 692,300 |
Total oil and natural gas properties | ||
Property, Plant and Equipment [Line Items] | ||
Unproved properties | 92,609 | 128,274 |
Proved properties | 1,286,373 | 1,124,367 |
Total oil and natural gas properties | 1,378,982 | 1,252,641 |
Furniture and equipment | ||
Property, Plant and Equipment [Line Items] | ||
Total property and equipment | $ 3,068 | $ 3,010 |
Property, Plant and Equipment47
Property, Plant and Equipment (Narrative) (Details) Boe in Millions | Feb. 19, 2016USD ($) | Dec. 16, 2015USD ($) | Oct. 14, 2015USD ($)awell | Nov. 15, 2013USD ($) | Jul. 02, 2013USD ($)a | Jun. 07, 2013USD ($) | Jan. 01, 2013USD ($) | Sep. 30, 2010USD ($) | Dec. 31, 2015USD ($)Boewell$ / bbl$ / Mcf | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jul. 06, 2015USD ($)awell | Oct. 02, 2013a | Sep. 04, 2013a | Aug. 06, 2013USD ($) | Mar. 28, 2013awell |
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Asset retirement obligation | $ 2,400,000 | $ 2,400,000 | $ 3,400,000 | |||||||||||||
Reclassification of unproved properties to proved properties | $ 14,400,000 | 3,300,000 | ||||||||||||||
Estimated proved reserves volume | Boe | 55.9 | |||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 47,314,000 | 5,530,000 | 112,201,000 | |||||||||||||
Percentage difference of fair value to purchase price | 6.00% | |||||||||||||||
Assets, fair value adjustment | $ 0 | |||||||||||||||
Gain on acquisition of assets at fair value, net of income taxes | $ 0 | 0 | $ 27,670,000 | |||||||||||||
Gastar Exploration USA | Hunton Joint Venture | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Acquisition of oil and natural gas properties | $ 11,800,000 | |||||||||||||||
Transaction and integration costs | $ 133,000 | |||||||||||||||
Net acres (acres) | a | 12,800 | |||||||||||||||
Gastar Exploration USA | Atinum Participation Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Working interest In wells (percentage) | 50.00% | |||||||||||||||
Adjusted purchase price | $ 70,000,000 | |||||||||||||||
Percentage of lease bonuses and third party leasing costs up to 20 million to be received | 10.00% | |||||||||||||||
Percentage of lease bonuses and third party leasing costs above 20 million to be received | 5.00% | |||||||||||||||
Percentage of obligated share in future acquisitions | 50.00% | |||||||||||||||
Term of development program | 3 years | |||||||||||||||
Participation agreement expiry date | Nov. 1, 2015 | |||||||||||||||
Gastar Exploration USA | Atinum Participation Agreement | Minimum | Before Price Decline | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Productive gas wells, number of wells to be drilled | well | 60 | |||||||||||||||
Gastar Exploration USA | Atinum Participation Agreement | Minimum | After Price Decline | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Productive gas wells, number of wells to be drilled | well | 51 | |||||||||||||||
Gastar Exploration USA | Atinum Participation Agreement | Maximum | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Third party oil and gas leasing cost | $ 20,000,000 | |||||||||||||||
Mid Continent Divestiture | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Net wells | well | 16.7 | |||||||||||||||
Gross wells | well | 38 | |||||||||||||||
Gross acres (acres) | a | 29,500 | |||||||||||||||
Net acres (acres) | a | 19,200 | |||||||||||||||
Net cash purchase price of divestiture | $ 46,500,000 | |||||||||||||||
Hunton Divestiture | Gastar Exploration USA | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Net acres (acres) | a | 76,000 | |||||||||||||||
Net cash purchase price of divestiture | $ 57,000,000 | |||||||||||||||
Husky Acquisition | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Gross wells | well | 103 | |||||||||||||||
Net wells | well | 10.2 | |||||||||||||||
Net acres | a | 11,000 | |||||||||||||||
Acquisition of oil and natural gas properties | $ 43,300,000 | |||||||||||||||
Escrow for pending resolution of title defects and purchase of overrides recorded in other assets | 4,300,000 | |||||||||||||||
Purchase and sale agreement amendment date | Dec. 16, 2016 | |||||||||||||||
Cash consideration | 42,085,000 | $ 42,100,000 | ||||||||||||||
Fair market valuation amount | 44,600,000 | |||||||||||||||
Husky Acquisition | General and Administrative Expense | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Transaction and integration costs | $ 1,100,000 | |||||||||||||||
Chesapeake Assets | Gastar Exploration USA | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Cash consideration | $ 69,400,000 | |||||||||||||||
Fair market valuation amount | 113,100,000 | |||||||||||||||
Net acres (acres) | a | 157,000 | |||||||||||||||
Productive conventional wells (wells) | well | 206 | |||||||||||||||
Gain on acquisition of assets at fair value, net of income taxes | 27,670,000 | |||||||||||||||
Income tax expense recognized | 16,042,000 | |||||||||||||||
Chesapeake Assets | General and Administrative Expense | Gastar Exploration USA | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Transaction and integration costs | $ 2,100,000 | |||||||||||||||
Oklahoma Oil and Gas Leasehold Interests | Gastar Exploration USA | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Net acres (acres) | a | 1,850 | |||||||||||||||
WEHLU Purchase Agreement | Gastar Exploration USA | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Cash consideration | $ 177,778,000 | |||||||||||||||
Transaction and integration costs | 286,000 | |||||||||||||||
Net acres (acres) | a | 24,000 | |||||||||||||||
Working interest In wells (percentage) | 98.30% | |||||||||||||||
Net revenue interest | 80.50% | |||||||||||||||
Preliminary assessment of fair value of WEHLU Assets | $ 176,800,000 | |||||||||||||||
Crude Oil And N G L Per Barrel | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Decrease in average reserve price | $ / bbl | 46.26 | |||||||||||||||
Natural Gas Per Thousand Cubic Feet | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Decrease in average reserve price | $ / Mcf | 2.40 | |||||||||||||||
Appalchian Basin | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Reclassification of unproved properties to proved properties | $ 14,400,000 | |||||||||||||||
Appalchian Basin | Subsequent Event | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 80,000,000 | |||||||||||||||
East Texas | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Reclassification of unproved properties to proved properties | $ 3,300,000 | |||||||||||||||
East Texas | Gastar Exploration USA | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 42,900,000 | |||||||||||||||
Gross acres (acres) | a | 31,800 | |||||||||||||||
Net acres (acres) | a | 16,300 | |||||||||||||||
Marcellus Shale | Gastar Exploration USA | Atinum Participation Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Productive conventional wells (wells) | well | 74 | |||||||||||||||
Utica Shale | Gastar Exploration USA | Atinum Participation Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Productive conventional wells (wells) | well | 2 | |||||||||||||||
Appalachian Basin | Subsequent Event | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 80,000,000 |
Property, Plant and Equipment48
Property, Plant and Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Unproved properties, excluded from amortization: | ||
Drilling in progress costs | $ 1,533 | $ 29,193 |
Acreage acquisition costs | 82,560 | 91,362 |
Capitalized interest | 8,516 | 7,719 |
Total unproved properties excluded from amortization | $ 92,609 | $ 128,274 |
Property, Plant and Equipment49
Property, Plant and Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Sep. 30, 2015USD ($)$ / MMBTU$ / bbl | Jun. 30, 2015USD ($)$ / MMBTU$ / bbl | Mar. 31, 2015$ / MMBTU$ / bbl | Dec. 31, 2014$ / MMBTU$ / bbl | Sep. 30, 2014$ / MMBTU$ / bbl | Jun. 30, 2014$ / MMBTU$ / bbl | Mar. 31, 2014$ / MMBTU$ / bbl | Dec. 31, 2013$ / MMBTU$ / bbl | Sep. 30, 2013$ / MMBTU$ / bbl | Jun. 30, 2013$ / MMBTU$ / bbl | Mar. 31, 2013$ / MMBTU$ / bbl | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | ||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Impairment recorded (pre-tax) (in thousands) | $ | $ 144,760 | $ 181,966 | $ 100,152 | $ 426,878 | $ 0 | $ 0 | ||||||||||
Natural Gas Per Thousand Cubic Feet | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Average price per Mcfe | $ / MMBTU | [1] | 2.59 | 3.06 | 3.39 | 3.88 | 4.35 | 4.24 | 4.10 | 3.99 | 3.67 | 3.61 | 3.44 | 2.95 | |||
Crude Oil And N G L Per Barrel | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Average price per Mcfe | $ / bbl | [1] | 50.28 | 59.21 | 71.68 | 82.72 | 94.99 | 99.08 | 100.11 | 98.30 | 96.78 | 91.69 | 88.13 | 89.17 | |||
[1] | For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices. |
Property, Plant And Equipment50
Property, Plant And Equipment (Schedule of Assets Acquired) (Details) - USD ($) $ in Thousands | Dec. 16, 2015 | Oct. 14, 2015 | Nov. 15, 2013 | Jun. 07, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Business Acquisition [Line Items] | |||||||
Gain on acquisition of assets at fair value, net of income taxes | $ 0 | $ 0 | $ 27,670 | ||||
Husky Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | $ 42,085 | ||||||
Total purchase price | 42,085 | $ 42,100 | |||||
Unproved properties | 27,875 | ||||||
Proved properties | 15,592 | ||||||
Other | (1,382) | ||||||
Total assets acquired | $ 42,085 | ||||||
Chesapeake Assets | Gastar Exploration USA | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | $ 69,371 | ||||||
Total purchase price | 69,400 | ||||||
Unproved properties | 86,327 | ||||||
Proved properties | 26,756 | ||||||
Total assets acquired | 113,083 | ||||||
Deferred tax liability | 16,042 | ||||||
Total purchase price plus liabilities assumed | 85,413 | ||||||
Gain on acquisition of assets at fair value, net of income taxes | $ 27,670 | ||||||
WEHLU Purchase Agreement | Gastar Exploration USA | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | $ 177,778 | ||||||
Total purchase price | 177,778 | ||||||
Unproved properties | 13,026 | ||||||
Proved properties | 164,752 | ||||||
Total assets acquired | $ 177,778 |
Property, Plant And Equipment51
Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Husky Acquisition | |||
Business Acquisition [Line Items] | |||
Revenues | $ 115,147 | $ 186,591 | |
Net (Loss) Income | $ (470,874) | $ 46,370 | |
Loss per share, Basic | $ (6.07) | $ 0.73 | |
Loss per share, Diluted | $ (6.07) | $ 0.70 | |
Revenues | $ 132 | ||
Excess of revenues over direct operating expenses | $ 130 | ||
WEHLU Purchase Agreement | Gastar Exploration USA | |||
Business Acquisition [Line Items] | |||
Revenues | $ 132,721 | ||
Net (Loss) Income | $ (4,836) | ||
Loss per share, Basic | $ (0.08) | ||
Loss per share, Diluted | $ (0.08) | ||
Revenues | $ 11,292 | ||
Excess of revenues over direct operating expenses | $ 7,591 |
Long-Term Debt (Narrative) (Det
Long-Term Debt (Narrative) (Details) | Mar. 09, 2016USD ($) | Jun. 07, 2013 | May. 15, 2013USD ($) | Dec. 31, 2015USD ($) | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Sep. 29, 2016 | Jun. 30, 2016 | Jun. 29, 2016 | Apr. 10, 2016USD ($) | Mar. 31, 2016 | Mar. 30, 2016 | Mar. 09, 2015USD ($) | Mar. 08, 2015USD ($) | Nov. 15, 2013 |
Line of Credit Facility [Line Items] | |||||||||||||||||
Waiver expiration date | Mar. 10, 2016 | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Interest rate description | borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent (ii) the federal funds rate plus 50 basis points or (iii) LIBOR plus 1.0%. | ||||||||||||||||
Annual commitment fee (percentage) | 0.50% | ||||||||||||||||
Revolving credit facility scheduled maturity date | Nov. 14, 2017 | ||||||||||||||||
Percentage of stock foreign subsidiary pledged as collateral for credit facility (percentage) | 65.00% | ||||||||||||||||
Line of credit facility covenant compliance EBITDA to Interest Expense Ratio on a four quarter rolling basis | 250.00% | ||||||||||||||||
Revolving credit facility borrowing base | $ 200,000,000 | $ 145,000,000 | |||||||||||||||
Borrowings outstanding | $ 200,000,000 | ||||||||||||||||
Scheduled borrowing base redetermination month and year | 2016-05 | ||||||||||||||||
Increase in current borrowing base | $ 50,000,000 | ||||||||||||||||
Increase in adjusted consolidated net tangibles assets | 17.50% | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | Minimum | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Line of credit facility covenant compliance Current Ratio | 100.00% | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | Maximum | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Line of credit facility covenant compliance indebtedness to EBITDA Ratio | 400.00% | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | Federal Funds Rate | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Applicable interest margin (percentage) | 0.50% | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | LIBOR | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Applicable interest margin (percentage) | 1.00% | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | Reference Rate | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Applicable interest margin (percentage) | 3.00% | ||||||||||||||||
Second Amended and Restated Revolving Credit Facility | Eurodollar | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Applicable interest margin (percentage) | 4.00% | ||||||||||||||||
Amendment to Second Amended and Restated Revolving Credit Facility | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Revolving credit facility borrowing base | $ 200,000,000 | ||||||||||||||||
Amendment to Second Amended and Restated Revolving Credit Facility | Scenario Forecast | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Leverage ratio | 4 | 4.25 | 4.75 | 5 | 5.25 | 4 | |||||||||||
Interest coverage ratio | 250.00% | 200.00% | |||||||||||||||
Senior Secured Notes Due 2018 | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 325,000,000 | ||||||||||||||||
Debt instrument interest rate description | The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. | ||||||||||||||||
Interest rate | 8.625% | 8.625% | |||||||||||||||
Debt instrument maturity date | May 15, 2018 | ||||||||||||||||
Percentage of aggregate principal amount | 101.00% | ||||||||||||||||
Long-term debt | $ 317,800,000 | ||||||||||||||||
Unamortized discounts | 7,200,000 | ||||||||||||||||
Senior Secured Notes Due 2018 | Scenario Forecast | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Leverage ratio | 2 | 2.25 | |||||||||||||||
Amendment No. 8 | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Revolving credit facility borrowing base | $ 200,000,000 | ||||||||||||||||
Amendment No. 8 | Subsequent Event | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Revolving credit facility borrowing base | $ 180,000,000 | ||||||||||||||||
Threshold for automatic reductions of the borrowing base in connection with asset sales | 5,000,000 | ||||||||||||||||
Threshold for lenders consent requirement in connection with asset sales | $ 5,000,000 | ||||||||||||||||
Amendment No. 8 | Scenario Forecast | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Revolving credit facility borrowing base | $ 100,000,000 | ||||||||||||||||
Leverage ratio | 2 | 2.50 | |||||||||||||||
Interest coverage ratio | 250.00% | 110.00% | |||||||||||||||
Amendment No. 8 | Maximum | Scenario Forecast | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Leverage ratio | 4 | ||||||||||||||||
Amendment No. 8 | Reference Rate | Scenario Forecast | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Applicable interest margin (percentage) | 3.00% | ||||||||||||||||
Amendment No. 8 | Eurodollar | Scenario Forecast | |||||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||||
Applicable interest margin (percentage) | 4.00% |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset retirement obligation, beginning of year | $ 5,557 | $ 6,063 | $ 6,963 |
Liabilities incurred during period | 302 | 305 | 3,416 |
Liabilities settled during period | (37) | (704) | (126) |
Accretion of asset retirement obligation | 502 | 506 | 468 |
Revision in previous estimates and other | 178 | 32 | 60 |
Deletions related to property disposals | (416) | (645) | (4,718) |
Asset retirement obligation, end of year | $ 6,086 | $ 5,557 | $ 6,063 |
Asset Retirement Obligation (Na
Asset Retirement Obligation (Narrative) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset retirement obligation | $ 89 | $ 82 |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Amount reclassified from unproved to proved properties | $ 14.4 | $ 3.3 |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of long-term debt | $ 377.5 | $ 330.6 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets: | ||
Cash and cash equivalents | $ 50,074 | $ 11,008 |
Assets, Commodity derivative contracts | 24,869 | 27,502 |
Liabilities: | ||
Liabilities, Commodity derivative contracts | (451) | |
Total | 74,492 | 38,510 |
Level 1 | ||
Assets: | ||
Cash and cash equivalents | 50,074 | 11,008 |
Liabilities: | ||
Total | 50,074 | 11,008 |
Level 3 | ||
Assets: | ||
Assets, Commodity derivative contracts | 24,869 | 27,502 |
Liabilities: | ||
Liabilities, Commodity derivative contracts | (451) | |
Total | $ 24,418 | $ 27,502 |
Fair Value Measurements (Net Ch
Fair Value Measurements (Net Change in Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
The amount of total (losses) gains for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2015 and 2014 | $ (1,900) | $ 23,900 | $ (10,000) | |
Fair Value, Measurements, Recurring | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Balance at beginning of period | 27,502 | 3,764 | ||
Total gains included in earnings | 24,589 | 19,569 | ||
Purchases | 1,326 | 369 | ||
Issuances | (1,313) | |||
Settlements | [1] | (27,686) | 3,800 | |
Balance at end of period | 24,418 | 27,502 | $ 3,764 | |
The amount of total (losses) gains for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2015 and 2014 | $ (1,890) | $ 23,902 | ||
[1] | Included in gain (loss) on commodity derivatives contracts on the consolidated statement of operations |
Derivative Instruments and He58
Derivative Instruments and Hedging Activity (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||
Change in fair value of commodity derivative contracts | $ (1.9) | $ 23.9 | $ (10) |
Derivative Instruments and He59
Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details) | 12 Months Ended | |
Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 5,000 | |
Total of Notional Volume (MMBtus) | MMBTU | 1,825,000 | |
Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | |
Short | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4 | |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 2.35 | |
Producer Three-way Collar 1 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | [1] |
Total of Notional Volume (MMBtus) | MMBTU | 762,500 | [1] |
Producer Three-way Collar 1 - 2016 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | [1] |
Producer Three-way Collar 1 - 2016 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 3.65 | [1] |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 2.25 | [1] |
Protective Spread 2 - Natural Gas 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU | 4.11 | |
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,000 | |
Total of Notional Volume (MMBtus) | MMBTU | 732,000 | |
Protective Spread 2 - Natural Gas 2016 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3.25 | |
Producer Three-way Collar 2 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,000 | |
Total of Notional Volume (MMBtus) | MMBTU | 732,000 | |
Producer Three-way Collar 2 - 2016 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 4 | |
Producer Three-way Collar 2 - 2016 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4.58 | |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3.25 | |
Producer Three-way Collar 3 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 5,000 | |
Total of Notional Volume (MMBtus) | MMBTU | 1,830,000 | |
Producer Three-way Collar 3 - 2016 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3.40 | |
Producer Three-way Collar 3 - 2016 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4.10 | |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 2.65 | |
Basis Swap 1 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 915,000 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1.10) | |
Basis Swap 2 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 915,000 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1.02) | |
Basis Swap 3 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 915,000 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1) | |
Producer Three-way Collar 4 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 7,500 | [2] |
Total of Notional Volume (MMBtus) | MMBTU | 682,500 | [2] |
Producer Three-way Collar 4 - 2016 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | [2] |
Producer Three-way Collar 4 - 2016 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4 | [2] |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 2.50 | [2] |
Producer Three-way Collar 5 - 2016 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 5,000 | [3] |
Total of Notional Volume (MMBtus) | MMBTU | 1,375,000 | [3] |
Producer Three-way Collar 5 - 2016 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | [3] |
Producer Three-way Collar 5 - 2016 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4 | [3] |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 2.35 | [3] |
Short Call To Be Settled In Twenty Seventeen | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 10,000 | |
Total of Notional Volume (MMBtus) | MMBTU | 3,650,000 | |
Short Call To Be Settled In Twenty Seventeen | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4.75 | |
Basis Swap 1 - 2017 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 912,500 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1.02) | |
Basis Swap 2 - 2017 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 912,500 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1) | |
Producer Three-way Collar 1 - 2017 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 5,000 | |
Total of Notional Volume (MMBtus) | MMBTU | 1,825,000 | |
Producer Three-way Collar 1 - 2017 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | |
Producer Three-way Collar 1 - 2017 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4 | |
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 2.35 | |
Basis Swap 1 - 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 912,500 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1.02) | |
Basis Swap 2 - 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | MMBTU | 2,500 | |
Total of Notional Volume (MMBtus) | MMBTU | 912,500 | |
Base Fixed Price (Price per MMBtu or Bbl), Reduction | $ / MMBTU | (1) | |
Fixed Price Swap - Natural Gas Liquids 2016 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 500 | |
Total of Notional Volume (Bbls) | bbl | 183,000 | |
Base Fixed Price (Price per MMBtu or Bbl) | 20.79 | |
Crude Oil | Costless Three-way Collar 1 - 2016 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 275 | [4] |
Total of Notional Volume (Bbls) | bbl | 100,650 | |
Base Fixed Price (Price per MMBtu or Bbl) | 85 | |
Crude Oil | Costless Three-way Collar 1 - 2016 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 65 | |
Crude Oil | Costless Three-way Collar 1 - 2016 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 95.10 | |
Ceiling (Short) (Price per MMBtu or Bbl) | 96.50 | |
Crude Oil | Costless Three-way Collar 2 - 2016 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 330 | [4] |
Total of Notional Volume (Bbls) | bbl | 120,780 | |
Base Fixed Price (Price per MMBtu or Bbl) | 80 | |
Crude Oil | Costless Three-way Collar 2 - 2016 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 65 | |
Crude Oil | Costless Three-way Collar 2 - 2016 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 97.35 | |
Ceiling (Short) (Price per MMBtu or Bbl) | 97.80 | |
Crude Oil | Costless Three-way Collar 3 - 2016 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 450 | [4] |
Total of Notional Volume (Bbls) | bbl | 164,700 | |
Base Fixed Price (Price per MMBtu or Bbl) | 57.50 | |
Crude Oil | Costless Three-way Collar 3 - 2016 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 42.50 | |
Crude Oil | Costless Three-way Collar 3 - 2016 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 80 | |
Ceiling (Short) (Price per MMBtu or Bbl) | 96.25 | |
Crude Oil | Put Spread 1 - 2016 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 550 | [4] |
Total of Notional Volume (Bbls) | bbl | 201,300 | |
Base Fixed Price (Price per MMBtu or Bbl) | 85 | |
Crude Oil | Put Spread 1 - 2016 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 65 | |
Crude Oil | Put Spread 1 - 2016 | Short | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | 96.50 | |
Crude Oil | Put Spread 2 - 2016 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 300 | [4] |
Total of Notional Volume (Bbls) | bbl | 109,800 | |
Base Fixed Price (Price per MMBtu or Bbl) | 85.50 | |
Crude Oil | Put Spread 2 - 2016 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 65.50 | |
Crude Oil | Put Spread 2 - 2016 | Short | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | 97.80 | |
Crude Oil | Costless Three-way Collar 1 - 2017 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 280 | [4] |
Total of Notional Volume (Bbls) | bbl | 102,200 | |
Base Fixed Price (Price per MMBtu or Bbl) | 80 | |
Crude Oil | Costless Three-way Collar 1 - 2017 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 65 | |
Crude Oil | Costless Three-way Collar 1 - 2017 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 97.25 | |
Ceiling (Short) (Price per MMBtu or Bbl) | 96.25 | |
Crude Oil | Costless Three-way Collar 2 - 2017 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 242 | [4] |
Total of Notional Volume (Bbls) | bbl | 88,330 | |
Base Fixed Price (Price per MMBtu or Bbl) | 80 | |
Crude Oil | Costless Three-way Collar 2 - 2017 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 60 | |
Crude Oil | Costless Three-way Collar 2 - 2017 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 98.70 | |
Crude Oil | Costless Three-way Collar 3 - 2017 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 200 | [4] |
Total of Notional Volume (Bbls) | bbl | 73,000 | |
Base Fixed Price (Price per MMBtu or Bbl) | 60 | |
Crude Oil | Costless Three-way Collar 3 - 2017 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 42.50 | |
Crude Oil | Costless Three-way Collar 3 - 2017 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 85 | |
Crude Oil | Put Spread 1 - 2017 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 500 | [4] |
Total of Notional Volume (Bbls) | bbl | 182,500 | |
Base Fixed Price (Price per MMBtu or Bbl) | 82 | |
Crude Oil | Put Spread 1 - 2017 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 62 | |
Crude Oil | Costless Three-way Collar 4 - 2017 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 200 | [4] |
Total of Notional Volume (Bbls) | bbl | 73,000 | |
Base Fixed Price (Price per MMBtu or Bbl) | 57.50 | |
Crude Oil | Costless Three-way Collar 4 - 2017 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 42.50 | |
Crude Oil | Costless Three-way Collar 4 - 2017 | Short | ||
Derivative [Line Items] | ||
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | 76.13 | |
Ceiling (Short) (Price per MMBtu or Bbl) | 95.10 | |
Crude Oil | Put Spread 1 - 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | bbl | 425 | [4],[5] |
Total of Notional Volume (Bbls) | bbl | 103,275 | [5] |
Base Fixed Price (Price per MMBtu or Bbl) | 80 | [5] |
Crude Oil | Put Spread 1 - 2018 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | 60 | [5] |
Crude Oil | Put Spread 1 - 2018 | Short | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | 97.35 | [5] |
[1] | For the period January to October 2016. | |
[2] | For the period January to March 2016. | |
[3] | For the period April to December 2016. | |
[4] | Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. | |
[5] | For the period January to August 2018. |
Derivative Instruments and He60
Derivative Instruments and Hedging Activity (Summary of Information Regarding Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||
Current commodity derivative premium put payable | $ 3,194 | $ 2,481 | ||
Long-term commodity derivative premium payable | 2,788 | 4,702 | ||
Total unamortized put premium liabilities | $ 5,982 | $ 7,183 | $ 5,982 | $ 7,183 |
Put Premium Liabilities [Roll Forward] | ||||
Put premium liabilities, beginning balance | 7,183 | 7,145 | ||
Amortization of put premium liabilities | (2,295) | (145) | ||
Additional put premium liabilities | 1,094 | 183 | ||
Put premium liabilities, ending balance | $ 5,982 | $ 7,183 |
Derivative Instruments and He61
Derivative Instruments and Hedging Activity (Summary of Amortization of Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||
January to December 2016 | $ 3,194 | ||
January to December 2017 | 1,819 | ||
January to December 2018 | 969 | ||
Total unamortized put premium liabilities | $ 5,982 | $ 7,183 | $ 7,145 |
Derivative Instruments and He62
Derivative Instruments and Hedging Activity (Summary of Information on the Location and Amounts of Derivative Fair Values and Derivative Gains and Losses) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivatives, Fair Value [Line Items] | |||
Gain (loss) on commodity derivatives contracts | $ 24,589 | $ 19,569 | $ (4,752) |
Commodity Contract | |||
Derivatives, Fair Value [Line Items] | |||
Gain (loss) on commodity derivatives contracts | 24,589 | 19,569 | (4,752) |
Commodity Contract | Gain (loss) on commodity derivatives contracts | |||
Derivatives, Fair Value [Line Items] | |||
Gain (loss) on commodity derivatives contracts | 24,589 | 19,569 | $ (4,752) |
Commodity Contract | Derivatives not designated as hedging instruments | |||
Derivatives, Fair Value [Line Items] | |||
Total derivatives not designated as hedging instruments | 24,418 | 27,502 | |
Commodity Contract | Current assets | Derivatives not designated as hedging instruments | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Assets | 15,534 | 19,687 | |
Commodity Contract | Other assets | Derivatives not designated as hedging instruments | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Assets | 9,335 | $ 7,815 | |
Commodity Contract | Long-term liabilities | Derivatives not designated as hedging instruments | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Liabilities | $ (451) |
Capital Stock (Narrative) (Deta
Capital Stock (Narrative) (Details) | Mar. 09, 2016 | Jan. 18, 2016Right$ / shares | Sep. 24, 2014USD ($)$ / sharesshares | Apr. 24, 2014shares | Jun. 07, 2013USD ($)shares | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)$ / sharesshares | Dec. 31, 2013USD ($)shares | May. 07, 2015USD ($) | Nov. 14, 2013$ / sharesshares | Oct. 25, 2013$ / sharesshares | Dec. 31, 2012shares | May. 24, 2011shares |
Class Of Stock [Line Items] | |||||||||||||
Common shares authorized for issuance (shares) | 275,000,000 | 275,000,000 | 275,000,000 | ||||||||||
Common stock, par value | $ / shares | $ 0.001 | $ 0.001 | $ 0.001 | ||||||||||
Common shares issued (shares) | 80,024,218 | 78,632,810 | |||||||||||
Proceeds from issuance of common shares, net of issuance costs | $ | $ 0 | $ 101,319,000 | $ 0 | ||||||||||
Aggregate offering price | $ | $ 50,000,000 | ||||||||||||
Issuance of shares - cash, net of offering costs (shares) | 0 | ||||||||||||
Dividend rights description | The Rights generally become exercisable on the earlier of (i) ten business days after any person or group obtains beneficial ownership of 4.9% of the Company’s outstanding common stock (an “Acquiring Person”) or (ii) ten business days after commencement of a tender or exchange offer resulting in any person or group becoming an Acquiring Person. | ||||||||||||
Exercise price description | In the event that, after a person or a group has become an Acquiring Person, the Company is acquired in a merger or other business combination transaction (or 50% or more of the Company’s assets or earning power are sold), proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then-current exercise price of the Right, that number of shares of common stock of the acquiring company having a market value at the time of that transaction equal to two times the exercise price | ||||||||||||
Rights exchange description | At any time after any person or group becomes an Acquiring Person, the Company may generally exchange each Right in whole or in part at an exchange ratio of two shares of common stock per outstanding Right, subject to adjustment. | ||||||||||||
Preferred stock, shares authorized | 40,000,000 | 40,000,000 | |||||||||||
Dividends on preferred stock | $ | $ 14,473,000 | $ 14,424,000 | 9,378,000 | ||||||||||
Common shares reserved for the exercise of stock options | 866,600 | ||||||||||||
Repurchase of common shares | $ | $ 0 | $ 0 | 9,753,000 | ||||||||||
Chesapeake Energy Corporation | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Amount paid to Chesapeake | $ | $ 10,800,000 | ||||||||||||
Repurchase of common shares | $ | $ 9,800,000 | ||||||||||||
Repurchase of common stock (shares) | 6,781,768 | ||||||||||||
PBUs | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Common shares reserved for the exercise of stock options (shares) | 1,283,167 | ||||||||||||
2006 Long-Term Stock Incentive Plan | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Shares reserved for issuance under LTIP | 3,000,000 | ||||||||||||
Shares available for future issuance (no more than) (shares) | 2,877,599 | ||||||||||||
Series C Preferred Stock | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Dividend payment terms | The dividend was paid to stockholders of record on January 28, 2016. Each Right entitles the holder, subject to the terms of the Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $6.96, subject to certain adjustments | ||||||||||||
Series A Preferred Stock | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | |||||||||||
Preferred stock, par value | $ / shares | $ 0.01 | $ 0.01 | |||||||||||
Preferred stock, dividend rate, percentage (percentage) | 8.625% | ||||||||||||
Redemption price | $ / shares | $ 25 | $ 25 | |||||||||||
Preferred stock, shares issued | 4,045,000 | 4,045,000 | |||||||||||
Preferred stock, shares outstanding | 4,045,000 | 4,045,000 | |||||||||||
Dividends on preferred stock | $ | $ 8,700,000 | $ 8,700,000 | 8,500,000 | ||||||||||
Series B Preferred Stock | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | |||||||||||
Preferred stock, par value | $ / shares | $ 0.01 | $ 0.01 | |||||||||||
Preferred stock, dividend rate, percentage (percentage) | 10.75% | ||||||||||||
Redemption price | $ / shares | $ 25 | $ 25 | |||||||||||
Preferred stock, shares issued | 2,140,000 | 2,140,000 | |||||||||||
Preferred stock, shares outstanding | 2,140,000 | 2,140,000 | |||||||||||
Dividends on preferred stock | $ | $ 5,800,000 | $ 5,800,000 | $ 847,000 | ||||||||||
Preferred stock redemption price per share | $ / shares | $ 25 | ||||||||||||
Period after change in control to redeem preferred stock | 90 days | ||||||||||||
Option to convert shares of Series B Preferred Stock | $ / shares | $ 11.5207 | ||||||||||||
Subsequent Event | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Number of rights issued on dividend declared | Right | 1 | ||||||||||||
Percent of ownership in outstanding common stock | 4.90% | ||||||||||||
Rights redemption price per right | $ / shares | $ 0.001 | ||||||||||||
Expiration date of rights | Jan. 18, 2019 | ||||||||||||
Preferred stock dividends payment conditions applied commencement period | 2016-04 | ||||||||||||
Subsequent Event | Series C Preferred Stock | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Preferred stock, dividend rate, per share | $ / shares | $ 6.96 | ||||||||||||
Dividends payable record date | Jan. 28, 2016 | ||||||||||||
Subsequent Event | Series A Preferred Stock | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Fixed rate preferred dividend increases percentage if suspension more than one year | 2.00% | ||||||||||||
Subsequent Event | Series B Preferred Stock | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Fixed rate preferred dividend increases percentage if suspension more than one year | 2.00% | ||||||||||||
Gastar Exploration USA | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Common shares authorized for issuance (shares) | 275,000,000 | 1,000 | |||||||||||
Common stock, par value | $ / shares | $ 0.001 | ||||||||||||
Common shares issued (shares) | 750 | 750 | |||||||||||
Shares of common stock in underwritten public offering | 17,000,000 | ||||||||||||
Price per share of underwritten public offering | $ / shares | $ 6.25 | ||||||||||||
Sale Price of underwritten public offering before offering costs and expenses | $ | $ 106,300,000 | ||||||||||||
Proceeds from issuance of common shares, net of issuance costs | $ | 101,300,000 | ||||||||||||
Estimated offering costs and expenses | $ | $ 5,000,000 | ||||||||||||
Preferred stock, shares authorized | 40,000,000 | ||||||||||||
Gastar Exploration USA | Chesapeake Energy Corporation | |||||||||||||
Class Of Stock [Line Items] | |||||||||||||
Amount paid to Chesapeake | $ | $ 1,000,000 | ||||||||||||
Repurchase of common shares | $ | $ 9,800,000 |
Capital Stock (Schedule of Issu
Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details) - shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares of common stock issued pursuant to PBUs vested, net of forfeitures | 497,636 | 472,189 | |
Stock options exercised | 7,500 | ||
Restricted shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares of restricted common stock granted | 1,426,604 | 601,473 | |
Shares of restricted common stock vested | 1,422,670 | 1,915,242 | |
Shares of restricted common stock surrendered upon vesting/exercise | [1] | 413,333 | 612,612 |
Shares of restricted common stock forfeited | 119,499 | 47,398 | |
[1] | Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period. |
Equity Compensation Plans (Narr
Equity Compensation Plans (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 5 | $ 4.9 | $ 3.4 |
Unrecognized expense for outstanding awards | $ 3.2 | ||
Unvested restricted shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 3 years | ||
Stock-based compensation expense | $ 3.5 | ||
Unrecognized expense for outstanding awards | $ 1.4 | ||
Weighted average period for recognition for unrecognized expense | 1 year 4 months 10 days | ||
Unvested restricted shares | Director | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 1 year | ||
Unvested restricted shares | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 1 year | ||
Unvested restricted shares | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 3 years | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted | 0 | 0 | 0 |
PBUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 1.5 | ||
Weighted average period for recognition for unrecognized expense | 1 year 11 months 1 day | ||
Total unrecognized expense for PBUs | $ 1.8 | ||
2006 Long-Term Stock Incentive Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares available for future issuance (no more than) (shares) | 2,877,599 | ||
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 3 years | ||
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 2 years | ||
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 4 years | ||
2006 Long-Term Stock Incentive Plan | PBUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 3 years | ||
Percentage settlement of targeted number of PBUs | 100.00% | ||
2006 Long-Term Stock Incentive Plan | PBUs | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage settlement of targeted number of PBUs | 0.00% | ||
2006 Long-Term Stock Incentive Plan | PBUs | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage settlement of targeted number of PBUs | 200.00% |
Equity Compensation Plans (Shar
Equity Compensation Plans (Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable) (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, Options, Outstanding [Roll Forward] | |||
Exercised | (7,500) | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Outstanding at beginning of period | 866,600 | ||
Granted | 0 | 0 | 0 |
Exercised | 0 | ||
Canceled/Expired | 0 | ||
Forfeited | 0 | ||
Outstanding at end of period | 866,600 | 866,600 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | |||
Weighted-Average Exercise Price, Outstanding at beginning of period | $ 11.75 | ||
Granted | 0 | ||
Exercised | 0 | ||
Canceled/Expired | 0 | ||
Forfeited | 0 | ||
Weighted-Average Exercise Price, Outstanding at end of period | $ 11.75 | $ 11.75 | |
Number of shares vested and exercisable | 866,600 | ||
Weighted Average Exercise Price per Share | $ 11.75 | ||
Weighted Average Remaining Contractual Term (in years) | 1 year 2 months 9 days | ||
Aggregate Intrinsic Value | $ 0 |
Equity Compensation Plans (Rest
Equity Compensation Plans (Restricted Stock Activity) (Details) - Unvested restricted shares $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Unvested PBUs at December 31, 2014 | shares | 2,411,914 |
Granted | shares | 1,426,604 |
Vested | shares | (1,422,670) |
Forfeited | shares | (119,499) |
Unvested PBUs at December 31, 2015 | shares | 2,296,349 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Weighted-Average Grant Date Fair Value, Outstanding at beginning of period | $ / shares | $ 2.79 |
Granted | $ / shares | 2.40 |
Vested | $ / shares | 2.67 |
Forfeited | $ / shares | 2.58 |
Weighted-Average Grant Date Fair Value, Outstanding at end of period | $ / shares | $ 2.63 |
Weighted Average Remaining Contractual Term (in years) | 1 year 2 months 23 days |
Aggregate Intrinsic Value | $ | $ 3,008 |
Equity Compensation Plans (Sche
Equity Compensation Plans (Schedule of Weighted Average Grant Date Fair Value) (Details) - Unvested restricted shares - 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] | |||
Weighted average grant date fair value (in dollars per share) | $ 2.40 | $ 5.85 | $ 1.30 |
Grant date fair value of stock options vested | $ 3,794 | $ 3,497 | $ 2,725 |
Equity Compensation Plans (Summ
Equity Compensation Plans (Summary of PBUs) (Details) - PBUs | 12 Months Ended |
Dec. 31, 2015$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Unvested PBUs at December 31, 2014 | shares | 990,658 |
Granted | shares | 741,146 |
Vested | shares | (448,637) |
Forfeited | shares | 0 |
Unvested PBUs at December 31, 2015 | shares | 1,283,167 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Unvested PBUs at December 31, 2014 | $ / shares | $ 3.19 |
Granted | $ / shares | 3.01 |
Vested | $ / shares | 2.76 |
Forfeited | $ / shares | 0 |
Unvested PBUs at December 31, 2015 | $ / shares | $ 3.24 |
Equity Compensation Plans (Sc70
Equity Compensation Plans (Schedule of Future Amortization of Unrecognized Compensation Cost) (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
2,016 | $ 2,074 |
2,017 | 1,075 |
2,018 | 82 |
Total | $ 3,231 |
Interest Expense (Schedule of C
Interest Expense (Schedule of Components of Interest Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Interest Expense [Abstract] | ||||
Cash and accrued | $ 30,981 | $ 28,851 | $ 14,130 | |
Amortization of deferred financing costs | [1],[2] | 3,584 | 3,067 | 2,322 |
Capitalized interest | (3,879) | (4,347) | (3,284) | |
Total interest expense | $ 30,686 | $ 27,571 | $ 13,168 | |
[1] | The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.” | |||
[2] | The years ended December 31, 2015, 2014 and 2013 include $2.5 million, $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes. |
Interest Expense (Schedule of72
Interest Expense (Schedule of Components of Interest Expense) (Parenthetical) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Interest Expense [Abstract] | |||
Deferred financing costs written off | $ 1,200,000 | ||
Accretion of debt discount | $ 2,500,000 | $ 2,300,000 | $ 716,000 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands | Jun. 07, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2007 |
Related Party Transaction [Line Items] | |||||
Repurchase of common shares | $ 0 | $ 0 | $ 9,753 | ||
Investor | |||||
Related Party Transaction [Line Items] | |||||
Common shares acquired by Chesapeake Energy Corporation (shares) | 6,781,768 | ||||
Chesapeake Energy Corporation | |||||
Related Party Transaction [Line Items] | |||||
Amount paid to Chesapeake | $ 10,800 | ||||
Repurchase of common shares | $ 9,800 | ||||
Repurchase of common stock (shares) | 6,781,768 |
Income Taxes (Schedule of (Loss
Income Taxes (Schedule of (Loss) Income before Income Taxes) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||
United States | $ (459,507) | $ 50,953 | $ 35,234 |
Foreign | 0 | 0 | (1,934) |
Total income (loss) before income taxes | $ (459,507) | $ 50,953 | $ 33,300 |
Income Taxes (Schedule of Compo
Income Taxes (Schedule of Components of Deferred Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Deferred: | |||
Federal | $ 0 | $ 0 | $ (15,299) |
State | 0 | 0 | (743) |
Foreign | 0 | 0 | 0 |
Income tax expense (benefit) | $ 0 | $ 0 | $ (16,042) |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Loss Carryforwards [Line Items] | ||
Foreign tax credit carry forwards | $ 50,681 | $ 50,681 |
US | ||
Operating Loss Carryforwards [Line Items] | ||
Federal statutory rate | 35.00% | |
Net operating loss carryforwards | $ 512,000 |
Income Taxes (Schedule of Effec
Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Contingency [Line Items] | |||
Expected income tax provision (benefit) at statutory rate | $ (160,827) | $ 17,833 | $ 11,655 |
State tax, tax effected | (7,799) | 803 | 96 |
Stock-based compensation expense (benefit) | 255 | (1,291) | 605 |
Gain on acquisition of assets at fair value | 0 | 0 | (9,685) |
Non-deductible costs of migration from Canada to U.S. | 0 | 0 | 95 |
Other | 17 | 38 | (49) |
Other changes in valuation allowance | 168,354 | (17,383) | (38,777) |
Actual income tax provision | 0 | 0 | (16,042) |
Canada | |||
Income Tax Contingency [Line Items] | |||
Tax effect of Canadian tax rate differences | 0 | 0 | 193 |
Loss of Canadian tax attributes due to migration from Canada | $ 0 | $ 0 | $ 19,825 |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax asset (liability): | ||
Capital assets | $ 10,485 | $ (134,223) |
Stock-based compensation | 4,243 | 4,504 |
Net operating loss carry forwards | 187,963 | 164,056 |
Foreign tax credit carry forwards | 50,681 | 50,681 |
Valuation allowance | (253,372) | (85,018) |
Net deferred tax asset | $ 0 | $ 0 |
Earnings per Share (Schedule of
Earnings per Share (Schedule of Earnings per Share, Basic and Diluted, by Common Class, Including Two Class Method) (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 | |
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net income (loss) attributable to common stockholders | $ (161,143) | $ (191,819) | $ (118,014) | $ (3,004) | $ 26,671 | $ 9,807 | $ 2,016 | $ (1,965) | $ (473,980) | $ 36,529 | $ 39,964 |
Weighted average common shares outstanding basic (shares) | 77,685,049 | 77,628,120 | 77,611,167 | 77,114,826 | 75,994,979 | 60,006,903 | 58,702,982 | 58,204,532 | 77,511,677 | 63,270,733 | 60,220,115 |
Incremental shares from unvested restricted shares | 0 | 2,451,903 | 2,869,490 | ||||||||
Incremental shares from outstanding stock options | 0 | 97,491 | 26,095 | ||||||||
Incremental shares from outstanding PBUs | 0 | 672,462 | 502,701 | ||||||||
Weighted average common shares outstanding diluted (shares) | 77,685,049 | 77,628,120 | 77,611,167 | 77,114,826 | 78,577,762 | 63,399,446 | 61,922,874 | 58,204,532 | 77,511,677 | 66,492,589 | 63,618,401 |
Basic (dollars per share) | $ (2.07) | $ (2.47) | $ (1.52) | $ (0.04) | $ 0.35 | $ 0.16 | $ 0.03 | $ (0.03) | $ (6.11) | $ 0.58 | $ 0.66 |
Diluted (dollars per share) | $ (2.07) | $ (2.47) | $ (1.52) | $ (0.04) | $ 0.34 | $ 0.15 | $ 0.03 | $ (0.03) | $ (6.11) | $ 0.55 | $ 0.63 |
Common shares excluded from denominator as anti-dilutive (shares) | 195,252 | 34,058 | 3,505 | ||||||||
Unvested restricted shares | |||||||||||
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 177,663 | 34,058 | 3,505 | ||||||||
Unvested PBUs | |||||||||||
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 17,589 | 0 | 0 |
Commitments and Contingencies80
Commitments and Contingencies (Narrative) (Details) | Oct. 30, 2014USD ($) | Jun. 17, 2014USD ($) | Apr. 22, 2014well | Jun. 07, 2013USD ($) | Dec. 17, 2010USD ($) | Jun. 30, 2014MMcf / d | Dec. 31, 2010 | Dec. 31, 2015USD ($)a | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 29, 2015USD ($) | Aug. 07, 2013USD ($) | Dec. 31, 2012USD ($) |
Loss Contingencies [Line Items] | |||||||||||||
Office lease expense | $ 687,000 | $ 649,000 | $ 372,000 | ||||||||||
Repurchase of common shares | 0 | 0 | 9,753,000 | ||||||||||
Asset retirement obligation | 6,086,000 | 5,557,000 | $ 6,063,000 | $ 6,963,000 | |||||||||
Asset retirement obligation, current | 89,000 | 82,000 | |||||||||||
Asset retirement obligation, non-current | 5,997,000 | $ 5,475,000 | |||||||||||
Chesapeake Energy Corporation | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Repurchase of common shares | $ 9,800,000 | ||||||||||||
Amount paid to Chesapeake | 10,800,000 | ||||||||||||
SEI Energy LLC | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Contractual Obligation | $ 0 | ||||||||||||
SEI Energy LLC | Capacity | Fort Beeler Processing Plant | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Capacity of processing plants (MMcf/day) | MMcf / d | 520 | ||||||||||||
SEI Energy LLC | Capacity | Oak Grove Processing Plant | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Capacity of processing plants (MMcf/day) | MMcf / d | 200 | ||||||||||||
Gastar Exploration USA | Chesapeake Energy Corporation | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Settlement aggregate amount | 80,000,000 | ||||||||||||
Acquisition of oil and natural gas properties | 69,400,000 | ||||||||||||
Repurchase of common shares | 9,800,000 | ||||||||||||
Amount paid to Chesapeake | $ 1,000,000 | ||||||||||||
Gastar Exploration USA | SEI Energy LLC | Capacity | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Natural gas production term (years) | 5 years | ||||||||||||
Gastar Exploration USA | Atinum and SEI Energy | Capacity | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Natural gas production term (years) | 10 years | ||||||||||||
Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Settlement aggregate amount | $ 21,200,000 | ||||||||||||
Directors and officers liability coverage limit | $ 20,000,000 | ||||||||||||
Husky Ventures Inc vs J Russell Porter, Michael A Gerlich, Michael McCown, Keith R Blair, Henry J Hansen and John M Selser Sr | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Date of Dismissal | Oct. 16, 2015 | ||||||||||||
Gastar Exploration Inc V Christopher Mc Arthur | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Damages sought in arbitration matter | $ 2,750,000 | ||||||||||||
Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Date of Dismissal | Dec. 3, 2015 | ||||||||||||
Number of wells drilled | well | 3 | ||||||||||||
Gross acres (acres) | a | 3,300 | ||||||||||||
Claim, settlement amount | $ 900,000 | ||||||||||||
Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania | Surety Bond | Judicial Ruling | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss contingency, damages sought, value | $ 800,000 | ||||||||||||
Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania | Marshall County, West Virginia | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Gross acres (acres) | a | 16,000 | ||||||||||||
Gastar Exploration U S A Inc V Williams Ohio Valley Midstream L L C | Gastar Exploration USA | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Settlement aggregate amount | $ 8,600,000 | ||||||||||||
Damages sought in arbitration matter | $ 612,000 | ||||||||||||
Maximum | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Lease Expiration Date | 2018-12 | ||||||||||||
Minimum | Husky Ventures Inc vs J Russell Porter, Michael A Gerlich, Michael McCown, Keith R Blair, Henry J Hansen and John M Selser Sr | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss contingency, damages sought, value | $ 2,000,000 |
Commitments and Contingencies81
Commitments and Contingencies (Schedule of Future Minimum Rental Commitments) (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2,016 | $ 660 |
2,017 | 211 |
2,018 | 176 |
Total | $ 1,047 |
Concentration of Risk and Sig82
Concentration of Risk and Significant Customers (Schedule of Concentration Risk) (Details) - Natural gas, oil and NGLs revenues excluding realized hedge impact | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Customer Concentration Risk | SEI | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 22.00% | 50.00% | 56.00% | |
Customer Concentration Risk | Sunoco | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 62.00% | 37.00% | 16.00% | |
Appalachian Basin | Geographic Concentration Risk | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 17.00% | 39.00% | 65.00% | |
Mid-Continent | Geographic Concentration Risk | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 83.00% | 61.00% | 26.00% | |
Hilltop Area, East Texas | Geographic Concentration Risk | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | [1] | 9.00% | ||
[1] | The Company’s working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013. |
Statement of Cash Flows - Sup83
Statement of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest, net of capitalized amounts | $ 26,859 | $ 24,632 | $ 7,341 |
Non-cash transactions: | |||
Capital expenditures (excluded from) included in accounts payable and accrued drilling costs | (26,228) | 12,777 | 582 |
Capital expenditures included in accounts receivable | 4,077 | (4,077) | |
Asset retirement obligation included in oil and natural gas properties | 526 | 221 | (1,302) |
Asset retirement obligation for property disposals | (416) | (645) | (4,354) |
Application of advances to operators | 11,445 | 58,326 | 19,755 |
Other | $ 5 | $ (11) | $ 47 |
Quarterly Consolidated Financ84
Quarterly Consolidated Financial Data - Unaudited (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 | |||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||
Revenues | $ 22,608 | $ 28,386 | $ 21,928 | $ 34,372 | $ 61,448 | $ 41,746 | $ 35,897 | $ 32,327 | |||||||
Income (loss) from operations | (149,272) | [1] | (180,272) | [1] | (107,462) | [1] | 8,172 | [1] | 37,063 | 20,413 | 12,539 | 8,497 | $ (428,834) | $ 78,512 | $ 18,764 |
Income (loss) before provision for income taxes | (157,525) | (188,201) | (114,395) | 614 | 30,290 | 13,425 | 5,627 | 1,611 | |||||||
Net income (loss) | (157,525) | (188,201) | (114,395) | 614 | 30,290 | 13,425 | 5,627 | 1,611 | (459,507) | 50,953 | 49,342 | ||||
Dividend on preferred stock | 3,618 | 3,618 | 3,619 | 3,618 | 3,619 | 3,618 | 3,611 | 3,576 | |||||||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ (161,143) | $ (191,819) | $ (118,014) | $ (3,004) | $ 26,671 | $ 9,807 | $ 2,016 | $ (1,965) | $ (473,980) | $ 36,529 | $ 39,964 | ||||
Basic (in dollars per share) | $ (2.07) | $ (2.47) | $ (1.52) | $ (0.04) | $ 0.35 | $ 0.16 | $ 0.03 | $ (0.03) | $ (6.11) | $ 0.58 | $ 0.66 | ||||
Diluted (in dollars per share) | $ (2.07) | $ (2.47) | $ (1.52) | $ (0.04) | $ 0.34 | $ 0.15 | $ 0.03 | $ (0.03) | $ (6.11) | $ 0.55 | $ 0.63 | ||||
Basic (shares) | 77,685,049 | 77,628,120 | 77,611,167 | 77,114,826 | 75,994,979 | 60,006,903 | 58,702,982 | 58,204,532 | 77,511,677 | 63,270,733 | 60,220,115 | ||||
Diluted (shares) | 77,685,049 | 77,628,120 | 77,611,167 | 77,114,826 | 78,577,762 | 63,399,446 | 61,922,874 | 58,204,532 | 77,511,677 | 66,492,589 | 63,618,401 | ||||
[1] | Income (loss) from operations for the second, third and fourth quarters of 2015 includes impairment of oil and natural gas properties of $100.2 million, $182.0 million and $144.8 million, respectively. |
Quarterly Consolidated Financ85
Quarterly Consolidated Financial Data - Unaudited (Parenthetical) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information Disclosure [Abstract] | ||||||
Impairment of natural gas and oil properties | $ 144,760 | $ 181,966 | $ 100,152 | $ 426,878 | $ 0 | $ 0 |
Supplemental Oil and Gas Disc86
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved properties: | $ 1,286,373 | $ 1,124,367 | |
U S | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved properties: | 1,286,373 | 1,124,367 | $ 935,773 |
Unproved properties | 92,609 | 128,274 | 96,220 |
Total oil and natural gas properties | 1,378,982 | 1,252,641 | 1,031,993 |
Impairment of proved oil and natural gas properties | (764,817) | (337,939) | (337,939) |
Accumulated depreciation, depletion and amortization | (286,020) | (223,555) | (177,790) |
Net capitalized costs | $ 328,145 | $ 691,147 | $ 516,264 |
Supplemental Oil and Gas Disc87
Supplemental Oil and Gas Disclosures - Unaudited (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Extractive Industries [Abstract] | |||
Asset retirement costs | $ 2.4 | $ 2.4 | $ 3.4 |
Supplemental Oil and Gas Disc88
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) - U S - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Proved property acquisition | [1] | $ 15,615 | $ 0 | $ 189,594 |
Unproved property acquisition | [2] | 50,434 | 41,475 | 71,472 |
Exploration | 53,290 | 127,384 | 36,893 | |
Development | 54,316 | 57,913 | 53,058 | |
Total costs incurred | $ 173,655 | $ 226,772 | $ 351,017 | |
[1] | The 2013 property acquisition costs exclude a downward adjustment of $2.6 million for fair value of acquisition. | |||
[2] | The 2013 property acquisition costs exclude $46.3 million of adjustment for fair value of acquisition. |
Supplemental Oil and Gas Disc89
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Parenthetical) (Details) - U S $ in Millions | 12 Months Ended |
Dec. 31, 2013USD ($) | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
Downward adjustment for fair value of acquisition | $ (2.6) |
Adjustment for fair value of acquisition | $ 46.3 |
Supplemental Oil and Gas Disc90
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Results of Operations for Oil and Gas Producing Activities) (Details) - U S $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)$ / MBoe | Dec. 31, 2014USD ($)$ / MBoe | Dec. 31, 2013USD ($)$ / MBoe | |
Results Of Operations For Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Oil, condensate, natural gas and NGLs sales, including commodity derivatives | $ 107,294 | $ 171,418 | $ 87,755 |
Production expenses | (28,792) | (29,735) | (18,113) |
Impairment of oil and natural gas properties | (426,878) | 0 | 0 |
Depreciation, depletion and amortization | (62,465) | (45,765) | (32,158) |
Results of producing activities | $ (410,841) | $ 95,918 | $ 37,484 |
Depreciation, depletion and amortization per MBoe | $ / MBoe | 12.67 | 12.34 | 9.94 |
Supplemental Oil and Gas Disc91
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Oil and Gas Net Production, Average Sales Price and Average Production Costs) (Details) | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2015$ / MMBTU$ / bbl | Sep. 30, 2015$ / MMBTU$ / bbl | Jun. 30, 2015$ / MMBTU$ / bbl | Mar. 31, 2015$ / MMBTU$ / bbl | Dec. 31, 2014$ / MMBTU$ / bbl | Sep. 30, 2014$ / MMBTU$ / bbl | Jun. 30, 2014$ / MMBTU$ / bbl | Mar. 31, 2014$ / MMBTU$ / bbl | Dec. 31, 2013$ / MMBTU$ / bbl | Sep. 30, 2013$ / MMBTU$ / bbl | Jun. 30, 2013$ / MMBTU$ / bbl | Mar. 31, 2013$ / MMBTU$ / bbl | Dec. 31, 2015$ / MMBTU$ / bbl | Dec. 31, 2014$ / MMBTU$ / bbl | Dec. 31, 2013$ / MMBTU$ / bbl | ||
Natural gas (per MMBtu): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / MMBTU | [1] | 2.59 | 3.06 | 3.39 | 3.88 | 4.35 | 4.24 | 4.10 | 3.99 | 3.67 | 3.61 | 3.44 | 2.95 | |||
Oil (per Bbl): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / bbl | [1] | 50.28 | 59.21 | 71.68 | 82.72 | 94.99 | 99.08 | 100.11 | 98.30 | 96.78 | 91.69 | 88.13 | 89.17 | |||
Henry Hub | Natural gas (per MMBtu): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / MMBTU | 2.59 | 4.35 | 3.67 | |||||||||||||
WTI spot | Oil (per Bbl): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / bbl | 50.28 | 94.99 | 96.78 | |||||||||||||
[1] | For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices. |
Supplemental Oil and Gas Disc92
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) bbl in Thousands, MBoe in Thousands | 12 Months Ended | ||||||
Dec. 31, 2015MBoebblMMcf | Dec. 31, 2014MBoebblMMcf | Dec. 31, 2013MBoebblMMcf | |||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period, equivalents | MBoe | [1] | 102,063 | 54,634 | 30,152 | |||
Extensions and discoveries | MBoe | [1] | 9,374 | [2] | 42,810 | [3] | 15,483 | [4] |
Revisions of previous estimates | MBoe | [1] | (53,268) | [5] | 8,574 | 1,729 | ||
Production | MBoe | [1] | (4,931) | (3,708) | (3,237) | |||
Purchases in place | MBoe | [1] | 2,971 | 14,639 | ||||
Sales in place | MBoe | [1] | (332) | (247) | (4,132) | |||
Proved reserves at the end of the period. equivalents | MBoe | [1] | 55,877 | 102,063 | 54,634 | |||
Proved developed reserves | MBoe | [1] | 28,415 | 36,789 | 30,892 | |||
Proved undeveloped reserves | MBoe | [1] | 27,462 | 65,274 | 23,742 | |||
Total | MBoe | [1] | 55,877 | 102,063 | 54,634 | |||
Oil | |||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period | [6] | 28,636 | 14,718 | 3,394 | |||
Extensions and discoveries | [6] | 4,777 | [2] | 13,137 | [3] | 4,385 | [4] |
Revisions of previous estimates | [6] | (8,962) | [5] | 1,780 | (337) | ||
Production | [6] | (1,425) | (975) | (515) | |||
Purchases in place | [6] | 1,270 | 7,796 | ||||
Sales in place | [6] | (94) | (24) | (5) | |||
Proved reserves as of the end of the period | [6] | 24,202 | 28,636 | 14,718 | |||
Proved developed reserves | [6] | 7,181 | 6,968 | 5,834 | |||
Proved undeveloped reserves | [6] | 17,021 | 21,668 | 8,884 | |||
Total | [6] | 24,202 | 28,636 | 14,718 | |||
Natural Gas | |||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period | MMcf | [7] | 287,005 | 180,710 | 131,010 | |||
Extensions and discoveries | MMcf | [7] | 14,114 | [2] | 121,672 | [3] | 52,750 | [4] |
Revisions of previous estimates | MMcf | [7] | (182,600) | [5] | (2,465) | 8,114 | ||
Production | MMcf | [7] | (13,759) | (11,598) | (13,366) | |||
Purchases in place | MMcf | [7] | 4,965 | 26,961 | ||||
Sales in place | MMcf | [7] | (1,274) | (1,314) | (24,759) | |||
Proved reserves as of the end of the period | MMcf | [7] | 108,451 | 287,005 | 180,710 | |||
Proved developed reserves | MMcf | [7] | 77,966 | 114,564 | 114,195 | |||
Proved undeveloped reserves | MMcf | [7] | 30,485 | 172,441 | 66,515 | |||
Total | MMcf | [7] | 108,451 | 287,005 | 180,710 | |||
Natural Gas Liquids | |||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period | [6] | 25,593 | 9,798 | 4,922 | |||
Extensions and discoveries | [6] | 2,244 | [2] | 9,394 | [3] | 2,306 | [4] |
Revisions of previous estimates | [6] | (13,873) | [5] | 7,205 | 714 | ||
Production | [6] | (1,212) | (800) | (494) | |||
Purchases in place | [6] | 873 | 2,350 | ||||
Sales in place | [6] | (26) | (4) | 0 | |||
Proved reserves as of the end of the period | [6] | 13,599 | 25,593 | 9,798 | |||
Proved developed reserves | [6] | 8,240 | 10,726 | 6,025 | |||
Proved undeveloped reserves | [6] | 5,359 | 14,867 | 3,773 | |||
Total | [6] | 13,599 | 25,593 | 9,798 | |||
[1] | Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. | ||||||
[2] | All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. | ||||||
[3] | Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. | ||||||
[4] | Of the 2013 extensions and discoveries, 74% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. | ||||||
[5] | The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. | ||||||
[6] | Thousand barrels | ||||||
[7] | Million cubic feet or million cubic feet equivalent, as applicable |
Supplemental Oil and Gas Disc93
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Parenthetical) (Details) - MBoe MBoe in Thousands | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Reserve Quantities [Line Items] | |||||
Production, Barrels of Oil Equivalents | Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. | ||||
Percentage of extensions and discoveries from successful drilling results in Marcellus Shale | 69.00% | 74.00% | |||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease) | [2] | 53,268 | [1] | (8,574) | (1,729) |
Appalchian Basin | |||||
Reserve Quantities [Line Items] | |||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease) | (36,800) | ||||
[1] | The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. | ||||
[2] | Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. |
Supplemental Oil and Gas Disc94
Supplemental Oil and Gas Disclosures - Unaudited (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves) (Details) - U S - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Future cash inflows | $ 1,425,734 | $ 3,855,227 | $ 2,103,023 |
Future production costs | (547,484) | (1,048,554) | (588,568) |
Future development costs | (365,123) | (611,602) | (296,666) |
Future income taxes | (486,593) | (215,502) | |
Future net cash flows | 513,127 | 1,708,478 | 1,002,287 |
10% annual discount for estimated timing of cash flows | (283,324) | (891,739) | (486,458) |
Standardized measure of discounted future cash flows | $ 229,803 | $ 816,739 | $ 515,829 |
Supplemental Oil and Gas Disc95
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - U S - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Extensions and discoveries, less related costs | $ 71,547 | $ 369,806 | $ 196,448 |
Sale of natural gas and oil, net of production costs | (53,914) | (122,114) | (74,394) |
Purchases of reserves in place | 9,937 | 247,208 | |
Sales of reserves in place | (4,853) | (1,475) | (9,063) |
Revisions of previous quantity estimates | (324,036) | 101,044 | 6,191 |
Net change in income tax | 171,946 | (95,245) | (76,701) |
Net change in prices and production costs | (604,074) | 59,786 | 79,820 |
Accretion of discount | 98,869 | (3,996) | 1,211 |
Development costs incurred | 10,500 | 37,461 | 23,567 |
Net change in estimated future development costs | 31,131 | (1,276) | (97,461) |
Change in production rates (timing) and other | 6,011 | (43,081) | 12,194 |
End of period | $ 229,803 | $ 816,739 | $ 515,829 |