Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Mar. 11, 2015 | Jun. 30, 2014 |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Gastar Exploration Inc. | ||
Entity Central Index Key | 1431372 | ||
Current Fiscal Year End Date | -19 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $507.90 | ||
Entity Common Stock, Shares Outstanding | 80,195,695 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
CURRENT ASSETS: | ||
Cash and cash equivalents | $11,008 | $32,393 |
Accounts receivable, net of allowance for doubtful accounts of $0 and $507, respectively | 30,841 | 21,656 |
Commodity derivative contracts | 19,687 | 0 |
Prepaid expenses | 2,083 | 1,145 |
Total current assets | 63,619 | 55,194 |
Oil and natural gas properties, full cost method of accounting: | ||
Unproved properties, excluded from amortization | 128,274 | 96,220 |
Proved properties | 1,124,367 | 935,773 |
Total oil and natural gas properties | 1,252,641 | 1,031,993 |
Furniture and equipment | 3,010 | 2,691 |
Total property, plant and equipment | 1,255,651 | 1,034,684 |
Accumulated depreciation, depletion and amortization | -563,351 | -517,171 |
Total property, plant and equipment, net | 692,300 | 517,513 |
OTHER ASSETS: | ||
Commodity derivative contracts | 7,815 | 7,545 |
Deferred charges, net | 2,586 | 2,950 |
Advances to operators and other assets | 9,474 | 6,733 |
Total other assets | 19,875 | 17,228 |
TOTAL ASSETS | 775,794 | 589,935 |
CURRENT LIABILITIES: | ||
Accounts payable | 28,843 | 11,046 |
Revenue payable | 9,122 | 12,514 |
Accrued interest | 3,528 | 3,504 |
Accrued drilling and operating costs | 5,977 | 8,756 |
Advances from non-operators | 1,820 | 9,259 |
Commodity derivative contracts | 0 | 3,403 |
Commodity derivative premium payable | 2,481 | 145 |
Asset retirement obligation | 82 | 633 |
Other accrued liabilities | 3,175 | 4,844 |
Total current liabilities | 55,028 | 54,104 |
LONG-TERM LIABILITIES: | ||
Long-term debt | 360,303 | 312,994 |
Commodity derivative contracts | 0 | 378 |
Commodity derivative premium payable | 4,702 | 7,000 |
Asset retirement obligation | 5,475 | 5,430 |
Total long-term liabilities | 370,480 | 325,802 |
Commitments and contingencies (Note 14) | ||
STOCKHOLDERS' EQUITY: | ||
Common stock | 78 | 61 |
Additional paid-in capital | 568,440 | 464,730 |
Accumulated deficit | -218,294 | -254,823 |
Total stockholders' equity | 350,286 | 210,029 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | 775,794 | 589,935 |
Series A Preferred Stock | ||
STOCKHOLDERS' EQUITY: | ||
Preferred stock | 41 | 40 |
Series B Preferred Stock | ||
STOCKHOLDERS' EQUITY: | ||
Preferred stock | $21 | $21 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, except Share data, unless otherwise specified | ||
Accounts receivable, doubtful accounts | $0 | $507 |
Common stock, par value | $0.00 | $0.00 |
Common stock, shares authorized | 275,000,000 | 275,000,000 |
Common stock, shares issued | 78,632,810 | 61,211,658 |
Common stock, shares outstanding | 78,632,810 | 61,211,658 |
Series A Preferred Stock | ||
Preferred stock, par value | $0.01 | $0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 4,045,000 | 3,958,160 |
Preferred stock, shares outstanding | 4,045,000 | 3,958,160 |
Preferred Stock, liquidation preference per share | $25 | $25 |
Series B Preferred Stock | ||
Preferred stock, par value | $0.01 | $0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 2,140,000 | 2,140,000 |
Preferred stock, shares outstanding | 2,140,000 | 2,140,000 |
Preferred Stock, liquidation preference per share | $25 | $25 |
Consolidated_Statements_Of_Ope
Consolidated Statements Of Operations (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
REVENUES: | |||
Oil and condensate | $82,820 | $36,480 | $11,570 |
Natural gas | 47,647 | 40,416 | 23,318 |
NGLs | 21,382 | 15,611 | 7,630 |
Total oil and condensate, natural gas and NGLs revenues | 151,849 | 92,507 | 42,518 |
Gain (loss) on commodity derivatives contracts | 19,569 | -4,752 | 7,422 |
Total revenues | 171,418 | 87,755 | 49,940 |
EXPENSES: | |||
Production taxes | 6,733 | 4,651 | 2,269 |
Lease operating expenses | 19,323 | 9,456 | 6,174 |
Transportation, treating and gathering | 3,679 | 4,006 | 4,965 |
Depreciation, depletion and amortization | 46,180 | 32,449 | 25,424 |
Impairment of natural gas and oil properties | 0 | 0 | 150,787 |
Accretion of asset retirement obligation | 506 | 468 | 388 |
General and administrative expense | 16,485 | 16,961 | 12,211 |
Litigation settlement expense | 0 | 1,000 | 1,250 |
Total expenses | 92,906 | 68,991 | 203,468 |
INCOME (LOSS) FROM OPERATIONS | 78,512 | 18,764 | -153,528 |
OTHER INCOME (EXPENSE): | |||
Gain on acquisition of assets at fair value, net of income taxes | 0 | 27,670 | 0 |
Interest expense | -27,571 | -13,168 | -270 |
Investment and other income | 19 | 48 | 9 |
Foreign transaction loss | -7 | -14 | -2 |
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES | 50,953 | 33,300 | -153,791 |
Income tax benefit | 0 | -16,042 | 0 |
NET INCOME (LOSS) | 50,953 | 49,342 | -153,791 |
Dividends on preferred stock | -14,424 | -9,378 | -7,077 |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | $36,529 | $39,964 | ($160,868) |
NET INCOME (LOSS) PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS: | |||
Basic (in dollars per share) | $0.58 | $0.66 | ($2.53) |
Diluted (in dollars per share) | $0.55 | $0.63 | ($2.53) |
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | |||
Basic (shares) | 63,270,733 | 60,220,115 | 63,538,362 |
Diluted (shares) | 66,492,589 | 63,618,401 | 63,538,362 |
Consolidated_Statement_of_Stoc
Consolidated Statement of Stockholders' Equity (USD $) | Total | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Series A Preferred Stock | Series B Preferred Stock |
In Thousands, except Share data, unless otherwise specified | Preferred Stock | Preferred Stock | ||||
Balance at beginning of period at Dec. 31, 2011 | $235,194 | $316,346 | $52,753 | ($133,919) | $14 | $0 |
Balance at beginning of period (in shares) at Dec. 31, 2011 | 64,706,750 | 1,364,543 | 0 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of preferred stock (shares) | 2,586,711 | |||||
Issuance of preferred stock | 49,250 | 49,224 | 26 | |||
Issuance of restricted stock (shares) | 1,916,980 | |||||
Issuance of restricted stock | 0 | |||||
Forfeitures of restricted stock (shares) | -191,728 | |||||
Forfeitures of restricted stock | -335 | -335 | ||||
Exercise of stock options, net of forfeitures (shares) | 607 | |||||
Stock based compensation | 3,295 | 3,295 | ||||
Preferred stock dividends | -7,077 | -7,077 | ||||
Net income (loss) | -153,791 | -153,791 | ||||
Balance at end of period at Dec. 31, 2012 | 126,536 | 316,346 | 104,937 | -294,787 | 40 | 0 |
Balance at end 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 (shares) | 6,906 | 2,140,000 | ||||
Issuance of preferred stock | 50,181 | 50,160 | 21 | |||
Repurchase of common stock (shares) | -6,781,768 | |||||
Repurchase of shares of common stock | -9,753 | -9,753 | ||||
Reclassification of par value of common stock | -306,532 | 306,532 | ||||
Issuance of restricted stock (shares) | 2,288,179 | |||||
Issuance of restricted stock | 0 | |||||
Forfeitures of restricted stock (shares) | -737,362 | |||||
Forfeitures of restricted stock | -334 | -334 | ||||
Exercise of stock options, net of forfeitures (shares) | 10,000 | 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 (shares) | 86,840 | |||||
Issuance of preferred stock | 2,066 | 2,065 | 1 | |||
Issuance of preferred stock (shares) | 17,000,000 | |||||
Issuance of preferred stock | 101,319 | 17 | 101,302 | |||
Exercise of stock options, net of forfeitures (shares) | 472,189 | |||||
Issuance of restricted stock (shares) | 601,473 | |||||
Issuance of restricted stock | 0 | |||||
Forfeitures of restricted stock (shares) | -659,227 | |||||
Forfeitures of restricted stock | -4,562 | -4,562 | ||||
Exercise of stock options, net of forfeitures (shares) | 7,500 | 6,717 | ||||
Exercise of stock options, net of forfeitures | 15 | 15 | ||||
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 |
Consolidated_Statement_of_Stoc1
Consolidated Statement of Stockholders' Equity (Parenthetical) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Statement of Stockholders' Equity [Abstract] | |
Issuance of shares- cash, offering costs | $4,931 |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||
Net income (loss) | $50,953 | $49,342 | ($153,791) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 46,180 | 32,449 | 25,424 | |||
Impairment of natural gas and oil properties | 0 | 0 | 150,787 | |||
Stock-based compensation | 4,890 | 3,435 | 3,295 | |||
Total (gain) loss on commodity derivatives contracts | -19,569 | 4,752 | -7,422 | |||
Cash settlements of matured commodity derivative contracts, net | -4,901 | 5,892 | 16,251 | |||
Cash premiums paid for commodity derivatives contracts | -185 | -152 | -4,539 | |||
Amortization of deferred financing costs | 3,067 | [1],[2] | 2,322 | [1],[2] | 224 | [1],[2] |
Accretion of asset retirement obligation | 506 | 468 | 388 | |||
Settlement of asset retirement obligation | -588 | -66 | -636 | |||
Gain on acquisition of assets at fair value | 0 | -27,670 | 0 | |||
Deferred tax benefit | 0 | -16,042 | 0 | |||
Changes in operating assets and liabilities: | ||||||
Accounts receivable | -12,524 | -8,431 | 2,487 | |||
Prepaid expenses | -938 | -48 | 146 | |||
Accounts payable and accrued liabilities | -2,566 | 1,563 | 4,441 | |||
Net cash provided by operating activities | 64,325 | 47,814 | 37,055 | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Development and purchase of oil and natural gas properties | -155,631 | -95,343 | -136,311 | |||
Advances to operators | -61,067 | -22,213 | -9,649 | |||
Acquisition of oil and natural gas properties - refund (expenditure) | 4,209 | -251,096 | 0 | |||
Proceeds from sale of oil and natural gas properties | 5,530 | 112,201 | 0 | |||
Use of proceeds from non-operators | -7,439 | -8,281 | -1,983 | |||
Purchase of furniture and equipment | -319 | -766 | -296 | |||
Net cash used in investing activities | -214,717 | -265,498 | -148,239 | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||
Proceeds from issuance of common shares, net of issuance costs | 101,319 | 0 | 0 | |||
Repurchase of common stock | 0 | -9,753 | 0 | |||
Proceeds from revolving credit facility | 103,000 | 19,000 | 98,000 | |||
Repayment of revolving credit facility | -58,000 | -117,000 | -30,000 | |||
Proceeds from issuance of senior secured notes, net of discount | 0 | 312,279 | 0 | |||
Proceeds from issuance of preferred stock, net of issuance costs | 2,064 | 50,183 | 49,250 | |||
Dividends on preferred stock | -14,424 | -9,378 | -7,077 | |||
Deferred financing charges | -405 | -3,785 | -450 | |||
Tax withholding related to restricted stock and PBU vestings | -4,562 | -334 | -336 | |||
Other | 15 | -36 | 51 | |||
Net cash provided by financing activities | 129,007 | 241,176 | 109,438 | |||
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | -21,385 | 23,492 | -1,746 | |||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 32,393 | 8,901 | 10,647 | |||
CASH AND CASH EQUIVALENTS, END OF PERIOD | $11,008 | $32,393 | $8,901 | |||
[1] | The years ended DecemberB 31, 2014 and 2013 include $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes. | |||||
[2] | The year ended DecemberB 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. bLong-Term Debt - Second Amended and Restated Revolving Credit Facility.b |
Description_Of_Business
Description Of Business | 12 Months Ended |
Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of business | Description of Business |
Gastar Exploration Inc. (“Gastar”) 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 is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expects to test other prospective formations on the same acreage, including the Woodford Shale and the Meramec Shale (middle Mississippi Lime), which Gastar refers to as the Stack Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled its first successful dry gas Utica Shale/Point Pleasant well on its acreage. Gastar completed the sale of substantially all of its East Texas assets on October 2, 2013, with an effective date of January 1, 2013. | |
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. 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_Account
Summary Of Significant Accounting Policies | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Summary of Significant Accounting Policies | 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 prior year balances are those of Gastar Exploration, Inc. | ||||||||||||
Reclassifications | ||||||||||||
Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact on net income (loss). | ||||||||||||
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. | ||||||||||||
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 $11.0 million and $32.4 million as of December 31, 2014 and 2013, 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. A summary of the activity related to the allowance for doubtful accounts is as follows: | ||||||||||||
For the years ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Allowance for doubtful accounts, beginning of year | $ | 507 | $ | 546 | $ | 551 | ||||||
Expense | — | — | — | |||||||||
Reductions/write-offs | (507 | ) | (39 | ) | (5 | ) | ||||||
Allowance for doubtful accounts, end of year | $ | — | $ | 507 | $ | 546 | ||||||
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, 2014 and 2013 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, 2014. 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 $4.3 million, $3.3 million and $1.9 million for 2014, 2013 and 2012, 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. | ||||||||||||
The following table indicates deferred charges and related accumulated amortization as of the dates indicated: | ||||||||||||
As of December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Deferred charges | $ | 3,664 | $ | 3,269 | ||||||||
Accumulated amortization | (1,078 | ) | (319 | ) | ||||||||
Deferred charges, net | $ | 2,586 | $ | 2,950 | ||||||||
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 (loss) gain 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 (loss) gain 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. The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. The Company did not award any stock option grants during 2014, 2013 or 2012. | ||||||||||||
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, 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 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 stock options, unvested restricted shares and PBUs. | ||||||||||||
Joint Venture 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: | ||||||||||||
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. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows. | ||||||||||||
Income taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this guidance did not impact the Company's operating results, financial position or cash flows. |
Property_Plant_And_Equipment
Property, Plant And Equipment | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Property, Plant And Equipment | 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 West Virginia, Pennsylvania, Oklahoma and Texas. The Company sold substantially all of its interest in East Texas on October 2, 2013, with an effective date of January 1, 2013. The Company's total property, plant and equipment consists of the following: | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Oil and natural gas properties, full cost method of accounting: | |||||||||||||||||||||
Unproved properties | $ | 128,274 | $ | 96,220 | |||||||||||||||||
Proved properties | 1,124,367 | 935,773 | |||||||||||||||||||
Total oil and natural gas properties | 1,252,641 | 1,031,993 | |||||||||||||||||||
Furniture and equipment | 3,010 | 2,691 | |||||||||||||||||||
Total property and equipment | 1,255,651 | 1,034,684 | |||||||||||||||||||
Impairment of proved natural gas and oil properties | (337,939 | ) | (337,939 | ) | |||||||||||||||||
Accumulated depreciation, depletion and amortization | (225,412 | ) | (179,232 | ) | |||||||||||||||||
Total accumulated depreciation, depletion and amortization | (563,351 | ) | (517,171 | ) | |||||||||||||||||
Total property and equipment, net | $ | 692,300 | $ | 517,513 | |||||||||||||||||
Included in the Company's oil and natural gas properties are asset retirement costs of $2.4 million and $3.4 million as of December 31, 2014 and 2013, respectively. | |||||||||||||||||||||
The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Unproved properties, excluded from amortization: | |||||||||||||||||||||
Drilling in progress costs | $ | 29,193 | $ | 4,774 | |||||||||||||||||
Acreage acquisition costs | 91,362 | 86,097 | |||||||||||||||||||
Capitalized interest | 7,719 | 5,349 | |||||||||||||||||||
Total unproved properties excluded from amortization | $ | 128,274 | $ | 96,220 | |||||||||||||||||
For the years ended December 31, 2014 and 2013, 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 Marcellus East, the Company reclassified $3.3 million and $20.5 million of unproved properties to proved properties for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||
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 our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. 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 dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted: | |||||||||||||||||||||
2014 | |||||||||||||||||||||
Total Impairment | 31-Dec | 30-Sep | 30-Jun | 31-Mar | |||||||||||||||||
Henry Hub natural gas price (per MMBtu)(1) | $ | 4.35 | $ | 4.24 | $ | 4.1 | $ | 3.99 | |||||||||||||
West Texas Intermediate oil price (per Bbl)(1) | $ | 94.99 | $ | 99.08 | $ | 100.11 | $ | 98.3 | |||||||||||||
Impairment recorded (pre-tax) (in thousands) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
2013 | |||||||||||||||||||||
Total Impairment | 31-Dec | 30-Sep | 30-Jun | 31-Mar | |||||||||||||||||
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) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
2012 | |||||||||||||||||||||
Total Impairment | 31-Dec | 30-Sep | 30-Jun | 31-Mar | |||||||||||||||||
Henry Hub natural gas price (per MMBtu)(1) | $ | 2.76 | $ | 2.83 | $ | 3.15 | $ | 3.73 | |||||||||||||
West Texas Intermediate oil price (per Bbl)(1) | $ | 91.21 | $ | 91.48 | $ | 92.17 | $ | 94.65 | |||||||||||||
Impairment recorded (pre-tax) (in thousands) | $ | 150,787 | $ | — | $ | 78,054 | $ | 72,733 | $ | — | |||||||||||
_________________________________ | |||||||||||||||||||||
-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. | ||||||||||||||||||||
Future declines in the 12-month average of oil, condensate, natural gas and NGLs prices could result in the recognition of future ceiling impairments. | |||||||||||||||||||||
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 years ended December 31, 2013 and 2012 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of each respective 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 the Years Ended December 31, | |||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
(in thousands, except per share data) | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
Revenues | $ | 132,721 | $ | 97,760 | |||||||||||||||||
Net Loss | $ | (4,836 | ) | $ | (175,809 | ) | |||||||||||||||
Loss per share: | |||||||||||||||||||||
Basic | $ | (0.08 | ) | $ | (2.77 | ) | |||||||||||||||
Diluted | $ | (0.08 | ) | $ | (2.77 | ) | |||||||||||||||
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, 2013 | |||||||||||||||||||||
(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 Joint Venture | |||||||||||||||||||||
In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum”), a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, Gastar USA assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consisted of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well (the “Atinum Joint Venture Assets”). Atinum paid Gastar USA approximately $30.0 million in cash at the closing and paid an additional $40.0 million of Gastar USA's share of drilling costs over time in the form of a “drilling carry.” Upon completion of the funding of the drilling carry, Gastar USA made additional assignments to Atinum in early 2012 as a result of which Atinum owns a 50% interest in the Atinum Joint Venture Assets. The terms of the drilling carry required Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of Gastar USA’s ultimate 50% share of those same costs until the $40.0 million drilling carry had been satisfied. As of December 31, 2011, Atinum had completed the funding of the $40.0 million drilling carry. Subsequent to December 31, 2011, Atinum funds only its 50% share of costs. | |||||||||||||||||||||
The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 60 horizontal wells by year-end 2013. Due to natural gas price declines, Atinum and Gastar USA agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 wells to 51 wells. At December 31, 2014, 67 gross (32.0 net) operated Marcellus Shale wells and one gross (0.5 net) gross operated Utica Shale well were capable of production under the Atinum Joint Venture. The Atinum Joint Venture agreement expires on November 1, 2015. | |||||||||||||||||||||
Subsequent to 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, Gastar USA 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 Gastar USA 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. |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | |
Dec. 31, 2014 | ||
Debt Disclosure [Abstract] | ||
Long-Term Debt | 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 varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base and subject to adjustments based on the Company's leverage ratio. 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 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 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. | ||
Borrowing base re-determinations are scheduled semi-annually in May and November of each calendar year. 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, 2014, the Revolving Credit Facility had a borrowing base of $145.0 million, with $45.0 million of borrowings outstanding and availability of $100.0 million. Effective March 9, 2015, the borrowing base was increased to $200.0 million. The next regularly scheduled re-determination is set for November 2015. 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, 2014, the Company was in compliance with all financial covenants under the Revolving Credit Facility. | ||
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. | ||
On May 15, 2013 and November 15, 2013, in connection with each issuance and sale of the Notes, the Company and each of the Guarantors entered into Registration Rights Agreements (together, the “Registration Rights Agreements”) with Imperial Capital, LLC, as representative of the initial purchasers. Under the Registration Rights Agreement, the Company agreed, subject to certain exceptions, to (i) file a registration statement with the SEC with respect to an exchange of the Notes for new notes having terms substantially identical in all material respects to the Notes (except that the exchange notes will not contain terms relating to transfer restrictions), (ii) use its reasonable best efforts to cause the exchange offer registration statement to be declared effective under the Securities Act of 1933, as amended, within 360 days after the issue date of the Notes, (iii) as soon as practicable after the effectiveness of the exchange offer registration statement, offer the exchange notes in exchange for the Notes, and (iv) keep the registered exchange offer open for not less than 30 days (or longer if required by applicable law) after the date of the registered exchange offer is mailed to the holders of the Notes. The Company and the Guarantors also agreed to file a shelf registration statement for the resale of the Notes if an exchange offer cannot be effected within the time period specified above and in other circumstances. Pursuant to the Registration Rights Agreements entered into in connection with the offering and sale of the Notes, in May 2014, holders of the Notes exchanged their notes for registered notes with the same terms. | ||
At December 31, 2014, the Notes reflected a balance of $315.3 million, net of unamortized discounts of $9.7 million, on the consolidated balance sheets. |
Asset_Retirement_Obligation
Asset Retirement Obligation | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||
Asset Retirement Obligation | Asset Retirement Obligation | |||||||||||
A summary of the activity related to the asset retirement obligation is as follows: | ||||||||||||
For the years ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Asset retirement obligation, beginning of year | $ | 6,063 | $ | 6,963 | $ | 8,275 | ||||||
Liabilities incurred during period | 305 | 3,416 | 271 | |||||||||
Liabilities settled during period | (704 | ) | (126 | ) | (297 | ) | ||||||
Accretion expense | 506 | 468 | 388 | |||||||||
Revision in previous estimates and other | 32 | 60 | 553 | |||||||||
Deletions related to property disposals | (645 | ) | (4,718 | ) | (2,227 | ) | ||||||
Asset retirement obligation, end of year | $ | 5,557 | $ | 6,063 | $ | 6,963 | ||||||
As of December 31, 2014, the current portion of the Company's asset retirement obligation was $82,000 and was recorded in current liabilities on the consolidated balance sheet. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||
Fair Value Measurements | Fair Value Measurements | |||||||||||||||
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, 2014 and 2013, management's evaluation of unproved properties resulted in an impairment. Due to continued low natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $3.3 million and $20.5 million of unproved properties to proved properties for the years ended December 31, 2014 and 2013, respectively. As no other fair value measurements are required to be recognized on a non-recurring basis at December 31, 2014, no additional disclosures are provided at December 31, 2014. | ||||||||||||||||
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 2014 and 2013 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, 2014 and 2013: | ||||||||||||||||
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 as of December 31, 2013 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Cash and cash equivalents | $ | 32,393 | $ | — | $ | — | $ | 32,393 | ||||||||
Restricted cash | — | — | — | — | ||||||||||||
Commodity derivative contracts | — | — | 7,545 | 7,545 | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivative contracts | — | — | (3,781 | ) | (3,781 | ) | ||||||||||
Total | $ | 32,393 | $ | — | $ | 3,764 | $ | 36,157 | ||||||||
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, 2014 and 2013. 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, 2014 and 2013. | ||||||||||||||||
For the years ended December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Balance at beginning of period | $ | 3,764 | $ | 6,465 | ||||||||||||
Total gains (losses) | ||||||||||||||||
included in earnings | 19,569 | (4,752 | ) | |||||||||||||
Purchases | 369 | 9,772 | ||||||||||||||
Issuances | — | (2,308 | ) | |||||||||||||
Settlements(1) | 3,800 | (5,413 | ) | |||||||||||||
Balance at end of period | $ | 27,502 | $ | 3,764 | ||||||||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2014 and 2013 | $ | 23,902 | $ | (9,967 | ) | |||||||||||
_________________________________ | ||||||||||||||||
-1 | Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. | |||||||||||||||
At December 31, 2014, 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, 2014 was $330.6 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, 2013 was $324.6 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_Hed
Derivative Instruments And Hedging Activity | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||
Derivative Instruments And Hedging Activity | Derivative Instruments and Hedging Activity | ||||||||||||||||||||||||
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 (loss) gain on commodity derivatives contracts. 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. For the years ended December 31, 2013 and 2012, the Company reported losses of $10.0 million and $5.6 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. | |||||||||||||||||||||||||
As of December 31, 2014, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: | |||||||||||||||||||||||||
Settlement Period | Derivative Instrument | Average | Total of | Base | Floor | Short | Ceiling | ||||||||||||||||||
Daily | Notional | Fixed | (Long) | Put | (Short) | ||||||||||||||||||||
Volume | Volume | Price | |||||||||||||||||||||||
(in MMBtu's) | |||||||||||||||||||||||||
2015(1) | Protective spread | 10,000 | 900,000 | $ | 4.46 | $ | — | $ | 3.7 | $ | — | ||||||||||||||
2015(1) | Call spread | 10,000 | 900,000 | $ | — | $ | — | $ | — | $ | 5 | ||||||||||||||
2015 | Fixed price swap | 400 | 146,000 | $ | 4 | $ | — | $ | — | $ | — | ||||||||||||||
2015 | Fixed price swap | 2,500 | 912,500 | $ | 4.06 | $ | — | $ | — | $ | — | ||||||||||||||
2015 | Protective spread | 2,600 | 949,000 | $ | 4 | $ | — | $ | 3.25 | $ | — | ||||||||||||||
2015(1) | Producer three-way collar | 3,750 | 337,500 | $ | — | $ | 4.6 | $ | 3.5 | $ | 5.34 | ||||||||||||||
2015(1) | Producer three-way collar | 2,500 | 337,500 | $ | — | $ | 4.4 | $ | 3.65 | $ | 5 | ||||||||||||||
2015 | Producer three-way collar | 2,000 | 760,000 | $ | — | $ | 4 | $ | 3.25 | $ | 4.58 | ||||||||||||||
2015 | Basis swap(2) | 2,500 | 912,500 | $ | (1.12 | ) | $ | — | $ | — | $ | — | |||||||||||||
2015 | Basis swap(2) | 2,500 | 912,500 | $ | (1.11 | ) | $ | — | $ | — | $ | — | |||||||||||||
2015 | Basis swap(2) | 2,500 | 912,500 | $ | (1.14 | ) | $ | — | $ | — | $ | — | |||||||||||||
2015(3) | Protective spread | 5,000 | 1,375,000 | $ | 4 | $ | — | $ | 3.25 | $ | — | ||||||||||||||
2015(3) | Producer three-way collar | 2,500 | 687,500 | $ | — | $ | 3.7 | $ | 3 | $ | 4.09 | ||||||||||||||
2015(3) | Producer three-way collar | 5,000 | 1,375,000 | $ | — | $ | 3.77 | $ | 3 | $ | 4.11 | ||||||||||||||
2016 | Protective spread | 2,000 | 732,000 | $ | 4.11 | $ | — | $ | 3.25 | $ | — | ||||||||||||||
_______________________________ | |||||||||||||||||||||||||
-1 | For the period January to March 2015. | ||||||||||||||||||||||||
-2 | Represents basis swaps at the sales point of Dominion South. | ||||||||||||||||||||||||
-3 | For the period April to December 2015. | ||||||||||||||||||||||||
As of December 31, 2014, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: | |||||||||||||||||||||||||
Settlement Period | Derivative Instrument | Average | Total of | Base | Floor | Short | Ceiling | ||||||||||||||||||
Daily | Notional | Fixed | (Long) | Put | (Short) | ||||||||||||||||||||
Volume (1) | Volume | Price | |||||||||||||||||||||||
(in Bbls) | |||||||||||||||||||||||||
2015(2) | Costless collar | 400 | 72,400 | $ | — | $ | 85 | $ | — | $ | 96.5 | ||||||||||||||
2015(2) | Costless collar | 366 | 66,300 | $ | — | $ | 85 | $ | — | $ | 97.8 | ||||||||||||||
2015(2) | Costless collar | 150 | 27,150 | $ | — | $ | 85 | $ | — | $ | 96.25 | ||||||||||||||
2015(3) | Costless three-way collar | 400 | 73,600 | $ | — | $ | 85 | $ | 70 | $ | 96.5 | ||||||||||||||
2015(3) | Costless three-way collar | 325 | 59,800 | $ | — | $ | 85 | $ | 65 | $ | 97.8 | ||||||||||||||
2015(3) | Costless three-way collar | 50 | 9,200 | $ | — | $ | 85 | $ | 65 | $ | 96.25 | ||||||||||||||
2015(2) | Put spread | 700 | 126,700 | $ | — | $ | 90 | $ | 70 | $ | — | ||||||||||||||
2015 | Put spread | 250 | 91,250 | $ | — | $ | 89 | $ | 69 | $ | — | ||||||||||||||
2015(3) | Put spread | 600 | 110,400 | $ | — | $ | 87 | $ | 67 | $ | — | ||||||||||||||
2016 | Costless three-way collar | 275 | 100,600 | $ | — | $ | 85 | $ | 65 | $ | 95.1 | ||||||||||||||
2016 | Costless three-way collar | 330 | 120,780 | $ | — | $ | 80 | $ | 65 | $ | 97.35 | ||||||||||||||
2016 | Put spread | 550 | 201,300 | $ | — | $ | 85 | $ | 65 | $ | — | ||||||||||||||
2016 | Put spread | 300 | 109,800 | $ | — | $ | 85.5 | $ | 65.5 | $ | — | ||||||||||||||
2017 | Costless three-way collar | 280 | 102,200 | $ | — | $ | 80 | $ | 65 | $ | 97.25 | ||||||||||||||
2017 | Costless three-way collar | 242 | 88,150 | $ | — | $ | 80 | $ | 60 | $ | 98.7 | ||||||||||||||
2017 | Put spread | 500 | 182,500 | $ | — | $ | 82 | $ | 62 | $ | — | ||||||||||||||
2018(4) | Put spread | 425 | 103,275 | $ | — | $ | 80 | $ | 60 | $ | — | ||||||||||||||
_______________________________ | |||||||||||||||||||||||||
-1 | Crude volumes hedged include oil, condensate and certain components of our NGLs production. | ||||||||||||||||||||||||
-2 | For the period January to June 2015. | ||||||||||||||||||||||||
-3 | For the period July to December 2015. | ||||||||||||||||||||||||
-4 | For the period January to August 2018. | ||||||||||||||||||||||||
As of December 31, 2014, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: | |||||||||||||||||||||||||
Settlement Period | Derivative Instrument | Average | Total of | Base | |||||||||||||||||||||
Daily | Notional | Fixed | |||||||||||||||||||||||
Volume | Volume | Price | |||||||||||||||||||||||
(in Bbls) | |||||||||||||||||||||||||
2015(1) | Fixed price swap | 250 | 68,750 | $ | 45.61 | ||||||||||||||||||||
_______________________________ | |||||||||||||||||||||||||
-1 | For the period April to December 2015. | ||||||||||||||||||||||||
As of December 31, 2014, 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 2014 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company began amortizing the deferred put premium liabilities in December 2013. The following table provides information regarding the deferred put premium liabilities for the periods indicated: | |||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Current commodity derivative premium put payable | $ | 2,481 | $ | 145 | |||||||||||||||||||||
Long-term commodity derivative premium payable | 4,702 | 7,000 | |||||||||||||||||||||||
Total unamortized put premium liabilities | $ | 7,183 | $ | 7,145 | |||||||||||||||||||||
For the Year December 31, 2014 | |||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Put premium liabilities, beginning balance | $ | 7,145 | |||||||||||||||||||||||
Less: | |||||||||||||||||||||||||
Amortization of put premium liabilities | (145 | ) | |||||||||||||||||||||||
Additional put premium liabilities | 183 | ||||||||||||||||||||||||
Put premium liabilities, ending balance | $ | 7,183 | |||||||||||||||||||||||
The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2014: | |||||||||||||||||||||||||
Amortization | |||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
January to December 2015 | $ | 2,481 | |||||||||||||||||||||||
January to December 2016 | 2,408 | ||||||||||||||||||||||||
January to December 2017 | 1,460 | ||||||||||||||||||||||||
January to August 2018 | 834 | ||||||||||||||||||||||||
Total unamortized put premium liabilities | $ | 7,183 | |||||||||||||||||||||||
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 | 2014 | 2013 | |||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||||
Commodity derivative contracts | Current assets | $ | 19,687 | $ | — | ||||||||||||||||||||
Commodity derivative contracts | Other assets | 7,815 | 7,545 | ||||||||||||||||||||||
Commodity derivative contracts | Current liabilities | — | (3,403 | ) | |||||||||||||||||||||
Commodity derivative contracts | Long-term liabilities | — | (378 | ) | |||||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 27,502 | $ | 3,764 | |||||||||||||||||||||
Amount of Gain (Loss) | |||||||||||||||||||||||||
Recognized in Income on | |||||||||||||||||||||||||
Derivatives For the Years Ended December 31, | |||||||||||||||||||||||||
Location of Gain (Loss) Recognized in | 2014 | 2013 | 2012 | ||||||||||||||||||||||
Income on Derivatives | |||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||||
Commodity derivative contracts | Gain (loss) on commodity derivatives contracts | $ | 19,569 | $ | (4,752 | ) | $ | 7,422 | |||||||||||||||||
Commodity derivative contracts | Interest expense | — | — | (186 | ) | ||||||||||||||||||||
Total | $ | 19,569 | $ | (4,752 | ) | $ | 7,236 | ||||||||||||||||||
Capital_Stock
Capital Stock | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Stockholders' Equity Note [Abstract] | ||||||
Capital Stock | 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. | ||||||
Preferred Stock | ||||||
Prior to the Conversion, Gastar USA’s articles of incorporation did not authorize issuance of preferred stock. | ||||||
Following the Conversion, Gastar USA’s Delaware certificate of incorporation allowed Gastar USA to issue 10,000,000 shares of preferred stock, par value $0.01 per share. The preferred stock was permitted to be issued from time to time in one or more series. Gastar USA’s Board of Directors (the “Gastar USA Board”) was authorized to fix the number of shares of any series of preferred stock and to determine the designation of any such series. The Gastar USA Board was also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued series of preferred stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series outstanding) the number of shares of any series subsequent to the issues shares of that series). Pursuant to the A&R Certificate, the number of shares of preferred stock authorized for issuance was increased to 40,000,000 shares. | ||||||
Series A Preferred Stock | ||||||
On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of its 8.625% Series A Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series A Preferred Stock”) through a best efforts underwritten public offering. The net proceeds to Gastar USA were approximately $13.6 million after deducting underwriting discounts, commissions and offering expenses. | ||||||
On June 29, 2011, Gastar USA entered into an at-the-market sales agreement (“ATM Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”). According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A Preferred Stock through MLV, as its sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV. | ||||||
For the year ended December 31, 2014, Gastar USA sold 86,840 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $2.1 million, resulting in 4,045,000 total shares of Series A Preferred Stock issued for total net proceeds, inception to date, of $78.8 million at December 31, 2014. | ||||||
The Series A Preferred Stock is subordinated to all of Gastar USA’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 of Gastar USA or the Company, but may be redeemed by Gastar USA, at Gastar USA’s option for $25.00 per share plus any accrued and unpaid dividends or in certain circumstances prior to such date as a result of a change in control. Following a change in control, Gastar USA will have the option to redeem the Series A Preferred Stock, in whole but not in part, within 90 days after the date on which the change in control occurs, for cash at $25.00 per share, plus accrued and unpaid dividends (whether or not declared), up to the redemption date. | ||||||
There is no mandatory redemption of the Series A Preferred Stock. | ||||||
Gastar USA 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, 2014, 2013 and 2012, Gastar USA paid dividends of $8.7 million, $8.5 million and $7.1 million, respectively. | ||||||
Series B Preferred Stock | ||||||
On October 29, 2013, Gastar USA sold 2,000,000 shares of its 10.75% Series B Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series B Preferred Stock”), in an underwritten public offering. On November 1, 2013, the underwriters partially exercised their option to purchase additional shares of Series B Preferred Stock and purchased an additional 140,000 shares of Series B Preferred Stock. The issuance of the 2,140,000 shares of Series B Preferred Stock closed on November 7, 2013 with Gastar USA receiving net proceeds of approximately $50.1 million after deducting underwriting commissions and offering expenses. | ||||||
The Series B Preferred Stock rank senior to Gastar USA’s common stock and on parity with its 8.625% Series A Cumulative 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 Gastar USA’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 Gastar USA’s option for $25.00 per share in cash. Following a change in ownership or control, Gastar USA will have the option to redeem the Series B Preferred Stock, 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 Gastar USA 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 up to and aggregate of 11.5207 shares of Gastar USA’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If Gastar USA 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. | ||||||
Gastar USA 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, 2014 and 2013, Gastar USA paid dividends of $5.8 million and $847,000, respectively. | ||||||
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, | ||||||
2014 | 2013 | |||||
Other stock issuances: | ||||||
Shares of restricted common stock granted | 601,473 | 2,288,179 | ||||
Shares of restricted common stock vested | 1,915,242 | 762,682 | ||||
Shares of common stock issued pursuant to PBUs vested, net of forfeitures | 472,189 | — | ||||
Stock options exercised | 7,500 | 10,000 | ||||
Shares of restricted common stock surrendered upon vesting/exercise (1) | 612,612 | 224,500 | ||||
Shares of restricted common stock forfeited | 47,398 | 512,862 | ||||
_______________________________ | ||||||
-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. | |||||
On June 7, 2012, Parent's stockholders voted to approve the Second Amendment to Parent's 2006 Long-Term Stock Incentive Plan. This amendment, effective June 3, 2012, increased the total number of shares available for issuance under the plan from 6,000,000 shares to 11,000,000 shares. 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 4,561,508 shares available for issuance under the LTIP at December 31, 2014. | ||||||
Shares Reserved | ||||||
At December 31, 2014, the Company had 866,600 shares of common stock reserved for the exercise of stock options and 990,658 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, 2014 | |||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||
Equity Compensation Plans | 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, 2014, 4,561,508 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. | |||||||||||||||||
Determining Fair Value of Stock Options | |||||||||||||||||
There were no stock options granted during the years ended December 31, 2014, 2013 and 2012. However, in prior years, the Company issued stock options as a component of its equity compensation program. As of December 31, 2014, all stock options were vested. In determining the fair value of stock option grants, the Company utilized the following assumptions: | |||||||||||||||||
Valuation and Amortization Method. The Company estimates the fair value of stock option awards using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.” | |||||||||||||||||
Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding. The Company determined the expected life to be 6.25 years, based on historical information, for all stock options issued with four-year vesting periods and ten-year grant expirations. | |||||||||||||||||
Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of the Company's common stock at the beginning of the quarter in which the stock option is granted. The volatility is based on weighted average historical movements of the Company's common stock price on the NYSE MKT LLC over a period that approximates the expected life. | |||||||||||||||||
Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life. | |||||||||||||||||
Expected Dividend Yield. The Company has not paid any cash dividends on its common stock and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model. | |||||||||||||||||
Expected Forfeitures. 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 2014, 2013 and 2012, the Company used forfeiture rates in determining compensation expense of 25.5%, 14% and 15.5%, respectively. | |||||||||||||||||
The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. | |||||||||||||||||
The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated: | |||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(in thousands, except per share data) | |||||||||||||||||
Weighted average grant date fair value per stock option granted | $ | — | $ | — | $ | — | |||||||||||
Intrinsic value of stock options exercised (1) | $ | 28 | $ | 19 | $ | 2 | |||||||||||
Grant date fair value of stock options vested | $ | 27 | $ | 88 | $ | 117 | |||||||||||
_______________________________ | |||||||||||||||||
-1 | Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised. | ||||||||||||||||
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, 2014: | |||||||||||||||||
Shares | Weighted Average | Weighted Average | Aggregate | ||||||||||||||
Exercise Price | Remaining | Intrinsic Value | |||||||||||||||
per Share | Contractual Term | (in thousands) | |||||||||||||||
(in years) | |||||||||||||||||
Outstanding at December 31, 2013 | 874,100 | $ | 11.68 | ||||||||||||||
Granted | — | — | |||||||||||||||
Exercised | (7,500 | ) | 2.6 | ||||||||||||||
Canceled/Expired | — | — | |||||||||||||||
Forfeited | — | — | |||||||||||||||
Outstanding at December 31, 2014 | 866,600 | $ | 11.75 | ||||||||||||||
Options vested and exercisable at December 31, 2014 | 866,600 | $ | 11.75 | 2.19 | $ | — | |||||||||||
Shares | Weighted Average | Weighted Average | Weighted Average | Aggregate | |||||||||||||
Fair Value | Exercise Price | Remaining | Intrinsic Value | ||||||||||||||
per Share | per Share | Contractual Term | (in thousands) | ||||||||||||||
(in years) | |||||||||||||||||
Outstanding non-vested options at December 31, 2013 | 10,000 | $ | 2.74 | ||||||||||||||
Granted | — | — | |||||||||||||||
Vested | (10,000 | ) | 2.74 | ||||||||||||||
Forfeited | — | — | |||||||||||||||
Outstanding non-vested options at December 31, 2014 | — | $ | — | $ | — | 0 | $ | — | |||||||||
There was no unrecognized expense as of December 31, 2014 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. Prior to December 31, 2014, 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. The following table summarizes information related to restricted shares at December 31, 2014: | |||||||||||||||||
Shares | Weighted Average | Weighted Average | Aggregate | ||||||||||||||
Fair Value | Remaining | Intrinsic Value (in thousands) | |||||||||||||||
per Share | Contractual Term | ||||||||||||||||
(in years) | |||||||||||||||||
Outstanding non-vested restricted shares at December 31, 2013 | 3,773,081 | $ | 1.82 | ||||||||||||||
Granted | 601,473 | 5.85 | |||||||||||||||
Vested | (1,915,242 | ) | 1.83 | ||||||||||||||
Forfeited | (47,398 | ) | 3.76 | ||||||||||||||
Outstanding non-vested restricted shares at December 31, 2014 | 2,411,914 | $ | 2.79 | 8.11 | $ | 5,813 | |||||||||||
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, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(in thousands, except per share data) | |||||||||||||||||
Weighted average grant date fair value per restricted share | $ | 5.85 | $ | 1.3 | $ | 2.09 | |||||||||||
Total fair value of restricted shares vested | $ | 3,497 | $ | 2,725 | $ | 2,492 | |||||||||||
Unrecognized compensation expense as of December 31, 2014 for all outstanding restricted share awards is $1.6 million and will be recognized over a weighted average period of 1.43 years. | |||||||||||||||||
Performance Based Units Activity | |||||||||||||||||
During 2014 and 2013, a portion of long-term incentive grants 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 Value per Unit | ||||||||||||||||
Unvested PBUs at December 31, 2013 | 1,065,734 | $ | 1.56 | ||||||||||||||
Granted | 280,171 | 7.34 | |||||||||||||||
Vested | (355,247 | ) | 1.56 | ||||||||||||||
Forfeited | — | — | |||||||||||||||
Unvested PBUs at December 31, 2014 | 990,658 | $ | 3.19 | ||||||||||||||
For the year ended December 31, 2014, the Company recognized $1.7 million of compensation expense associated with the PBUs. As of December 31, 2014, the Company had $1.1 million of total unrecognized expense for the PBUs. | |||||||||||||||||
Stock-Based Compensation Expense | |||||||||||||||||
For the years ended December 31, 2014, 2013 and 2012, the Company recorded stock-based compensation expense for restricted shares, PBUs, and stock options granted using the fair-value method of $4.9 million, $3.4 million and $3.3 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, 2014, the Company had approximately $2.8 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) | |||||||||||||||||
2015 | $ | 2,034 | |||||||||||||||
2016 | 663 | ||||||||||||||||
2017 | 59 | ||||||||||||||||
Total | $ | 2,756 | |||||||||||||||
Interest_Expense
Interest Expense | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Interest Expense [Abstract] | ||||||||||||
Interest Expense | Interest Expense | |||||||||||
The following tables summarize the components of the Company's interest expense for the periods indicated: | ||||||||||||
For the Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Interest expense: | ||||||||||||
Cash and accrued | $ | 28,851 | $ | 14,130 | $ | 1,992 | ||||||
Amortization of deferred financing costs(1)(2) | 3,067 | 2,322 | 224 | |||||||||
Capitalized interest | (4,347 | ) | (3,284 | ) | (1,946 | ) | ||||||
Total interest expense | $ | 27,571 | $ | 13,168 | $ | 270 | ||||||
_______________________________ | ||||||||||||
-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, 2014 and 2013 include $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, 2014 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 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, 2014, Chesapeake Energy Corporation did not own any of the Company's outstanding common stock. |
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||
Income Taxes | Income Taxes | |||||||||||
The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
United States | $ | 50,953 | $ | 51,276 | $ | (152,322 | ) | |||||
Foreign | — | (1,934 | ) | (1,469 | ) | |||||||
Total income (loss) before income taxes | $ | 50,953 | $ | 49,342 | $ | (153,791 | ) | |||||
The Company did not report any current provision for income taxes for the years ended December 31, 2014, 2013 and 2012. The Company’s deferred income tax expense (benefit) consists of the following for the periods presented: | ||||||||||||
For the Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Expected income tax provision (benefit) at statutory rate | $ | 17,833 | $ | 11,655 | $ | (53,827 | ) | |||||
State tax, tax effected | 803 | 96 | (2,562 | ) | ||||||||
Stock-based compensation expense | (1,291 | ) | 605 | 560 | ||||||||
Tax effect of Canadian tax rate differences | — | 193 | (125 | ) | ||||||||
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 | 38 | (49 | ) | 15 | ||||||||
Other changes in valuation allowance | (17,383 | ) | (38,777 | ) | 55,939 | |||||||
Actual income tax provision | $ | — | $ | (16,042 | ) | $ | — | |||||
The components of the Company’s U.S. deferred taxes are as follows: | ||||||||||||
As of December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax asset (liability): | ||||||||||||
Capital assets | $ | (134,223 | ) | $ | (77,456 | ) | ||||||
Stock-based compensation | 4,504 | 6,501 | ||||||||||
Net operating loss carry forwards | 164,056 | 122,675 | ||||||||||
Foreign tax credit carry forwards | 50,681 | 50,681 | ||||||||||
Valuation allowance | (85,018 | ) | (102,401 | ) | ||||||||
Net deferred tax asset | $ | — | $ | — | ||||||||
The Company has approximately $447.0 million of net operating loss carry forwards as of December 31, 2014, which, if not utilized, will expire between 2030 and 2034. For U.S. federal income tax purposes, as of December 31, 2014, 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. is not expected to 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, 2014, 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 forward and the foreign jurisdictions of Canada and Australia for the tax periods 2000 and forward due to the Company’s continued loss position in such jurisdictions. | ||||||||||||
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, 2014 | ||||||||||||
Earnings Per Share [Abstract] | ||||||||||||
Earnings Per Share | 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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands, except per share and share data) | ||||||||||||
Net income (loss) attributable to common stockholders | $ | 36,529 | $ | 39,964 | $ | (160,868 | ) | |||||
Weighted average shares of common stock outstanding - basic | 63,270,733 | 60,220,115 | 63,538,362 | |||||||||
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 | 66,492,589 | 63,618,401 | 63,538,362 | |||||||||
Net income (loss) per share of common stock attributable to common stockholders: | ||||||||||||
Basic | $ | 0.58 | $ | 0.66 | $ | (2.53 | ) | |||||
Diluted | $ | 0.55 | $ | 0.63 | $ | (2.53 | ) | |||||
Shares of common stock excluded from denominator as anti-dilutive: | ||||||||||||
Unvested restricted shares | 34,058 | 3,505 | 1,831,435 | |||||||||
Stock options | — | — | 936,967 | |||||||||
Total | 34,058 | 3,505 | 2,768,402 | |||||||||
Commitments_And_Contingencies
Commitments And Contingencies | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Commitments and Contingencies Disclosure [Abstract] | ||||
Commitments And Contingencies | Commitments and Contingencies | |||
Contractual Obligations | ||||
The Company leases its office facilities and certain office equipment under non-cancelable operating lease agreements terminating in October 2018. For the years ended December 31, 2014, 2013 and 2012, office lease expense totaled approximately $649,000, $372,000 and $377,000, respectively. | ||||
As of December 31, 2014, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: | ||||
2015 | $ | 640 | ||
2016 | 498 | |||
2017 | 187 | |||
2018 | 161 | |||
$ | 1,486 | |||
Litigation | ||||
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. | ||||
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. | ||||
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 sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The case will be remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements. | ||||
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 13,700 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. Proved undeveloped well locations on this lease accounted for 87.7 Bcfe, or 19%, of the Gastar's total company proved reserves at June 30, 2014. 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 now plans to move to dismiss the suit in Pennsylvania on account of mootness. Gastar is currently seeking attorney’s fees and damages in West Virginia and also plans to seek attorney’s fees and damages in Pennsylvania pending disposition of the matter. | ||||
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 is 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. | ||||
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, 2014, the Company had total liabilities of $5.6 million related to asset retirement obligations of which $82,000 is recorded as short-term liabilities and $5.5 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. 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_Sign
Concentration of Risk and Significant Customers | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Risks and Uncertainties [Abstract] | ||||||||||
Concentration of Risk and Significant Customers | 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, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Appalachian Basin | 39 | % | 65 | % | 72 | % | ||||
Mid-Continent | 61 | % | 26 | % | — | % | ||||
Hilltop Area, East Texas(1) | — | % | 9 | % | 27 | % | ||||
Powder River Basin(2) | — | % | — | % | 1 | % | ||||
_______________________________ | ||||||||||
-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. | |||||||||
-2 | The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012. | |||||||||
The following table provides information regarding our significant customers and the percentages of oil, condensate, natural gas and NGLs revenues, excluding hedge impact, which they represented for the periods indicated: | ||||||||||
For the Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
SEI | 50 | % | 56 | % | 47 | % | ||||
Sunoco | 37 | % | 16 | % | — | % | ||||
Clearfield Appalachian | — | % | 8 | % | 14 | % | ||||
ETC | — | % | 8 | % | 24 | % | ||||
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. 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. Prior to the Company's sale of its interest in East Texas, ETC treated, transported and purchased substantially all of the Company’s East Texas natural gas production. |
Statement_Of_Cash_Flows_Supple
Statement Of Cash Flows - Supplemental Information | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Supplemental Cash Flow Information [Abstract] | ||||||||||||
Statement Of Cash Flows - Supplemental Information | 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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Cash paid for interest, net of capitalized amounts | $ | 24,632 | $ | 7,341 | $ | 39 | ||||||
Non-cash transactions: | ||||||||||||
Capital expenditures included in accounts payable and accrued drilling costs | $ | 12,777 | $ | 582 | $ | 4,666 | ||||||
Capital expenditures included in accounts receivable | 4,077 | (4,077 | ) | (929 | ) | |||||||
Asset retirement obligation included in oil and natural gas properties | 221 | (1,302 | ) | 1,164 | ||||||||
Asset retirement obligation sold/assigned to operator | (645 | ) | (4,354 | ) | (2,227 | ) | ||||||
Application of advances to operators | 58,326 | 19,755 | 7,441 | |||||||||
Other | (11 | ) | 47 | (36 | ) | |||||||
Quarterly_Consolidated_Financi
Quarterly Consolidated Financial Data - Unaudited | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Quarterly Consolidated Financial Data - Unaudited | Quarterly Consolidated Financial Data – Unaudited | |||||||||||||||
The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2014 and 2013: | ||||||||||||||||
2014 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | 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 | ||||||||||||
2013 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
(in thousands, except share and per share data) | ||||||||||||||||
Revenues | $ | 11,264 | $ | 30,926 | $ | 18,840 | $ | 26,725 | ||||||||
(Loss) income from operations | (1,849 | ) | 13,809 | 1,626 | 5,178 | |||||||||||
(Loss) income before provision for income taxes(1) | (2,456 | ) | 53,970 | (1,808 | ) | (16,406 | ) | |||||||||
Net (loss) income | (2,456 | ) | 53,970 | (1,808 | ) | (364 | ) | |||||||||
Dividend on preferred stock | 2,130 | 2,134 | 2,134 | 2,980 | ||||||||||||
Net (loss) income attributable to common stockholders | (4,586 | ) | 51,836 | (3,942 | ) | (3,344 | ) | |||||||||
Net (loss) income per share of common stock attributable to common stockholders: | ||||||||||||||||
Basic | $ | (0.07 | ) | $ | 0.83 | $ | (0.07 | ) | $ | (0.06 | ) | |||||
Diluted | $ | (0.07 | ) | $ | 0.81 | $ | (0.07 | ) | $ | (0.06 | ) | |||||
Weighted average shares of common stock outstanding: | ||||||||||||||||
Basic | 63,864,527 | 62,398,472 | 57,359,357 | 57,433,550 | ||||||||||||
Diluted | 63,864,527 | 63,813,423 | 57,359,357 | 57,433,550 | ||||||||||||
_________________________________ | ||||||||||||||||
-1 | Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million. |
Supplemental_Oil_and_Gas_Discl
Supplemental Oil and Gas Disclosures - Unaudited | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Extractive Industries [Abstract] | |||||||||||||
Supplemental Oil and Disclosures - Unaudited | Supplemental Oil and Gas Disclosures – Unaudited | ||||||||||||
Capitalized Costs Relating Oil and Producing Activities | |||||||||||||
The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities for the periods indicated: | |||||||||||||
As of December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Proved properties: | |||||||||||||
United States | $ | 1,124,367 | $ | 935,773 | $ | 671,193 | |||||||
Total proved properties | 1,124,367 | 935,773 | 671,193 | ||||||||||
Unproved properties: | |||||||||||||
United States | 128,274 | 96,220 | 67,892 | ||||||||||
Total unproved properties | 128,274 | 96,220 | 67,892 | ||||||||||
Total oil and natural gas properties | 1,252,641 | 1,031,993 | 739,085 | ||||||||||
Less: | |||||||||||||
Impairment of proved oil and natural gas properties | |||||||||||||
United States | (337,939 | ) | (337,939 | ) | (337,939 | ) | |||||||
Accumulated depreciation, depletion and amortization | (223,555 | ) | (177,790 | ) | (145,631 | ) | |||||||
Net capitalized costs | $ | 691,147 | $ | 516,264 | $ | 255,515 | |||||||
Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $2.4 million, $3.4 million and $4.8 million at December 31, 2014, 2013 and 2012, 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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Property acquisition | |||||||||||||
Proved(1) | $ | — | $ | 189,594 | $ | — | |||||||
Unproved(2) | 41,475 | 71,472 | 25,676 | ||||||||||
Exploration | 127,384 | 36,893 | 10,041 | ||||||||||
Development | 57,913 | 53,058 | 111,878 | ||||||||||
Total costs incurred | $ | 226,772 | $ | 351,017 | $ | 147,595 | |||||||
_________________________________ | |||||||||||||
-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 for the periods indicated: | |||||||||||||
For the Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands, except per Mcfe data) | |||||||||||||
Oil, condensate, natural gas and NGLs sales, including commodity derivatives | $ | 171,418 | $ | 87,755 | $ | 49,940 | |||||||
Production expenses | (29,735 | ) | (18,113 | ) | (13,408 | ) | |||||||
Impairment of oil and natural gas properties | — | — | (150,787 | ) | |||||||||
Depreciation, depletion and amortization | (45,765 | ) | (32,158 | ) | (25,195 | ) | |||||||
Results of producing activities | $ | 95,918 | $ | 37,484 | $ | (139,450 | ) | ||||||
Depreciation, depletion and amortization per MBoe | $ | 12.34 | $ | 9.94 | $ | 11.41 | |||||||
The results of producing activities exclude interest charges and general corporate expenses and represent U.S. activities only. | |||||||||||||
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, 2014 and 2013. 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, | |||||||||||||
2014 | 2013 | ||||||||||||
Natural gas (per MMBtu): | |||||||||||||
Henry Hub | $ | 4.35 | $ | 3.67 | |||||||||
Oil (per Bbl): | |||||||||||||
WTI spot | $ | 94.99 | 96.78 | ||||||||||
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, 2014, 2013, and 2012 and includes reserve information for the Appalachian Basin as of December 31, 2014, 2013, and 2012, reserve information for the Mid-Continent as of December 31, 2014 and reserve information for the Hilltop Area of East Texas as of 2012. The Company sold its working interest in the Hilltop Area of East Texas on October 2, 2013, with an effective date of January 1, 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, 2014, 2013 and 2012: | |||||||||||||
Change in Proved Reserves | Natural Gas | NGLs | Condensate and Oil | MBoe (3) Equivalents (4) | |||||||||
(MMcf) (1) | (MBbl) (2) | (MBbl) (2) | |||||||||||
Proved reserves as of December 31, 2011 | 91,652 | 2,757 | 1,921 | 19,953 | |||||||||
2012 Activity: | |||||||||||||
Extensions and discoveries(5) | 57,835 | 2,783 | 2,439 | 14,861 | |||||||||
Revisions of previous estimates | (6,518 | ) | (348 | ) | (796 | ) | (2,230 | ) | |||||
Production | (10,564 | ) | (270 | ) | (177 | ) | (2,208 | ) | |||||
Purchases in place | — | — | 7 | 7 | |||||||||
Sales in place | (1,395 | ) | — | — | (231 | ) | |||||||
Proved reserves as of December 31, 2012 | 131,010 | 4,922 | 3,394 | 30,152 | |||||||||
2013 Activity: | |||||||||||||
Extensions and discoveries(6) | 52,750 | 2,306 | 4,385 | 15,483 | |||||||||
Revisions of previous estimates | 8,114 | 714 | (337 | ) | 1,729 | ||||||||
Production | (13,366 | ) | (494 | ) | (515 | ) | (3,237 | ) | |||||
Purchases in place | 26,961 | 2,350 | 7,796 | 14,639 | |||||||||
Sales in place | (24,759 | ) | — | (5 | ) | (4,132 | ) | ||||||
Proved reserves as of December 31, 2013 | 180,710 | 9,798 | 14,718 | 54,634 | |||||||||
2014 Activity: | |||||||||||||
Extensions and discoveries(7) | 121,672 | 9,394 | 13,137 | 42,810 | |||||||||
Revisions of previous estimates | (2,465 | ) | 7,205 | 1,780 | 8,574 | ||||||||
Production | (11,598 | ) | (800 | ) | (975 | ) | (3,708 | ) | |||||
Sales in place | (1,314 | ) | (4 | ) | (24 | ) | (247 | ) | |||||
Proved reserves as of December 31, 2014 | 287,005 | 25,593 | 28,636 | 102,063 | |||||||||
_________________________________ | |||||||||||||
(1)Million cubic feet or million cubic feet equivalent, as applicable | |||||||||||||
-2 | Thousand barrels | ||||||||||||
-3 | Thousand barrels of oil, condensate or NGLs equivalent. | ||||||||||||
-4 | 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. | ||||||||||||
-5 | The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery. | ||||||||||||
-6 | 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. | ||||||||||||
-7 | 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. | ||||||||||||
Proved Developed and Undeveloped Reserves | Natural Gas | NGLs | Condensate and Oil | MBoe (3) Equivalents (4) | |||||||||
(MMcf) (1) | (MBbl) (2) | (MBbl) (2) | |||||||||||
31-Dec-12 | |||||||||||||
Proved developed reserves | 95,602 | 3,215.80 | 1,959 | 21,109 | |||||||||
Proved undeveloped reserves | 35,408 | 1,706 | 1,435 | 9,042 | |||||||||
Total | 131,010 | 4,922 | 3,394 | 30,151 | |||||||||
31-Dec-13 | |||||||||||||
Proved developed reserves | 114,195 | 6,025 | 5,834 | 30,892 | |||||||||
Proved undeveloped reserves | 66,515 | 3,773 | 8,884 | 23,742 | |||||||||
Total | 180,710 | 9,798 | 14,718 | 54,634 | |||||||||
31-Dec-14 | |||||||||||||
Proved developed reserves | 114,564 | 10,726 | 6,968 | 36,789 | |||||||||
Proved undeveloped reserves | 172,441 | 14,867 | 21,668 | 65,274 | |||||||||
Total | 287,005 | 25,593 | 28,636 | 102,063 | |||||||||
_________________________________ | |||||||||||||
(1)Million cubic feet or million cubic feet equivalent, as applicable | |||||||||||||
-2 | Thousand barrels | ||||||||||||
-3 | Thousand barrels of oil, condensate or NGLs equivalent. | ||||||||||||
-4 | 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, 2014, 2013 and 2012 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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Natural gas, per MMBtu | |||||||||||||
Henry Hub | $ | 4.35 | $ | 3.67 | $ | 2.76 | |||||||
Oil, per barrel: | |||||||||||||
WTI spot | $ | 94.99 | $ | 96.78 | $ | 94.71 | |||||||
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 is presented below: | |||||||||||||
United States | |||||||||||||
(in thousands) | |||||||||||||
December 31, 2012: | |||||||||||||
Future cash inflows | $ | 672,142 | |||||||||||
Future production costs | (167,864 | ) | |||||||||||
Future development costs | (83,697 | ) | |||||||||||
Future income taxes(1) | — | ||||||||||||
Future net cash flows | 420,581 | ||||||||||||
10% annual discount for estimated timing of cash flows | (213,772 | ) | |||||||||||
Standardized measure of discounted future cash flows | $ | 206,809 | |||||||||||
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 | |||||||||||
_________________________________ | |||||||||||||
-1 | No future taxes payable has been included in the determination of discounted future net cash flows for 2012 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: | |||||||||||||
United States | |||||||||||||
(in thousands) | |||||||||||||
December 31, 2011 | $ | 212,783 | |||||||||||
Extensions and discoveries, less related costs | 112,390 | ||||||||||||
Sale of natural gas and oil, net of production costs | (29,110 | ) | |||||||||||
Purchases of reserves in place | 64 | ||||||||||||
Sales of reserves in place | (216 | ) | |||||||||||
Revisions of previous quantity estimates | (30,959 | ) | |||||||||||
Net change in income tax | 4,334 | ||||||||||||
Net change in prices and production costs | (98,589 | ) | |||||||||||
Accretion of discount | 1,152 | ||||||||||||
Development costs incurred | 19,702 | ||||||||||||
Net change in estimated future development costs | 2,518 | ||||||||||||
Change in production rates (timing) and other | 12,740 | ||||||||||||
31-Dec-12 | $ | 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 | ||||||||||||
31-Dec-13 | $ | 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 | (1,277 | ) | |||||||||||
Change in production rates (timing) and other | (43,081 | ) | |||||||||||
31-Dec-14 | $ | 816,739 | |||||||||||
Recovered_Sheet1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
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 prior year balances are those of Gastar Exploration, Inc. | |
Reclassifications | Reclassifications |
Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact on net income (loss). | |
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. | |
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 $11.0 million and $32.4 million as of December 31, 2014 and 2013, 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. | |
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, 2014 and 2013 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, 2014. 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. | |
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. | |
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 (loss) gain 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 (loss) gain 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. The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. The Company did not award any stock option grants during 2014, 2013 or 2012. | |
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, 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 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 stock options, unvested restricted shares and PBUs. | |
Joint Venture Operations | Joint Venture 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: | |
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. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows. | |
Income taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this guidance did not impact the Company's operating results, financial position or cash flows. |
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Allowance for doubtful accounts, beginning of year | $ | 507 | $ | 546 | $ | 551 | ||||||
Expense | — | — | — | |||||||||
Reductions/write-offs | (507 | ) | (39 | ) | (5 | ) | ||||||
Allowance for doubtful accounts, end of year | $ | — | $ | 507 | $ | 546 | ||||||
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, | ||||||||||||
2014 | 2013 | |||||||||||
Deferred charges | $ | 3,664 | $ | 3,269 | ||||||||
Accumulated amortization | (1,078 | ) | (319 | ) | ||||||||
Deferred charges, net | $ | 2,586 | $ | 2,950 | ||||||||
Property_Plant_And_Equipment_T
Property, Plant And Equipment (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Property, Plant and Equipment | The Company's total property, plant and equipment consists of the following: | ||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Oil and natural gas properties, full cost method of accounting: | |||||||||||||||||||||
Unproved properties | $ | 128,274 | $ | 96,220 | |||||||||||||||||
Proved properties | 1,124,367 | 935,773 | |||||||||||||||||||
Total oil and natural gas properties | 1,252,641 | 1,031,993 | |||||||||||||||||||
Furniture and equipment | 3,010 | 2,691 | |||||||||||||||||||
Total property and equipment | 1,255,651 | 1,034,684 | |||||||||||||||||||
Impairment of proved natural gas and oil properties | (337,939 | ) | (337,939 | ) | |||||||||||||||||
Accumulated depreciation, depletion and amortization | (225,412 | ) | (179,232 | ) | |||||||||||||||||
Total accumulated depreciation, depletion and amortization | (563,351 | ) | (517,171 | ) | |||||||||||||||||
Total property and equipment, net | $ | 692,300 | $ | 517,513 | |||||||||||||||||
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, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Unproved properties, excluded from amortization: | |||||||||||||||||||||
Drilling in progress costs | $ | 29,193 | $ | 4,774 | |||||||||||||||||
Acreage acquisition costs | 91,362 | 86,097 | |||||||||||||||||||
Capitalized interest | 7,719 | 5,349 | |||||||||||||||||||
Total unproved properties excluded from amortization | $ | 128,274 | $ | 96,220 | |||||||||||||||||
Schedule of Relevant Assumptions Used in Ceiling Test Computations | The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted: | ||||||||||||||||||||
2014 | |||||||||||||||||||||
Total Impairment | 31-Dec | 30-Sep | 30-Jun | 31-Mar | |||||||||||||||||
Henry Hub natural gas price (per MMBtu)(1) | $ | 4.35 | $ | 4.24 | $ | 4.1 | $ | 3.99 | |||||||||||||
West Texas Intermediate oil price (per Bbl)(1) | $ | 94.99 | $ | 99.08 | $ | 100.11 | $ | 98.3 | |||||||||||||
Impairment recorded (pre-tax) (in thousands) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
2013 | |||||||||||||||||||||
Total Impairment | 31-Dec | 30-Sep | 30-Jun | 31-Mar | |||||||||||||||||
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) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
2012 | |||||||||||||||||||||
Total Impairment | 31-Dec | 30-Sep | 30-Jun | 31-Mar | |||||||||||||||||
Henry Hub natural gas price (per MMBtu)(1) | $ | 2.76 | $ | 2.83 | $ | 3.15 | $ | 3.73 | |||||||||||||
West Texas Intermediate oil price (per Bbl)(1) | $ | 91.21 | $ | 91.48 | $ | 92.17 | $ | 94.65 | |||||||||||||
Impairment recorded (pre-tax) (in thousands) | $ | 150,787 | $ | — | $ | 78,054 | $ | 72,733 | $ | — | |||||||||||
_________________________________ | |||||||||||||||||||||
-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. | ||||||||||||||||||||
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 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, 2013 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Revenues | $ | 11,292 | |||||||||||||||||||
Excess of revenues over direct operating expenses | $ | 7,591 | |||||||||||||||||||
The following unaudited pro forma results for the years ended December 31, 2013 and 2012 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of each respective 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 the Years Ended December 31, | |||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
(in thousands, except per share data) | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
Revenues | $ | 132,721 | $ | 97,760 | |||||||||||||||||
Net Loss | $ | (4,836 | ) | $ | (175,809 | ) | |||||||||||||||
Loss per share: | |||||||||||||||||||||
Basic | $ | (0.08 | ) | $ | (2.77 | ) | |||||||||||||||
Diluted | $ | (0.08 | ) | $ | (2.77 | ) |
Asset_Retirement_Obligation_Ta
Asset Retirement Obligation (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Asset retirement obligation, beginning of year | $ | 6,063 | $ | 6,963 | $ | 8,275 | ||||||
Liabilities incurred during period | 305 | 3,416 | 271 | |||||||||
Liabilities settled during period | (704 | ) | (126 | ) | (297 | ) | ||||||
Accretion expense | 506 | 468 | 388 | |||||||||
Revision in previous estimates and other | 32 | 60 | 553 | |||||||||
Deletions related to property disposals | (645 | ) | (4,718 | ) | (2,227 | ) | ||||||
Asset retirement obligation, end of year | $ | 5,557 | $ | 6,063 | $ | 6,963 | ||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
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, 2014 and 2013: | |||||||||||||||
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 as of December 31, 2013 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Cash and cash equivalents | $ | 32,393 | $ | — | $ | — | $ | 32,393 | ||||||||
Restricted cash | — | — | — | — | ||||||||||||
Commodity derivative contracts | — | — | 7,545 | 7,545 | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivative contracts | — | — | (3,781 | ) | (3,781 | ) | ||||||||||
Total | $ | 32,393 | $ | — | $ | 3,764 | $ | 36,157 | ||||||||
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, 2014 and 2013. 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, 2014 and 2013. | |||||||||||||||
For the years ended December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Balance at beginning of period | $ | 3,764 | $ | 6,465 | ||||||||||||
Total gains (losses) | ||||||||||||||||
included in earnings | 19,569 | (4,752 | ) | |||||||||||||
Purchases | 369 | 9,772 | ||||||||||||||
Issuances | — | (2,308 | ) | |||||||||||||
Settlements(1) | 3,800 | (5,413 | ) | |||||||||||||
Balance at end of period | $ | 27,502 | $ | 3,764 | ||||||||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2014 and 2013 | $ | 23,902 | $ | (9,967 | ) | |||||||||||
_________________________________ | ||||||||||||||||
-1 | Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. |
Derivative_Instruments_And_Hed1
Derivative Instruments And Hedging Activity (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||||
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location | The following table provides information regarding the deferred put premium liabilities for the periods indicated: | ||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Current commodity derivative premium put payable | $ | 2,481 | $ | 145 | |||||||||||||||||||||
Long-term commodity derivative premium payable | 4,702 | 7,000 | |||||||||||||||||||||||
Total unamortized put premium liabilities | $ | 7,183 | $ | 7,145 | |||||||||||||||||||||
Schedule of Deferred Put Premium Liability | |||||||||||||||||||||||||
For the Year December 31, 2014 | |||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Put premium liabilities, beginning balance | $ | 7,145 | |||||||||||||||||||||||
Less: | |||||||||||||||||||||||||
Amortization of put premium liabilities | (145 | ) | |||||||||||||||||||||||
Additional put premium liabilities | 183 | ||||||||||||||||||||||||
Put premium liabilities, ending balance | $ | 7,183 | |||||||||||||||||||||||
Schedule of Future 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, 2014: | ||||||||||||||||||||||||
Amortization | |||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
January to December 2015 | $ | 2,481 | |||||||||||||||||||||||
January to December 2016 | 2,408 | ||||||||||||||||||||||||
January to December 2017 | 1,460 | ||||||||||||||||||||||||
January to August 2018 | 834 | ||||||||||||||||||||||||
Total unamortized put premium liabilities | $ | 7,183 | |||||||||||||||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location | 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 | 2014 | 2013 | |||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||||
Commodity derivative contracts | Current assets | $ | 19,687 | $ | — | ||||||||||||||||||||
Commodity derivative contracts | Other assets | 7,815 | 7,545 | ||||||||||||||||||||||
Commodity derivative contracts | Current liabilities | — | (3,403 | ) | |||||||||||||||||||||
Commodity derivative contracts | Long-term liabilities | — | (378 | ) | |||||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 27,502 | $ | 3,764 | |||||||||||||||||||||
Amount of Gain (Loss) | |||||||||||||||||||||||||
Recognized in Income on | |||||||||||||||||||||||||
Derivatives For the Years Ended December 31, | |||||||||||||||||||||||||
Location of Gain (Loss) Recognized in | 2014 | 2013 | 2012 | ||||||||||||||||||||||
Income on Derivatives | |||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||||
Commodity derivative contracts | Gain (loss) on commodity derivatives contracts | $ | 19,569 | $ | (4,752 | ) | $ | 7,422 | |||||||||||||||||
Commodity derivative contracts | Interest expense | — | — | (186 | ) | ||||||||||||||||||||
Total | $ | 19,569 | $ | (4,752 | ) | $ | 7,236 | ||||||||||||||||||
Natural Gas | |||||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, 2014, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: | ||||||||||||||||||||||||
Settlement Period | Derivative Instrument | Average | Total of | Base | Floor | Short | Ceiling | ||||||||||||||||||
Daily | Notional | Fixed | (Long) | Put | (Short) | ||||||||||||||||||||
Volume | Volume | Price | |||||||||||||||||||||||
(in MMBtu's) | |||||||||||||||||||||||||
2015(1) | Protective spread | 10,000 | 900,000 | $ | 4.46 | $ | — | $ | 3.7 | $ | — | ||||||||||||||
2015(1) | Call spread | 10,000 | 900,000 | $ | — | $ | — | $ | — | $ | 5 | ||||||||||||||
2015 | Fixed price swap | 400 | 146,000 | $ | 4 | $ | — | $ | — | $ | — | ||||||||||||||
2015 | Fixed price swap | 2,500 | 912,500 | $ | 4.06 | $ | — | $ | — | $ | — | ||||||||||||||
2015 | Protective spread | 2,600 | 949,000 | $ | 4 | $ | — | $ | 3.25 | $ | — | ||||||||||||||
2015(1) | Producer three-way collar | 3,750 | 337,500 | $ | — | $ | 4.6 | $ | 3.5 | $ | 5.34 | ||||||||||||||
2015(1) | Producer three-way collar | 2,500 | 337,500 | $ | — | $ | 4.4 | $ | 3.65 | $ | 5 | ||||||||||||||
2015 | Producer three-way collar | 2,000 | 760,000 | $ | — | $ | 4 | $ | 3.25 | $ | 4.58 | ||||||||||||||
2015 | Basis swap(2) | 2,500 | 912,500 | $ | (1.12 | ) | $ | — | $ | — | $ | — | |||||||||||||
2015 | Basis swap(2) | 2,500 | 912,500 | $ | (1.11 | ) | $ | — | $ | — | $ | — | |||||||||||||
2015 | Basis swap(2) | 2,500 | 912,500 | $ | (1.14 | ) | $ | — | $ | — | $ | — | |||||||||||||
2015(3) | Protective spread | 5,000 | 1,375,000 | $ | 4 | $ | — | $ | 3.25 | $ | — | ||||||||||||||
2015(3) | Producer three-way collar | 2,500 | 687,500 | $ | — | $ | 3.7 | $ | 3 | $ | 4.09 | ||||||||||||||
2015(3) | Producer three-way collar | 5,000 | 1,375,000 | $ | — | $ | 3.77 | $ | 3 | $ | 4.11 | ||||||||||||||
2016 | Protective spread | 2,000 | 732,000 | $ | 4.11 | $ | — | $ | 3.25 | $ | — | ||||||||||||||
_______________________________ | |||||||||||||||||||||||||
-1 | For the period January to March 2015. | ||||||||||||||||||||||||
-2 | Represents basis swaps at the sales point of Dominion South. | ||||||||||||||||||||||||
-3 | For the period April to December 2015. | ||||||||||||||||||||||||
Crude Oil | |||||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, 2014, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: | ||||||||||||||||||||||||
Settlement Period | Derivative Instrument | Average | Total of | Base | Floor | Short | Ceiling | ||||||||||||||||||
Daily | Notional | Fixed | (Long) | Put | (Short) | ||||||||||||||||||||
Volume (1) | Volume | Price | |||||||||||||||||||||||
(in Bbls) | |||||||||||||||||||||||||
2015(2) | Costless collar | 400 | 72,400 | $ | — | $ | 85 | $ | — | $ | 96.5 | ||||||||||||||
2015(2) | Costless collar | 366 | 66,300 | $ | — | $ | 85 | $ | — | $ | 97.8 | ||||||||||||||
2015(2) | Costless collar | 150 | 27,150 | $ | — | $ | 85 | $ | — | $ | 96.25 | ||||||||||||||
2015(3) | Costless three-way collar | 400 | 73,600 | $ | — | $ | 85 | $ | 70 | $ | 96.5 | ||||||||||||||
2015(3) | Costless three-way collar | 325 | 59,800 | $ | — | $ | 85 | $ | 65 | $ | 97.8 | ||||||||||||||
2015(3) | Costless three-way collar | 50 | 9,200 | $ | — | $ | 85 | $ | 65 | $ | 96.25 | ||||||||||||||
2015(2) | Put spread | 700 | 126,700 | $ | — | $ | 90 | $ | 70 | $ | — | ||||||||||||||
2015 | Put spread | 250 | 91,250 | $ | — | $ | 89 | $ | 69 | $ | — | ||||||||||||||
2015(3) | Put spread | 600 | 110,400 | $ | — | $ | 87 | $ | 67 | $ | — | ||||||||||||||
2016 | Costless three-way collar | 275 | 100,600 | $ | — | $ | 85 | $ | 65 | $ | 95.1 | ||||||||||||||
2016 | Costless three-way collar | 330 | 120,780 | $ | — | $ | 80 | $ | 65 | $ | 97.35 | ||||||||||||||
2016 | Put spread | 550 | 201,300 | $ | — | $ | 85 | $ | 65 | $ | — | ||||||||||||||
2016 | Put spread | 300 | 109,800 | $ | — | $ | 85.5 | $ | 65.5 | $ | — | ||||||||||||||
2017 | Costless three-way collar | 280 | 102,200 | $ | — | $ | 80 | $ | 65 | $ | 97.25 | ||||||||||||||
2017 | Costless three-way collar | 242 | 88,150 | $ | — | $ | 80 | $ | 60 | $ | 98.7 | ||||||||||||||
2017 | Put spread | 500 | 182,500 | $ | — | $ | 82 | $ | 62 | $ | — | ||||||||||||||
2018(4) | Put spread | 425 | 103,275 | $ | — | $ | 80 | $ | 60 | $ | — | ||||||||||||||
_______________________________ | |||||||||||||||||||||||||
-1 | Crude volumes hedged include oil, condensate and certain components of our NGLs production. | ||||||||||||||||||||||||
-2 | For the period January to June 2015. | ||||||||||||||||||||||||
-3 | For the period July to December 2015. | ||||||||||||||||||||||||
-4 | For the period January to August 2018. | ||||||||||||||||||||||||
Natural Gas Liquids | |||||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, 2014, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: | ||||||||||||||||||||||||
Settlement Period | Derivative Instrument | Average | Total of | Base | |||||||||||||||||||||
Daily | Notional | Fixed | |||||||||||||||||||||||
Volume | Volume | Price | |||||||||||||||||||||||
(in Bbls) | |||||||||||||||||||||||||
2015(1) | Fixed price swap | 250 | 68,750 | $ | 45.61 | ||||||||||||||||||||
_______________________________ | |||||||||||||||||||||||||
-1 | For the period April to December 2015. |
Capital_Stock_Tables
Capital Stock (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
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, | ||||||
2014 | 2013 | |||||
Other stock issuances: | ||||||
Shares of restricted common stock granted | 601,473 | 2,288,179 | ||||
Shares of restricted common stock vested | 1,915,242 | 762,682 | ||||
Shares of common stock issued pursuant to PBUs vested, net of forfeitures | 472,189 | — | ||||
Stock options exercised | 7,500 | 10,000 | ||||
Shares of restricted common stock surrendered upon vesting/exercise (1) | 612,612 | 224,500 | ||||
Shares of restricted common stock forfeited | 47,398 | 512,862 | ||||
_______________________________ | ||||||
-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, 2014 | |||||||||||||||||
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, 2014: | ||||||||||||||||
Shares | Weighted Average | Weighted Average | Aggregate | ||||||||||||||
Exercise Price | Remaining | Intrinsic Value | |||||||||||||||
per Share | Contractual Term | (in thousands) | |||||||||||||||
(in years) | |||||||||||||||||
Outstanding at December 31, 2013 | 874,100 | $ | 11.68 | ||||||||||||||
Granted | — | — | |||||||||||||||
Exercised | (7,500 | ) | 2.6 | ||||||||||||||
Canceled/Expired | — | — | |||||||||||||||
Forfeited | — | — | |||||||||||||||
Outstanding at December 31, 2014 | 866,600 | $ | 11.75 | ||||||||||||||
Options vested and exercisable at December 31, 2014 | 866,600 | $ | 11.75 | 2.19 | $ | — | |||||||||||
Schedule of Nonvested Share Activity | |||||||||||||||||
Shares | Weighted Average | Weighted Average | Weighted Average | Aggregate | |||||||||||||
Fair Value | Exercise Price | Remaining | Intrinsic Value | ||||||||||||||
per Share | per Share | Contractual Term | (in thousands) | ||||||||||||||
(in years) | |||||||||||||||||
Outstanding non-vested options at December 31, 2013 | 10,000 | $ | 2.74 | ||||||||||||||
Granted | — | — | |||||||||||||||
Vested | (10,000 | ) | 2.74 | ||||||||||||||
Forfeited | — | — | |||||||||||||||
Outstanding non-vested options at December 31, 2014 | — | $ | — | $ | — | 0 | $ | — | |||||||||
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table summarizes information related to restricted shares at December 31, 2014: | ||||||||||||||||
Shares | Weighted Average | Weighted Average | Aggregate | ||||||||||||||
Fair Value | Remaining | Intrinsic Value (in thousands) | |||||||||||||||
per Share | Contractual Term | ||||||||||||||||
(in years) | |||||||||||||||||
Outstanding non-vested restricted shares at December 31, 2013 | 3,773,081 | $ | 1.82 | ||||||||||||||
Granted | 601,473 | 5.85 | |||||||||||||||
Vested | (1,915,242 | ) | 1.83 | ||||||||||||||
Forfeited | (47,398 | ) | 3.76 | ||||||||||||||
Outstanding non-vested restricted shares at December 31, 2014 | 2,411,914 | $ | 2.79 | 8.11 | $ | 5,813 | |||||||||||
Schedule of Share-based Compensation, Stock Options, Activity | The table below provides a summary of PBUs as of the date indicated: | ||||||||||||||||
PBUs | Fair Value per Unit | ||||||||||||||||
Unvested PBUs at December 31, 2013 | 1,065,734 | $ | 1.56 | ||||||||||||||
Granted | 280,171 | 7.34 | |||||||||||||||
Vested | (355,247 | ) | 1.56 | ||||||||||||||
Forfeited | — | — | |||||||||||||||
Unvested PBUs at December 31, 2014 | 990,658 | $ | 3.19 | ||||||||||||||
Schedule of Unrecognized Compensation Cost, Nonvested Awards | As of December 31, 2014, the Company had approximately $2.8 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) | |||||||||||||||||
2015 | $ | 2,034 | |||||||||||||||
2016 | 663 | ||||||||||||||||
2017 | 59 | ||||||||||||||||
Total | $ | 2,756 | |||||||||||||||
Stock options | |||||||||||||||||
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 weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated: | ||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(in thousands, except per share data) | |||||||||||||||||
Weighted average grant date fair value per stock option granted | $ | — | $ | — | $ | — | |||||||||||
Intrinsic value of stock options exercised (1) | $ | 28 | $ | 19 | $ | 2 | |||||||||||
Grant date fair value of stock options vested | $ | 27 | $ | 88 | $ | 117 | |||||||||||
_______________________________ | |||||||||||||||||
-1 | Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised. | ||||||||||||||||
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, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(in thousands, except per share data) | |||||||||||||||||
Weighted average grant date fair value per restricted share | $ | 5.85 | $ | 1.3 | $ | 2.09 | |||||||||||
Total fair value of restricted shares vested | $ | 3,497 | $ | 2,725 | $ | 2,492 | |||||||||||
Interest_Expense_Tables
Interest Expense (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Interest expense: | ||||||||||||
Cash and accrued | $ | 28,851 | $ | 14,130 | $ | 1,992 | ||||||
Amortization of deferred financing costs(1)(2) | 3,067 | 2,322 | 224 | |||||||||
Capitalized interest | (4,347 | ) | (3,284 | ) | (1,946 | ) | ||||||
Total interest expense | $ | 27,571 | $ | 13,168 | $ | 270 | ||||||
_______________________________ | ||||||||||||
-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, 2014 and 2013 include $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, 2014 | ||||||||||||
Income Tax Contingency [Line Items] | ||||||||||||
Schedule of Income before Income Tax, Domestic and Foreign | The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated: | |||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
United States | $ | 50,953 | $ | 51,276 | $ | (152,322 | ) | |||||
Foreign | — | (1,934 | ) | (1,469 | ) | |||||||
Total income (loss) before income taxes | $ | 50,953 | $ | 49,342 | $ | (153,791 | ) | |||||
Schedule of Components of Income Tax Expense (Benefit) | The Company’s deferred income tax expense (benefit) consists of the following for the periods presented: | |||||||||||
For the Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Expected income tax provision (benefit) at statutory rate | $ | 17,833 | $ | 11,655 | $ | (53,827 | ) | |||||
State tax, tax effected | 803 | 96 | (2,562 | ) | ||||||||
Stock-based compensation expense | (1,291 | ) | 605 | 560 | ||||||||
Tax effect of Canadian tax rate differences | — | 193 | (125 | ) | ||||||||
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 | 38 | (49 | ) | 15 | ||||||||
Other changes in valuation allowance | (17,383 | ) | (38,777 | ) | 55,939 | |||||||
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, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax asset (liability): | ||||||||||||
Capital assets | $ | (134,223 | ) | $ | (77,456 | ) | ||||||
Stock-based compensation | 4,504 | 6,501 | ||||||||||
Net operating loss carry forwards | 164,056 | 122,675 | ||||||||||
Foreign tax credit carry forwards | 50,681 | 50,681 | ||||||||||
Valuation allowance | (85,018 | ) | (102,401 | ) | ||||||||
Net deferred tax asset | $ | — | $ | — | ||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Earnings Per Share [Abstract] | ||||||||||||
Schedule of Earnings Per Share, Basic and Diluted | ||||||||||||
For the Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands, except per share and share data) | ||||||||||||
Net income (loss) attributable to common stockholders | $ | 36,529 | $ | 39,964 | $ | (160,868 | ) | |||||
Weighted average shares of common stock outstanding - basic | 63,270,733 | 60,220,115 | 63,538,362 | |||||||||
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 | 66,492,589 | 63,618,401 | 63,538,362 | |||||||||
Net income (loss) per share of common stock attributable to common stockholders: | ||||||||||||
Basic | $ | 0.58 | $ | 0.66 | $ | (2.53 | ) | |||||
Diluted | $ | 0.55 | $ | 0.63 | $ | (2.53 | ) | |||||
Shares of common stock excluded from denominator as anti-dilutive: | ||||||||||||
Unvested restricted shares | 34,058 | 3,505 | 1,831,435 | |||||||||
Stock options | — | — | 936,967 | |||||||||
Total | 34,058 | 3,505 | 2,768,402 | |||||||||
Commitments_And_Contingencies_
Commitments And Contingencies (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Commitments and Contingencies Disclosure [Abstract] | ||||
Schedule of future minimum annual rental commitments | As of December 31, 2014, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: | |||
2015 | $ | 640 | ||
2016 | 498 | |||
2017 | 187 | |||
2018 | 161 | |||
$ | 1,486 | |||
Concentration_of_Risk_and_Sign1
Concentration of Risk and Significant Customers (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
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, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Appalachian Basin | 39 | % | 65 | % | 72 | % | ||||
Mid-Continent | 61 | % | 26 | % | — | % | ||||
Hilltop Area, East Texas(1) | — | % | 9 | % | 27 | % | ||||
Powder River Basin(2) | — | % | — | % | 1 | % | ||||
_______________________________ | ||||||||||
-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. | |||||||||
-2 | The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012. | |||||||||
The following table provides information regarding our significant customers and the percentages of oil, condensate, natural gas and NGLs revenues, excluding hedge impact, which they represented for the periods indicated: | ||||||||||
For the Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
SEI | 50 | % | 56 | % | 47 | % | ||||
Sunoco | 37 | % | 16 | % | — | % | ||||
Clearfield Appalachian | — | % | 8 | % | 14 | % | ||||
ETC | — | % | 8 | % | 24 | % |
Statement_Of_Cash_Flows_Supple1
Statement Of Cash Flows - Supplemental Information (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Cash paid for interest, net of capitalized amounts | $ | 24,632 | $ | 7,341 | $ | 39 | ||||||
Non-cash transactions: | ||||||||||||
Capital expenditures included in accounts payable and accrued drilling costs | $ | 12,777 | $ | 582 | $ | 4,666 | ||||||
Capital expenditures included in accounts receivable | 4,077 | (4,077 | ) | (929 | ) | |||||||
Asset retirement obligation included in oil and natural gas properties | 221 | (1,302 | ) | 1,164 | ||||||||
Asset retirement obligation sold/assigned to operator | (645 | ) | (4,354 | ) | (2,227 | ) | ||||||
Application of advances to operators | 58,326 | 19,755 | 7,441 | |||||||||
Other | (11 | ) | 47 | (36 | ) | |||||||
Quarterly_Consolidated_Financi1
Quarterly Consolidated Financial Data - Unaudited (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
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, 2014 and 2013: | |||||||||||||||
2014 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | 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 | ||||||||||||
2013 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
(in thousands, except share and per share data) | ||||||||||||||||
Revenues | $ | 11,264 | $ | 30,926 | $ | 18,840 | $ | 26,725 | ||||||||
(Loss) income from operations | (1,849 | ) | 13,809 | 1,626 | 5,178 | |||||||||||
(Loss) income before provision for income taxes(1) | (2,456 | ) | 53,970 | (1,808 | ) | (16,406 | ) | |||||||||
Net (loss) income | (2,456 | ) | 53,970 | (1,808 | ) | (364 | ) | |||||||||
Dividend on preferred stock | 2,130 | 2,134 | 2,134 | 2,980 | ||||||||||||
Net (loss) income attributable to common stockholders | (4,586 | ) | 51,836 | (3,942 | ) | (3,344 | ) | |||||||||
Net (loss) income per share of common stock attributable to common stockholders: | ||||||||||||||||
Basic | $ | (0.07 | ) | $ | 0.83 | $ | (0.07 | ) | $ | (0.06 | ) | |||||
Diluted | $ | (0.07 | ) | $ | 0.81 | $ | (0.07 | ) | $ | (0.06 | ) | |||||
Weighted average shares of common stock outstanding: | ||||||||||||||||
Basic | 63,864,527 | 62,398,472 | 57,359,357 | 57,433,550 | ||||||||||||
Diluted | 63,864,527 | 63,813,423 | 57,359,357 | 57,433,550 | ||||||||||||
_________________________________ | ||||||||||||||||
-1 | Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million. |
Supplemental_Oil_and_Gas_Discl1
Supplemental Oil and Gas Disclosures - Unaudited (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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 for the periods indicated: | ||||||||||||
As of December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Proved properties: | |||||||||||||
United States | $ | 1,124,367 | $ | 935,773 | $ | 671,193 | |||||||
Total proved properties | 1,124,367 | 935,773 | 671,193 | ||||||||||
Unproved properties: | |||||||||||||
United States | 128,274 | 96,220 | 67,892 | ||||||||||
Total unproved properties | 128,274 | 96,220 | 67,892 | ||||||||||
Total oil and natural gas properties | 1,252,641 | 1,031,993 | 739,085 | ||||||||||
Less: | |||||||||||||
Impairment of proved oil and natural gas properties | |||||||||||||
United States | (337,939 | ) | (337,939 | ) | (337,939 | ) | |||||||
Accumulated depreciation, depletion and amortization | (223,555 | ) | (177,790 | ) | (145,631 | ) | |||||||
Net capitalized costs | $ | 691,147 | $ | 516,264 | $ | 255,515 | |||||||
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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Property acquisition | |||||||||||||
Proved(1) | $ | — | $ | 189,594 | $ | — | |||||||
Unproved(2) | 41,475 | 71,472 | 25,676 | ||||||||||
Exploration | 127,384 | 36,893 | 10,041 | ||||||||||
Development | 57,913 | 53,058 | 111,878 | ||||||||||
Total costs incurred | $ | 226,772 | $ | 351,017 | $ | 147,595 | |||||||
_________________________________ | |||||||||||||
-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 acquisitio | ||||||||||||
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 for the periods indicated: | ||||||||||||
For the Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands, except per Mcfe data) | |||||||||||||
Oil, condensate, natural gas and NGLs sales, including commodity derivatives | $ | 171,418 | $ | 87,755 | $ | 49,940 | |||||||
Production expenses | (29,735 | ) | (18,113 | ) | (13,408 | ) | |||||||
Impairment of oil and natural gas properties | — | — | (150,787 | ) | |||||||||
Depreciation, depletion and amortization | (45,765 | ) | (32,158 | ) | (25,195 | ) | |||||||
Results of producing activities | $ | 95,918 | $ | 37,484 | $ | (139,450 | ) | ||||||
Depreciation, depletion and amortization per MBoe | $ | 12.34 | $ | 9.94 | $ | 11.41 | |||||||
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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Natural gas, per MMBtu | |||||||||||||
Henry Hub | $ | 4.35 | $ | 3.67 | $ | 2.76 | |||||||
Oil, per barrel: | |||||||||||||
WTI spot | $ | 94.99 | $ | 96.78 | $ | 94.71 | |||||||
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, 2014, 2013 and 2012: | ||||||||||||
Change in Proved Reserves | Natural Gas | NGLs | Condensate and Oil | MBoe (3) Equivalents (4) | |||||||||
(MMcf) (1) | (MBbl) (2) | (MBbl) (2) | |||||||||||
Proved reserves as of December 31, 2011 | 91,652 | 2,757 | 1,921 | 19,953 | |||||||||
2012 Activity: | |||||||||||||
Extensions and discoveries(5) | 57,835 | 2,783 | 2,439 | 14,861 | |||||||||
Revisions of previous estimates | (6,518 | ) | (348 | ) | (796 | ) | (2,230 | ) | |||||
Production | (10,564 | ) | (270 | ) | (177 | ) | (2,208 | ) | |||||
Purchases in place | — | — | 7 | 7 | |||||||||
Sales in place | (1,395 | ) | — | — | (231 | ) | |||||||
Proved reserves as of December 31, 2012 | 131,010 | 4,922 | 3,394 | 30,152 | |||||||||
2013 Activity: | |||||||||||||
Extensions and discoveries(6) | 52,750 | 2,306 | 4,385 | 15,483 | |||||||||
Revisions of previous estimates | 8,114 | 714 | (337 | ) | 1,729 | ||||||||
Production | (13,366 | ) | (494 | ) | (515 | ) | (3,237 | ) | |||||
Purchases in place | 26,961 | 2,350 | 7,796 | 14,639 | |||||||||
Sales in place | (24,759 | ) | — | (5 | ) | (4,132 | ) | ||||||
Proved reserves as of December 31, 2013 | 180,710 | 9,798 | 14,718 | 54,634 | |||||||||
2014 Activity: | |||||||||||||
Extensions and discoveries(7) | 121,672 | 9,394 | 13,137 | 42,810 | |||||||||
Revisions of previous estimates | (2,465 | ) | 7,205 | 1,780 | 8,574 | ||||||||
Production | (11,598 | ) | (800 | ) | (975 | ) | (3,708 | ) | |||||
Sales in place | (1,314 | ) | (4 | ) | (24 | ) | (247 | ) | |||||
Proved reserves as of December 31, 2014 | 287,005 | 25,593 | 28,636 | 102,063 | |||||||||
_________________________________ | |||||||||||||
(1)Million cubic feet or million cubic feet equivalent, as applicable | |||||||||||||
-2 | Thousand barrels | ||||||||||||
-3 | Thousand barrels of oil, condensate or NGLs equivalent. | ||||||||||||
-4 | 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. | ||||||||||||
-5 | The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery. | ||||||||||||
-6 | 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. | ||||||||||||
-7 | 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. | ||||||||||||
Proved Developed and Undeveloped Reserves | Natural Gas | NGLs | Condensate and Oil | MBoe (3) Equivalents (4) | |||||||||
(MMcf) (1) | (MBbl) (2) | (MBbl) (2) | |||||||||||
31-Dec-12 | |||||||||||||
Proved developed reserves | 95,602 | 3,215.80 | 1,959 | 21,109 | |||||||||
Proved undeveloped reserves | 35,408 | 1,706 | 1,435 | 9,042 | |||||||||
Total | 131,010 | 4,922 | 3,394 | 30,151 | |||||||||
31-Dec-13 | |||||||||||||
Proved developed reserves | 114,195 | 6,025 | 5,834 | 30,892 | |||||||||
Proved undeveloped reserves | 66,515 | 3,773 | 8,884 | 23,742 | |||||||||
Total | 180,710 | 9,798 | 14,718 | 54,634 | |||||||||
31-Dec-14 | |||||||||||||
Proved developed reserves | 114,564 | 10,726 | 6,968 | 36,789 | |||||||||
Proved undeveloped reserves | 172,441 | 14,867 | 21,668 | 65,274 | |||||||||
Total | 287,005 | 25,593 | 28,636 | 102,063 | |||||||||
_________________________________ | |||||||||||||
(1)Million cubic feet or million cubic feet equivalent, as applicable | |||||||||||||
-2 | Thousand barrels | ||||||||||||
-3 | Thousand barrels of oil, condensate or NGLs equivalent. | ||||||||||||
-4 | 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 is presented below: | ||||||||||||
United States | |||||||||||||
(in thousands) | |||||||||||||
December 31, 2012: | |||||||||||||
Future cash inflows | $ | 672,142 | |||||||||||
Future production costs | (167,864 | ) | |||||||||||
Future development costs | (83,697 | ) | |||||||||||
Future income taxes(1) | — | ||||||||||||
Future net cash flows | 420,581 | ||||||||||||
10% annual discount for estimated timing of cash flows | (213,772 | ) | |||||||||||
Standardized measure of discounted future cash flows | $ | 206,809 | |||||||||||
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 | |||||||||||
_________________________________ | |||||||||||||
-1 | No future taxes payable has been included in the determination of discounted future net cash flows for 2012 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: | ||||||||||||
United States | |||||||||||||
(in thousands) | |||||||||||||
December 31, 2011 | $ | 212,783 | |||||||||||
Extensions and discoveries, less related costs | 112,390 | ||||||||||||
Sale of natural gas and oil, net of production costs | (29,110 | ) | |||||||||||
Purchases of reserves in place | 64 | ||||||||||||
Sales of reserves in place | (216 | ) | |||||||||||
Revisions of previous quantity estimates | (30,959 | ) | |||||||||||
Net change in income tax | 4,334 | ||||||||||||
Net change in prices and production costs | (98,589 | ) | |||||||||||
Accretion of discount | 1,152 | ||||||||||||
Development costs incurred | 19,702 | ||||||||||||
Net change in estimated future development costs | 2,518 | ||||||||||||
Change in production rates (timing) and other | 12,740 | ||||||||||||
31-Dec-12 | $ | 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 | ||||||||||||
31-Dec-13 | $ | 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 | (1,277 | ) | |||||||||||
Change in production rates (timing) and other | (43,081 | ) | |||||||||||
31-Dec-14 | $ | 816,739 | |||||||||||
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, | |||||||||||||
2014 | 2013 | ||||||||||||
Natural gas (per MMBtu): | |||||||||||||
Henry Hub | $ | 4.35 | $ | 3.67 | |||||||||
Oil (per Bbl): | |||||||||||||
WTI spot | $ | 94.99 | 96.78 | ||||||||||
Recovered_Sheet2
Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Accounting Policies [Line Items] | ||||
Cash and cash equivalents | $11,008 | $32,393 | $8,901 | $10,647 |
Capitalized interest | ($4,347) | ($3,284) | ($1,946) | |
Canada | ||||
Accounting Policies [Line Items] | ||||
Number of gas wells | 2 | |||
Minimum | Furniture and equipment | ||||
Accounting Policies [Line Items] | ||||
Estimated useful lives | 3 years | |||
Maximum | Furniture and equipment | ||||
Accounting Policies [Line Items] | ||||
Estimated useful lives | 7 years |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Schedule of Allowance for Doubtful Accounts) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||
Allowance for doubtful accounts, beginning of year | $507 | $546 | $551 |
Expense | 0 | 0 | 0 |
Reductions/write-offs | -507 | -39 | -5 |
Allowance for doubtful accounts, end of year | $0 | $507 | $546 |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies (Schedule of Deferred Financing Costs) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Accounting Policies [Abstract] | ||
Deferred charges | $3,664 | $3,269 |
Accumulated amortization | -1,078 | -319 |
Deferred charges, net | $2,586 | $2,950 |
Property_Plant_And_Equipment_S
Property, Plant And Equipment (Schedule of Property Plant and Equipment) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Property, Plant and Equipment [Line Items] | |||
Unproved properties | $128,274 | $96,220 | $67,892 |
Proved properties | 1,124,367 | 935,773 | 671,193 |
Total oil and natural gas properties | 1,252,641 | 1,031,993 | |
Total property and equipment | 1,255,651 | 1,034,684 | |
Impairment of proved natural gas and oil properties | -337,939 | -337,939 | |
Accumulated depreciation, depletion and amortization | -225,412 | -179,232 | |
Total accumulated depreciation, depletion and amortization | -563,351 | -517,171 | |
Total property, plant and equipment, net | 692,300 | 517,513 | |
Total oil and natural gas properties | |||
Property, Plant and Equipment [Line Items] | |||
Unproved properties | 128,274 | 96,220 | |
Proved properties | 1,124,367 | 935,773 | |
Total oil and natural gas properties | 1,252,641 | 1,031,993 | |
Furniture and equipment | |||
Property, Plant and Equipment [Line Items] | |||
Total property and equipment | $3,010 | $2,691 |
Property_Plant_And_Equipment_N
Property, Plant And Equipment (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | ||||||||||
Jun. 30, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 01, 2010 | Dec. 31, 2011 | Jul. 01, 2013 | Jan. 01, 2013 | Jun. 07, 2013 | Nov. 15, 2013 | Oct. 02, 2013 | Aug. 06, 2013 | Jul. 02, 2013 | Mar. 28, 2013 | Sep. 04, 2013 | |
well | acre | acre | acre | acre | |||||||||||
acre | well | ||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Asset retirement obligation | $2,400,000 | $3,400,000 | $4,800,000 | ||||||||||||
Gain on acquisition of assets at fair value, net of income taxes | 43,700,000 | 0 | 27,670,000 | 0 | |||||||||||
Proceeds from sale of natural gas and oil properties | 5,530,000 | 112,201,000 | 0 | ||||||||||||
Term of development program | 3 years | ||||||||||||||
Atinum Joint Venture | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 34,200 | ||||||||||||||
Productive conventional wells (wells) | 16 | ||||||||||||||
Working interest In wells (percentage) | 50.00% | ||||||||||||||
Gross acres | 37,600 | ||||||||||||||
Initial interest in assets (percentage) | 21.43% | ||||||||||||||
Non productive number of wells | 1 | ||||||||||||||
Proceeds from sale of Marcellus Shale assets | 30,000,000 | ||||||||||||||
Cash received from Atinum for drilling carrying costs | 40,000,000 | 40,000,000 | |||||||||||||
Atinum ownership interest in Atinum Joint Venture Assets (percentage) | 50.00% | ||||||||||||||
Percentage of share of drilling completion and infrastructure costs carried (percentage) | 75.00% | ||||||||||||||
Joint interest share of drilling completion and infrastructure costs (percentage) | 50.00% | 50.00% | |||||||||||||
Gross operated wells drilled, completed and on production | 67 | ||||||||||||||
Operated wells drilled, completed and on production | 32 | ||||||||||||||
Percentage of reimbursements for lease bonuses and third party lease costs up to 20 million (percentage) | 10.00% | ||||||||||||||
Percentage of lease operating expenses covered (percentage) | 5.00% | ||||||||||||||
East Texas | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Reclassification of unproved properties to proved properties | 3,300,000 | 20,500,000 | |||||||||||||
Gastar Exploration USA | Hunton Joint Venture | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 12,800 | ||||||||||||||
Transaction and integration costs | 133,000 | ||||||||||||||
Acquisition of oil and natural gas properties | 11,800,000 | ||||||||||||||
Gastar Exploration USA | East Texas | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 16,300 | ||||||||||||||
Gross acres | 31,800 | ||||||||||||||
Proceeds from sale of natural gas and oil properties | 42,900,000 | ||||||||||||||
Gastar Exploration USA | Utica Shale | Atinum Joint Venture | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Productive conventional wells (wells) | 1 | ||||||||||||||
Operated wells drilled, completed and on production | 0.5 | ||||||||||||||
Gastar Exploration USA | Hunton Divestiture | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 76,000 | ||||||||||||||
Net cash purchase price of divestiture | 57,000,000 | ||||||||||||||
Gastar Exploration USA | Chesapeake Assets | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 157,000 | ||||||||||||||
Productive conventional wells (wells) | 206 | ||||||||||||||
Cash consideration | 69,400,000 | ||||||||||||||
Fair market valuation amount | 113,083,000 | ||||||||||||||
Gain on acquisition of assets at fair value, net of income taxes | 27,670,000 | ||||||||||||||
Income tax expense recognized | 16,042,000 | ||||||||||||||
Gastar Exploration USA | Chesapeake Assets | General and Administrative Expense | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Transaction and integration costs | 2,100,000 | ||||||||||||||
Gastar Exploration USA | Oklahoma Oil and Gas Leasehold Interests | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 1,850 | ||||||||||||||
Gastar Exploration USA | WEHLU Purchase Agreement | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Net acres | 24,000 | ||||||||||||||
Cash consideration | 177,778,000 | ||||||||||||||
Transaction and integration costs | 286,000 | ||||||||||||||
Fair market valuation amount | 177,778,000 | ||||||||||||||
Working interest In wells (percentage) | 98.30% | ||||||||||||||
Net revenue interest | 80.50% | ||||||||||||||
Preliminary assessment of fair value of WEHLU Assets | $176,800,000 | ||||||||||||||
Minimum | Atinum Joint Venture | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Amended required exploratory wells drilled net productive to be drilled in current fiscal year (wells) | 51 | ||||||||||||||
Maximum | Gastar Exploration USA | Atinum Joint Venture | |||||||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||||||
Gross wells originally agreed upon | 60 |
Property_Plant_And_Equipment_S1
Property, Plant And Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Unproved properties, excluded from amortization: | ||
Drilling in progress costs | $29,193 | $4,774 |
Acreage acquisition costs | 91,362 | 86,097 |
Capitalized interest | 7,719 | 5,349 |
Total unproved properties excluded from amortization | $128,274 | $96,220 |
Property_Plant_And_Equipment_S2
Property, Plant And Equipment (Schedule of Relevant Assumptions Used In Ceiling Test Computations) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | ||||||||||||||||||||||||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Jun. 30, 2014 | Sep. 30, 2013 | Jun. 30, 2013 | Sep. 30, 2012 | Jun. 30, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2012 | ||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Impairment of natural gas and oil properties | $0 | $0 | $0 | $0 | $78,054 | $72,733 | $0 | $0 | $150,787 | ||||||||||||||||||
Henry Hub natural gas price (per MMBtu) | |||||||||||||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Key natural gas and oil prices | 4.24 | [1] | 4.1 | [1] | 3.61 | [1] | 3.44 | [1] | 2.83 | [1] | 3.15 | [1] | 4.35 | [1] | 3.99 | [1] | 3.67 | [1] | 2.95 | [1] | 2.76 | [1] | 3.73 | [1] | |||
West Texas Intermediate oil price (per Bbl) | |||||||||||||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Key natural gas and oil prices | 99.08 | [1] | 100.11 | [1] | 91.69 | [1] | 88.13 | [1] | 91.48 | [1] | 92.17 | [1] | 94.99 | [1] | 98.3 | [1] | 96.78 | [1] | 89.17 | [1] | 91.21 | [1] | 94.65 | [1] | |||
[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_Equipment_S3
Property, Plant And Equipment (Schedule of Assets Acquired) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | |||
In Thousands, unless otherwise specified | Jun. 30, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 07, 2013 | Nov. 15, 2013 |
Business Acquisition [Line Items] | ||||||
Gain on acquisition of assets at fair value, net of income taxes | $43,700 | $0 | $27,670 | $0 | ||
Chesapeake Assets | Gastar Exploration USA | ||||||
Business Acquisition [Line Items] | ||||||
Cash consideration | 69,371 | |||||
Deferred tax liability | 16,042 | |||||
Total purchase price plus liabilities assumed | 85,413 | |||||
Cash consideration | 69,400 | |||||
Unproved properties | 86,327 | |||||
Proved properties | 26,756 | |||||
Total assets acquired | 113,083 | |||||
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 | |||||
Unproved properties | 13,026 | |||||
Proved properties | 164,752 | |||||
Total assets acquired | $177,778 |
Property_Plant_And_Equipment_S4
Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) (WEHLU Purchase Agreement, Gastar Exploration USA, USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
WEHLU Purchase Agreement | Gastar Exploration USA | ||
Business Acquisition [Line Items] | ||
Revenues | $132,721 | $97,760 |
Net Loss | -4,836 | -175,809 |
Loss per share, Basic | ($0.08) | ($2.77) |
Loss per share, Diluted | ($0.08) | ($2.77) |
Revenues | 11,292 | |
Excess of revenues over direct operating expenses | $7,591 |
LongTerm_Debt_Narrative_Detail
Long-Term Debt (Narrative) (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | ||||||||||||
15-May-13 | Dec. 31, 2014 | Jun. 07, 2013 | Dec. 31, 2013 | Mar. 09, 2015 | Mar. 08, 2015 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Sep. 29, 2016 | Mar. 31, 2016 | Mar. 30, 2016 | Jun. 30, 2016 | Jun. 29, 2016 | |
Line of Credit Facility [Line Items] | |||||||||||||||
Long-term debt | $360,303,000 | $312,994,000 | |||||||||||||
Second Amended and Restated Revolving Credit Facility | Subsequent Event | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Revolving credit facility borrowing base | 200,000,000 | 145,000,000 | |||||||||||||
Second Amended and Restated Revolving Credit Facility | Subsequent Event | Scenario, Forecast | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Leverage ratio | 4 | 4.25 | 4.75 | 5 | 5.25 | ||||||||||
Interest coverage ratio | 2.5 | 2 | |||||||||||||
Senior Notes | Senior Secured Notes Due 2018 | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Aggregate principal amount | 325,000,000 | ||||||||||||||
Interest rate | 8.63% | 8.63% | |||||||||||||
Redemption percentage of aggregate principal amount | 101.00% | ||||||||||||||
Long-term debt | 315,300,000 | ||||||||||||||
Unamortized discounts | 9,700,000 | ||||||||||||||
Senior Notes | Senior Secured Notes Due 2018 | Subsequent Event | Scenario, Forecast | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Leverage ratio | 2 | 2.25 | |||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Annual commitment fee (percentage) | 0.50% | ||||||||||||||
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 | 2.5 | ||||||||||||||
Revolving credit facility borrowing base | 145,000,000 | 50,000,000 | |||||||||||||
Revolving Credit Facility, remaining borrowing capacity | 100,000,000 | ||||||||||||||
Revolving Credit Facility amount outstanding | $45,000,000 | ||||||||||||||
Percentage increase in adjusted consolidated net tangible assets | 17.50% | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Minimum | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Line of credit facility covenant compliance Current Ratio | 1 | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Maximum | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Line of credit facility covenant compliance indebtedness to EBITDA Ratio | 4 | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Federal Funds Rate | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Federal funds rate | federal funds rate plus | ||||||||||||||
Applicable interest rate margin | 0.50% | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | LIBOR | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Applicable interest rate margin | 1.00% | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Prime Rate | Minimum | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Applicable interest rate margin | 1.00% | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Prime Rate | Maximum | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Applicable interest rate margin | 2.00% | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Eurodollar | Minimum | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Applicable interest rate margin | 2.00% | ||||||||||||||
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Eurodollar | Maximum | |||||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||||
Applicable interest rate margin | 3.00% |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligation, beginning of year | $6,063 | $6,963 | $8,275 |
Liabilities incurred during period | 305 | 3,416 | 271 |
Liabilities settled during period | -704 | -126 | -297 |
Accretion of asset retirement obligation | 506 | 468 | 388 |
Revision in previous estimates and other | 32 | 60 | 553 |
Deletions related to property disposals | -645 | -4,718 | -2,227 |
Asset retirement obligation, end of year | 5,557 | 6,063 | 6,963 |
Asset retirement obligation | $82 | $633 |
Fair_Value_Measurements_Narrat
Fair Value Measurements (Narrative) (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Estimated fair value of long term debt | $330.60 | $324.60 |
East Texas | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Reclassification of unproved properties to proved properties | $3.30 | $20.50 |
Fair_Value_Measurements_Fair_V
Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) (Fair Value, Measurements, Recurring, USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Assets [Abstract] | ||
Assets, Commodity derivative contracts | $27,502 | $7,545 |
Derivative Liabilities [Abstract] | ||
Liabilities, Commodity derivative contracts | 0 | -3,781 |
Total | 38,510 | 36,157 |
Level 1 | ||
Derivative Assets [Abstract] | ||
Assets, Commodity derivative contracts | 0 | 0 |
Derivative Liabilities [Abstract] | ||
Liabilities, Commodity derivative contracts | 0 | 0 |
Total | 11,008 | 32,393 |
Level 2 | ||
Derivative Assets [Abstract] | ||
Assets, Commodity derivative contracts | 0 | 0 |
Derivative Liabilities [Abstract] | ||
Liabilities, Commodity derivative contracts | 0 | 0 |
Total | 0 | 0 |
Level 3 | ||
Derivative Assets [Abstract] | ||
Assets, Commodity derivative contracts | 27,502 | 7,545 |
Derivative Liabilities [Abstract] | ||
Liabilities, Commodity derivative contracts | 0 | -3,781 |
Total | 27,502 | 3,764 |
Cash and cash equivalents | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 11,008 | 32,393 |
Cash and cash equivalents | Level 1 | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 11,008 | 32,393 |
Cash and cash equivalents | Level 2 | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 0 | 0 |
Cash and cash equivalents | Level 3 | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 0 | 0 |
Restricted cash | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 0 | |
Restricted cash | Level 1 | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 0 | |
Restricted cash | Level 2 | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | 0 | |
Restricted cash | Level 3 | ||
Derivative Assets [Abstract] | ||
Cash and cash equivalents | $0 |
Fair_Value_Measurements_Net_Ch
Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) (Fair Value, Inputs, Level 3, Commodity, Fair Value, Measurements, Recurring, USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Measurements, Recurring | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Balance at beginning of period | $3,764 | $6,465 | ||
Total gains (losses) | ||||
included in earnings | 19,569 | -4,752 | ||
Purchases | 369 | 9,772 | ||
Issuances | 0 | -2,308 | ||
Settlements | 3,800 | [1] | -5,413 | [1] |
Balance at end of period | 27,502 | 3,764 | ||
The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2014 and 2013 | $23,902 | ($9,967) | ||
[1] | Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. |
Derivative_Instruments_And_Hed2
Derivative Instruments And Hedging Activity (Narrative) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Change in fair value of commodity derivative instruments | $23.90 | ($10) | ($5.60) |
Derivative_Instruments_And_Hed3
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, 2014 | ||
MMBTU | ||
Natural Gas | 2015 | Call spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 10,000 | [1] |
Total of Notional Volume (MMBtu's or Bbls) | 900,000 | [1] |
Base Fixed Price (Price per MMbtu or Bbl) | 0 | [1] |
Ceiling (Short) (Price per MMBtu) | 5 | [1] |
Natural Gas | 2016 | Protective spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,000 | |
Total of Notional Volume (MMBtu's or Bbls) | 732,000 | |
Base Fixed Price (Price per MMbtu or Bbl) | 4.11 | |
Short Put (Price per MMBtu) | 3.25 | |
Crude Oil | 2015 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 400 | [2],[3] |
Total of Notional Volume (MMBtu's or Bbls) | 73,600 | [3] |
Floor (Long) (Price per MMBtu) | 85 | [3] |
Short Put (Price per MMBtu) | 70 | [3] |
Ceiling (Short) (Price per MMBtu) | 96.5 | [3] |
Crude Oil | 2016 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 275 | [2],[4] |
Total of Notional Volume (MMBtu's or Bbls) | 100,600 | [4] |
Floor (Long) (Price per MMBtu) | 85 | [4] |
Short Put (Price per MMBtu) | 65 | [4] |
Ceiling (Short) (Price per MMBtu) | 95.1 | |
Crude Oil | 2017 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 280 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 102,200 | |
Floor (Long) (Price per MMBtu) | 80 | |
Short Put (Price per MMBtu) | 65 | |
Ceiling (Short) (Price per MMBtu) | 97.25 | |
Crude Oil | 2017 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 500 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 182,500 | |
Floor (Long) (Price per MMBtu) | 82 | |
Short Put (Price per MMBtu) | 62 | |
Crude Oil | 2018 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 425 | [2],[4] |
Total of Notional Volume (MMBtu's or Bbls) | 103,275 | [4] |
Floor (Long) (Price per MMBtu) | 80 | [4] |
Short Put (Price per MMBtu) | 60 | [4] |
Natural Gas Liquids | 2015 | Fixed price swap | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 250 | [5] |
Total of Notional Volume (MMBtu's or Bbls) | 68,750 | [5] |
Base Fixed Price (Price per MMbtu or Bbl) | 45.61 | [5] |
Protective Spread 1 | Natural Gas | 2015 | Protective spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 10,000 | [1] |
Total of Notional Volume (MMBtu's or Bbls) | 900,000 | [1] |
Base Fixed Price (Price per MMbtu or Bbl) | 4.46 | [1] |
Short Put (Price per MMBtu) | 3.7 | [1] |
Protective Spread 2 | Natural Gas | 2015 | Protective spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,600 | |
Total of Notional Volume (MMBtu's or Bbls) | 949,000 | |
Base Fixed Price (Price per MMbtu or Bbl) | 4 | |
Short Put (Price per MMBtu) | 3.25 | |
Costless Collar 1 | Crude Oil | 2015 | Costless collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 400 | [2],[6] |
Total of Notional Volume (MMBtu's or Bbls) | 72,400 | [6] |
Floor (Long) (Price per MMBtu) | 85 | [6] |
Ceiling (Short) (Price per MMBtu) | 96.5 | [6] |
Costless Collar 2 | Crude Oil | 2015 | Costless collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 366 | [2],[6] |
Total of Notional Volume (MMBtu's or Bbls) | 66,300 | [6] |
Floor (Long) (Price per MMBtu) | 85 | [6] |
Ceiling (Short) (Price per MMBtu) | 97.8 | [6] |
Costless Collar 3 | Crude Oil | 2015 | Costless collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 150 | [2],[6] |
Total of Notional Volume (MMBtu's or Bbls) | 27,150 | [6] |
Floor (Long) (Price per MMBtu) | 85 | [3] |
Ceiling (Short) (Price per MMBtu) | 96.25 | [6] |
Fixed Price Swap 1 | Natural Gas | 2015 | Fixed price swap | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 400 | |
Total of Notional Volume (MMBtu's or Bbls) | 146,000 | |
Base Fixed Price (Price per MMbtu or Bbl) | 4 | |
Fixed Price Swap 2 | Natural Gas | 2015 | Fixed price swap | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,500 | |
Total of Notional Volume (MMBtu's or Bbls) | 912,500 | |
Base Fixed Price (Price per MMbtu or Bbl) | 4.06 | |
Producer Three Way Collar 1 | Natural Gas | 2015 | Producer three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 3,750 | [1] |
Total of Notional Volume (MMBtu's or Bbls) | 337,500 | [1] |
Floor (Long) (Price per MMBtu) | 4.6 | [1] |
Short Put (Price per MMBtu) | 3.5 | [1] |
Ceiling (Short) (Price per MMBtu) | 5.34 | [1] |
Producer Three Way Collar Two | Natural Gas | 2015 | Producer three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,500 | [1] |
Total of Notional Volume (MMBtu's or Bbls) | 337,500 | [1] |
Floor (Long) (Price per MMBtu) | 4.4 | [1] |
Short Put (Price per MMBtu) | 3.65 | [1] |
Ceiling (Short) (Price per MMBtu) | 5 | [1] |
Producer Three Way Collar Three | Natural Gas | 2015 | Producer three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,000 | |
Total of Notional Volume (MMBtu's or Bbls) | 760,000 | |
Floor (Long) (Price per MMBtu) | 4 | |
Short Put (Price per MMBtu) | 3.25 | |
Ceiling (Short) (Price per MMBtu) | 4.58 | |
Basis Swap 1 | Natural Gas | 2015 | Basis Swap [Member] | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,500 | [7] |
Total of Notional Volume (MMBtu's or Bbls) | 912,500 | [7] |
Base Fixed Price (Price per MMbtu or Bbl) | -1.12 | [7] |
Basis Swap 2 | Natural Gas | 2015 | Basis Swap [Member] | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,500 | [7] |
Total of Notional Volume (MMBtu's or Bbls) | 912,500 | [7] |
Base Fixed Price (Price per MMbtu or Bbl) | -1.11 | [7] |
Basis Points 3 | Natural Gas | 2015 | Basis Swap [Member] | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,500 | [7] |
Total of Notional Volume (MMBtu's or Bbls) | 912,500 | [7] |
Base Fixed Price (Price per MMbtu or Bbl) | -1.14 | [7] |
Protective Spread 3 | Natural Gas | 2015 | Protective spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 5,000 | [5] |
Total of Notional Volume (MMBtu's or Bbls) | 1,375,000 | [5] |
Base Fixed Price (Price per MMbtu or Bbl) | 4 | [5] |
Short Put (Price per MMBtu) | 3.25 | [5] |
Producer Three Way Collar 4 | Natural Gas | 2015 | Producer three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 2,500 | [5] |
Total of Notional Volume (MMBtu's or Bbls) | 687,500 | [5] |
Floor (Long) (Price per MMBtu) | 3.7 | [5] |
Short Put (Price per MMBtu) | 3 | [5] |
Ceiling (Short) (Price per MMBtu) | 4.09 | [5] |
Producer Three Way Collar 5 | Natural Gas | 2015 | Producer three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 5,000 | [5] |
Total of Notional Volume (MMBtu's or Bbls) | 1,375,000 | [5] |
Floor (Long) (Price per MMBtu) | 3.77 | [5] |
Short Put (Price per MMBtu) | 3 | [5] |
Ceiling (Short) (Price per MMBtu) | 4.11 | [5] |
Costless Three Way Collar 2 | Crude Oil | 2015 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 325 | [2],[3] |
Total of Notional Volume (MMBtu's or Bbls) | 59,800 | [3] |
Floor (Long) (Price per MMBtu) | 85 | [3] |
Short Put (Price per MMBtu) | 65 | [3] |
Ceiling (Short) (Price per MMBtu) | 97.8 | [3] |
Costless Three Way Collar 2 | Crude Oil | 2016 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 330 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 120,780 | |
Floor (Long) (Price per MMBtu) | 80 | |
Short Put (Price per MMBtu) | 65 | |
Ceiling (Short) (Price per MMBtu) | 97.35 | |
Costless Three Way Collar 2 | Crude Oil | 2017 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 242 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 88,150 | |
Floor (Long) (Price per MMBtu) | 80 | |
Short Put (Price per MMBtu) | 60 | |
Ceiling (Short) (Price per MMBtu) | 98.7 | |
Cost Less Three Way Collar 3 | Crude Oil | 2015 | Costless three-way collar | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 50 | [2],[3] |
Total of Notional Volume (MMBtu's or Bbls) | 9,200 | [3] |
Floor (Long) (Price per MMBtu) | 85 | [3] |
Short Put (Price per MMBtu) | 65 | [3] |
Ceiling (Short) (Price per MMBtu) | 96.25 | [3] |
Put Spread 1 | Crude Oil | 2015 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 700 | [2],[6] |
Total of Notional Volume (MMBtu's or Bbls) | 126,700 | [6] |
Floor (Long) (Price per MMBtu) | 90 | [6] |
Short Put (Price per MMBtu) | 70 | [6] |
Put Spread 1 | Crude Oil | 2016 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 550 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 201,300 | |
Floor (Long) (Price per MMBtu) | 85 | |
Short Put (Price per MMBtu) | 65 | |
Put Spread 2 | Crude Oil | 2015 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 250 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 91,250 | |
Floor (Long) (Price per MMBtu) | 89 | [4] |
Short Put (Price per MMBtu) | 69 | [4] |
Put Spread 2 | Crude Oil | 2016 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 300 | [2] |
Total of Notional Volume (MMBtu's or Bbls) | 109,800 | |
Floor (Long) (Price per MMBtu) | 85.5 | |
Short Put (Price per MMBtu) | 65.5 | |
Put Spread 3 | Crude Oil | 2015 | Put spread | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtus or Bbls) | 600 | [2],[3] |
Total of Notional Volume (MMBtu's or Bbls) | 110,400 | [3] |
Floor (Long) (Price per MMBtu) | 87 | [3] |
Short Put (Price per MMBtu) | 67 | [3] |
[1] | For the period January to March 2015. | |
[2] | Crude volumes hedged include oil, condensate and certain components of our NGLs production. | |
[3] | For the period July to December 2015. | |
[4] | For the period January to August 2018. | |
[5] | For the period April to December 2015. | |
[6] | For the period January to June 2015. | |
[7] | Represents basis swaps at the sales point of Dominion South. |
Derivative_Instruments_And_Hed4
Derivative Instruments And Hedging Activity (Schedule of Unamortized Put Premium) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Commodity derivative premium payable | $2,481 | $145 |
Commodity derivative premium payable | 4,702 | 7,000 |
Total unamortized put premium liabilities | $7,183 | $7,145 |
Derivative_Instruments_And_Hed5
Derivative Instruments And Hedging Activity (Schedule of Deferred Put Premium Liability) (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Put Premium Liabilities [Roll Forward] | |
Put premium liabilities, beginning balance | $7,145 |
Amortization of put premium liabilities | -145 |
Additional put premium liabilities | 183 |
Put premium liabilities, ending balance | $7,183 |
Derivative_Instruments_And_Hed6
Derivative Instruments And Hedging Activity (Schedule of Future Amortization of Put Premium) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
January to December 2015 | $2,481 | |
January to December 2016 | 2,408 | |
January to December 2017 | 1,460 | |
January to August 2018 | 834 | |
Total unamortized put premium liabilities | $7,183 | $7,145 |
Derivative_Instruments_And_Hed7
Derivative Instruments And Hedging Activity (Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location) (Details) (Not Designated as Hedging Instrument, USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivatives, Fair Value [Line Items] | |||
Total derivatives not designated as hedging instruments | $27,502 | $3,764 | |
Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31, | 19,569 | -4,752 | 7,236 |
Gain (loss) on commodity derivatives contracts | |||
Derivatives, Fair Value [Line Items] | |||
Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31, | 19,569 | -4,752 | 7,422 |
Interest expense | |||
Derivatives, Fair Value [Line Items] | |||
Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31, | 0 | 0 | -186 |
Current assets | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Assets | 19,687 | 0 | |
Other assets | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Assets | 7,815 | 7,545 | |
Current liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Liabilities | 0 | -3,403 | |
Long-term liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Liabilities | $0 | ($378) |
Capital_Stock_Narrative_Detail
Capital Stock (Narrative) (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||||||||||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 24, 2014 | Jun. 23, 2011 | Nov. 07, 2013 | Oct. 29, 2013 | Jun. 07, 2013 | Apr. 24, 2014 | Nov. 14, 2013 | Jun. 03, 2012 | Jun. 02, 2012 | Oct. 25, 2013 | Oct. 24, 2013 | 24-May-11 | Nov. 01, 2013 | Jun. 29, 2011 | |
Class of Stock [Line Items] | |||||||||||||||||
Common shares authorized for issuance (shares) | 275,000,000 | 275,000,000 | 275,000,000 | ||||||||||||||
Common stock, par value | $0.00 | $0.00 | $0.00 | ||||||||||||||
Common shares issued (shares) | 78,632,810 | 61,211,658 | |||||||||||||||
Proceeds from issuance of common shares, net of issuance costs | $101,319,000 | $0 | $0 | ||||||||||||||
Proceeds from issuance of preferred stock and preference stock | 2,064,000 | 50,183,000 | 49,250,000 | ||||||||||||||
Preferred stock dividends | 14,424,000 | 9,378,000 | 7,077,000 | ||||||||||||||
Common shares reserved for the exercise of stock options (shares) | 11,000,000 | 6,000,000 | |||||||||||||||
Repurchase of common shares | 0 | 9,753,000 | 0 | ||||||||||||||
Series B Preferred Stock | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Preferred shares authorized for issuance (shares) | 10,000,000 | 10,000,000 | |||||||||||||||
Preferred stock par value per share | $0.01 | $0.01 | |||||||||||||||
Preferred stock, shares sold (shares) | 2,140,000 | 2,140,000 | |||||||||||||||
Redemption Price | $25 | $25 | |||||||||||||||
On or after June 23, 2014 | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Redemption Price | $25 | ||||||||||||||||
Gastar Exploration USA | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Common shares authorized for issuance (shares) | 275,000,000 | 1,000 | 1,000 | ||||||||||||||
Common stock, par value | $0.00 | ||||||||||||||||
Common shares issued (shares) | 750 | 750 | 750 | ||||||||||||||
Shares of common stock in underwritten public offering | 17,000,000 | ||||||||||||||||
Price per share of underwritten public offering | $6.25 | ||||||||||||||||
Sales 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 shares authorized for issuance (shares) | 40,000,000 | 10,000,000 | |||||||||||||||
Preferred stock par value per share | $0.01 | $0.01 | |||||||||||||||
Preferred stock, shares sold (shares) | 646,295 | ||||||||||||||||
Preferred stock, dividend rate, percentage (percentage) | 8.63% | ||||||||||||||||
Redemption Price | $25 | ||||||||||||||||
Proceeds from issuance of preferred stock and preference stock | 13,600,000 | ||||||||||||||||
Payments of dividends | -8,700,000 | -8,500,000 | -7,100,000 | ||||||||||||||
Gastar Exploration USA | Series B Preferred Stock | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Preferred stock par value per share | $0.01 | ||||||||||||||||
Preferred stock, shares sold (shares) | 2,140,000 | 2,000,000 | |||||||||||||||
Preferred stock, dividend rate, percentage (percentage) | 10.75% | ||||||||||||||||
Redemption Price | $25 | ||||||||||||||||
Exercise of option to purchase additional shares | 140,000 | ||||||||||||||||
Total net proceeds from offering | 50,100,000 | ||||||||||||||||
Preferred stock redemption price per share | $25 | ||||||||||||||||
Aggregate common shares with option to convert from preferred shares | 11.5207 | ||||||||||||||||
Preferred stock dividends | 5,800,000 | 847,000 | |||||||||||||||
Gastar Exploration USA | At The Market Sales Agreement | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Preferred stock, shares sold (shares) | 4,045,000 | ||||||||||||||||
Proceeds from issuance of preferred stock and preference stock | 2,100,000 | ||||||||||||||||
Preferred stock shares authorized to be sold in at the market sales agreement | 3,400,000 | ||||||||||||||||
Preferred stock shares issued during current period | 86,840 | ||||||||||||||||
Cumulative net proceeds from issuance of preferred stock | 78,800,000 | ||||||||||||||||
Period after change in control to redeem preferred stock (days) | 90 days | ||||||||||||||||
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 | ||||||||||||||||
Chesapeake Energy Corporation | Gastar Exploration USA | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Amount paid to Chesapeake | 1,000,000 | ||||||||||||||||
Repurchase of common shares | $9,800,000 | ||||||||||||||||
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) | 4,561,508 | ||||||||||||||||
Stock options | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Common shares reserved for the exercise of stock options (shares) | 866,600 | ||||||||||||||||
PBUs | |||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||
Common shares reserved for the exercise of stock options (shares) | 990,658 |
Capital_Stock_Schedule_of_Issu
Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock options exercised (shares) | 7,500 | 10,000 | ||
Unvested restricted shares | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Restricted common shares granted (shares) | 601,473 | 2,288,179 | ||
Restricted common shares vested (shares) | 1,915,242 | 762,682 | ||
Shares of common stock issued pursuant to PBUs vested, net of forfeitures | 472,189 | 0 | ||
Common shares forfeited (shares) | 612,612 | [1] | 224,500 | [1] |
Common shares canceled (shares) | 47,398 | 512,862 | ||
[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 $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Dividend rate utilized in the Black-Scholes Merton valuation model | 0.00% | ||
Expected Forfeitures (percentage) | 25.50% | 14.00% | 15.50% |
Unrecognized expense for outstanding awards | $2.80 | ||
Stock-based compensation expense | 4.9 | 3.4 | 3.3 |
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected life (in years) | 6 years 3 months | ||
Unvested restricted shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 3 years | ||
Unrecognized expense for outstanding awards | 1.6 | ||
Weighted average period for recognition for unrecognized expense | 1 year 5 months 5 days | ||
Unvested restricted shares | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 2 years | ||
Unvested restricted shares | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting term (years) | 4 years | ||
PBUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 1.7 | ||
Total unrecognized expense for PBUs | $1.10 | ||
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) | 4,561,508 | ||
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_Sche
Equity Compensation Plans (Schedule of Weighted Average Grant Date Fair Value) (Details) (USD $) | 12 Months Ended | |||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Stock options | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Weighted average grant date fair value (in dollars per share) | $0 | $0 | $0 | |||
Intrinsic value of stock options exercised | $28 | [1] | $19 | [1] | $2 | [1] |
Grant date fair value of stock options vested | 27 | 88 | 117 | |||
Unvested restricted shares | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Weighted average grant date fair value (in dollars per share) | $5.85 | $1.30 | $2.09 | |||
Grant date fair value of stock options vested | $3,497 | $2,725 | $2,492 | |||
[1] | Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised. |
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 $) | 12 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | ||
Exercised | -7,500 | -10,000 |
Stock options | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | ||
Outstanding at beginning of period | 874,100 | |
Granted | 0 | |
Exercised | -7,500 | |
Canceled/Expired | 0 | |
Forfeited | 0 | |
Outstanding at end of period | 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 | 11.68 | |
Granted | 0 | |
Exercised | 2.6 | |
Canceled/Expired | 0 | |
Forfeited | 0 | |
Weighted-Average Exercise Price, Outstanding at end of period | 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) | 2 years 2 months 9 days | |
Aggregate Intrinsic Value (in thousands) | 0 |
Equity_Compensation_Plans_Sche1
Equity Compensation Plans (Schedule of Non-vested Options) (Details) (Stock options, USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding non-vested options beginning balance | 10,000 | ||
Stock options granted during the period | 0 | ||
Vested | -10,000 | ||
Forfeited | 0 | ||
Outstanding non-vested options ending balance | 0 | 10,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Outstanding non-vested options at beginning of period | $2.74 | ||
Granted | $0 | $0 | $0 |
Vested | $2.74 | ||
Forfeited | $0 | ||
Outstanding non-vested options at end of period | $0 | $2.74 | |
Weighted Average Exercise Price per Share | $0 | ||
Weighted Average Remaining Contractual Term (in years) | 0 years | ||
Aggregate Intrinsic Value (in thousands) | $0 |
Equity_Compensation_Plans_Rest
Equity Compensation Plans (Restricted Stock Activity) (Details) (Unvested restricted shares, USD $) | 12 Months Ended |
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 |
Unvested restricted shares | |
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, 2013 | 3,773,081 |
Granted | 601,473 |
Vested | -1,915,242 |
Forfeited | -47,398 |
Unvested PBUs at December 31, 2014 | 2,411,914 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Wieghted-Average Grant Date Fair Value, Outstanding at beginning of period | $1.82 |
Granted | $5.85 |
Vested | $1.83 |
Forfeited | $3.76 |
Weighted-Average Grant Date Fair Value, Outstanding at end of period | $2.79 |
Weighted Average Remaining Contractual Term (in years) | 8 years 1 month 10 days |
Aggregate Intrinsic Value (in thousands) | $5,813 |
Equity_Compensation_Plans_Summ
Equity Compensation Plans (Summary of PBUs) (Details) (PBUs, USD $) | 12 Months Ended |
Dec. 31, 2014 | |
PBUs | |
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, 2013 | 1,065,734 |
Granted | 280,171 |
Vested | -355,247 |
Forfeited | 0 |
Unvested PBUs at December 31, 2014 | 990,658 |
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, 2013 | $1.56 |
Granted | $7.34 |
Vested | $1.56 |
Forfeited | $0 |
Unvested PBUs at December 31, 2014 | $3.19 |
Equity_Compensation_Plans_Sche2
Equity Compensation Plans (Schedule of Future Amortization of Unrecognized Compensation Cost) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
2015 | $2,034 |
2016 | 663 |
2017 | 59 |
Total | $2,756 |
Interest_Expense_Schedule_of_C
Interest Expense (Schedule of Components of Interest Expense) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Interest expense: | ||||||
Cash and accrued | $28,851,000 | $14,130,000 | $1,992,000 | |||
Amortization of deferred financing costs | 3,067,000 | [1],[2] | 2,322,000 | [1],[2] | 224,000 | [1],[2] |
Capitalized interest | -4,347,000 | -3,284,000 | -1,946,000 | |||
Total interest expense | 27,571,000 | 13,168,000 | 270,000 | |||
Deferred financing costs written off | 1,200,000 | |||||
Accretion of debt discount | $2,300,000 | $716,000 | ||||
[1] | The years ended DecemberB 31, 2014 and 2013 include $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes. | |||||
[2] | The year ended DecemberB 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. bLong-Term Debt - Second Amended and Restated Revolving Credit Facility.b |
Related_Party_Transactions_Nar
Related Party Transactions (Narrative) (Details) (USD $) | 12 Months Ended | 36 Months Ended | 0 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2007 | Jun. 07, 2013 | |
Related Party Transaction [Line Items] | |||||
Repurchase of common shares | $0 | $9,753,000 | $0 | ||
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 | 10,800,000 | ||||
Repurchase of common shares | $9,800,000 | ||||
Repurchase of common stock (shares) | 6,781,768 |
Income_Taxes_Schedule_of_Incom
Income Taxes (Schedule of Income (loss) before Provision for Income Taxes) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Disclosure [Abstract] | |||
United States | $50,953 | $51,276 | ($152,322) |
Foreign | 0 | -1,934 | -1,469 |
Total income (loss) before income taxes | $50,953 | $49,342 | ($153,791) |
Income_Taxes_Schedule_of_Compo
Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Deferred: | |||
Federal | $0 | ($15,299) | $0 |
State | 0 | -743 | 0 |
Foreign | 0 | 0 | 0 |
Income tax expense (benefit) | $0 | ($16,042) | $0 |
Income_Taxes_Narrative_Details
Income Taxes (Narrative) (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Loss Carryforwards [Line Items] | ||
Foreign tax credit carry forwards | $50,681,000 | $50,681,000 |
Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Federal statutory rate | 35.00% | |
Net operating loss carryforwards | $447,000,000 |
Income_Taxes_Income_Tax_Reconc
Income Taxes (Income Tax Reconciliation) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Contingency [Line Items] | |||
Expected income tax provision (benefit) at statutory rate | $17,833 | $11,655 | ($53,827) |
State tax, tax effected | 803 | 96 | -2,562 |
Stock-based compensation expense | -1,291 | 605 | 560 |
Gain on acquisition of assets at fair value | 0 | -9,685 | 0 |
Non-deductible costs of migration from Canada to U.S. | 0 | 95 | 0 |
Other | 38 | -49 | 15 |
Other changes in valuation allowance | -17,383 | -38,777 | 55,939 |
Actual income tax provision | 0 | -16,042 | 0 |
Canada | |||
Income Tax Contingency [Line Items] | |||
Tax effect of Canadian tax rate differences | 0 | 193 | -125 |
Loss of Canadian tax attributes due to migration from Canada | $0 | $19,825 | $0 |
Income_Taxes_Schedule_of_Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Deferred tax asset (liability): | ||
Capital assets | ($134,223) | ($77,456) |
Stock-based compensation | 4,504 | 6,501 |
Net operating loss carry forwards | 164,056 | 122,675 |
Foreign tax credit carry forwards | 50,681 | 50,681 |
Valuation allowance | -85,018 | -102,401 |
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 $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items] | |||||||||||
Net income (loss) attributable to common stockholder | $26,671 | $9,807 | $2,016 | ($1,965) | ($3,344) | ($3,942) | $51,836 | ($4,586) | $36,529 | $39,964 | ($160,868) |
Weighted average common shares outstanding basic (shares) | 75,994,979 | 60,006,903 | 58,702,982 | 58,204,532 | 57,433,550 | 57,359,357 | 62,398,472 | 63,864,527 | 63,270,733 | 60,220,115 | 63,538,362 |
Weighted average common shares outstanding diluted (shares) | 78,577,762 | 63,399,446 | 61,922,874 | 58,204,532 | 57,433,550 | 57,359,357 | 63,813,423 | 63,864,527 | 66,492,589 | 63,618,401 | 63,538,362 |
Basic (dollars per share) | $0.35 | $0.16 | $0.03 | ($0.03) | ($0.06) | ($0.07) | $0.83 | ($0.07) | $0.58 | $0.66 | ($2.53) |
Diluted (dollars per share) | $0.34 | $0.15 | $0.03 | ($0.03) | ($0.06) | ($0.07) | $0.81 | ($0.07) | $0.55 | $0.63 | ($2.53) |
Common shares excluded from denominator as anti-dilutive (shares) | 34,058 | 3,505 | 2,768,402 | ||||||||
Unvested restricted shares | |||||||||||
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items] | |||||||||||
Incremental shares | 2,451,903 | 2,869,490 | 0 | ||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 34,058 | 3,505 | 1,831,435 | ||||||||
Stock options | |||||||||||
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items] | |||||||||||
Incremental shares | 97,491 | 26,095 | 0 | ||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 0 | 0 | 936,967 | ||||||||
PBUs | |||||||||||
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items] | |||||||||||
Incremental shares | 672,462 | 502,701 | 0 |
Commitments_And_Contingencies_1
Commitments And Contingencies (Narrative) (Details) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 17, 2010 | Apr. 22, 2014 | Oct. 30, 2014 | Jun. 07, 2013 | Jun. 30, 2014 | Jun. 17, 2014 | Dec. 31, 2010 | Dec. 31, 2011 | Aug. 07, 2013 | |
well | MMcf | |||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Office lease expense | $649,000 | $372,000 | $377,000 | |||||||||
Repurchase of common shares | 0 | 9,753,000 | 0 | |||||||||
Asset retirement obligation | 5,557,000 | 6,063,000 | 6,963,000 | 8,275,000 | ||||||||
Asset retirement obligation, current | 82,000 | 633,000 | ||||||||||
Asset retirement obligation, non-current | 5,475,000 | 5,430,000 | ||||||||||
Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Litigation settlement, gross | 21,200,000 | |||||||||||
Directors and officers liability coverage limit | 20,000,000 | |||||||||||
Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Number of wells drilled | 3 | |||||||||||
Gross acres | 3,300 | |||||||||||
Proved undeveloped well locations on lease | 87,700,000 | |||||||||||
Percentage of total company proved reserves | 19.00% | |||||||||||
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 | 13,700 | |||||||||||
Chesapeake Energy Corporation | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Repurchase of common shares | 9,800,000 | |||||||||||
Amount paid to Chesapeake | 10,800,000 | |||||||||||
SEI Energy LLC | Capacity | Fort Beeler Processing Plant | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Capacity of processing plants (MMcf/day) | 520 | |||||||||||
SEI Energy LLC | Capacity | Oak Grove Processing Plant | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Capacity of processing plants (MMcf/day) | 200 | |||||||||||
Gastar Exploration USA | Gastar Exploration USA Inc v Williams Ohio Valley Midstream LLC | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Litigation settlement, gross | 8,600,000 | |||||||||||
Damages sought in arbitration matter | 612,000 | |||||||||||
Gastar Exploration USA | Chesapeake Energy Corporation | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Litigation settlement, gross | 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 |
Commitments_And_Contingencies_2
Commitments And Contingencies (Schedule of Future Minimum Rental Commitments) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Commitments and Contingencies Disclosure [Abstract] | |
2015 | $640 |
2016 | 498 |
2017 | 187 |
2018 | 161 |
Total | $1,486 |
Concentration_of_Risk_and_Sign2
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, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
SEI | Customer Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 50.00% | 56.00% | 47.00% | |||
Sunoco | Customer Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 37.00% | 16.00% | 0.00% | |||
Clearfield Appalachian | Customer Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 0.00% | 8.00% | 14.00% | |||
ETC | Customer Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 0.00% | 8.00% | 24.00% | |||
Appalachian Basin | Geographic Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 39.00% | 65.00% | 72.00% | |||
Mid-Continent | Geographic Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 61.00% | 26.00% | 0.00% | |||
Hilltop Area, East Texas | Geographic Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 0.00% | [1] | 9.00% | [1] | 27.00% | [1] |
Powder River Basin | Geographic Concentration Risk | ||||||
Concentration Risk [Line Items] | ||||||
Concentration risk, percentage | 0.00% | [2] | 0.00% | [2] | 1.00% | [2] |
[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. | |||||
[2] | The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012. |
Statement_Of_Cash_Flows_Supple2
Statement Of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest, net of capitalized amounts | $24,632 | $7,341 | $39 |
Non-cash transactions: | |||
Capital expenditures included in accounts payable and accrued drilling costs | 12,777 | 582 | 4,666 |
Capital expenditures included in accounts receivable | 4,077 | -4,077 | -929 |
Asset retirement obligation included in oil and natural gas properties | 221 | -1,302 | 1,164 |
Asset retirement obligation sold/assigned to operator | -645 | -4,354 | -2,227 |
Application of advances to operators | 58,326 | 19,755 | 7,441 |
Other | ($11) | $47 | ($36) |
Quarterly_Consolidated_Financi2
Quarterly Consolidated Financial Data - Unaudited (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | |||||||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 07, 2013 | ||||
Schedule Of Quarterly Financial Information [Line Items] | ||||||||||||||||
Revenues | $61,448 | $41,746 | $35,897 | $32,327 | $26,725 | $18,840 | $30,926 | $11,264 | ||||||||
Income from operations | 37,063 | 20,413 | 12,539 | 8,497 | 5,178 | 1,626 | 13,809 | -1,849 | 78,512 | 18,764 | -153,528 | |||||
Income (loss) before provision for income taxes | 30,290 | 13,425 | 5,627 | 1,611 | -16,406 | [1] | -1,808 | [1] | 53,970 | [1] | -2,456 | [1] | ||||
NET INCOME (LOSS) | 30,290 | 13,425 | 5,627 | 1,611 | -364 | -1,808 | 53,970 | -2,456 | 50,953 | 49,342 | -153,791 | |||||
Dividend on preferred stock | 3,619 | 3,618 | 3,611 | 3,576 | 2,980 | 2,134 | 2,134 | 2,130 | ||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | 26,671 | 9,807 | 2,016 | -1,965 | -3,344 | -3,942 | 51,836 | -4,586 | 36,529 | 39,964 | -160,868 | |||||
Basic (in dollars per share) | $0.35 | $0.16 | $0.03 | ($0.03) | ($0.06) | ($0.07) | $0.83 | ($0.07) | $0.58 | $0.66 | ($2.53) | |||||
Diluted (in dollars per share) | $0.34 | $0.15 | $0.03 | ($0.03) | ($0.06) | ($0.07) | $0.81 | ($0.07) | $0.55 | $0.63 | ($2.53) | |||||
Basic (shares) | 75,994,979 | 60,006,903 | 58,702,982 | 58,204,532 | 57,433,550 | 57,359,357 | 62,398,472 | 63,864,527 | 63,270,733 | 60,220,115 | 63,538,362 | |||||
Diluted (shares) | 78,577,762 | 63,399,446 | 61,922,874 | 58,204,532 | 57,433,550 | 57,359,357 | 63,813,423 | 63,864,527 | 66,492,589 | 63,618,401 | 63,538,362 | |||||
Gain on acquisition of assets at fair value, net of income taxes | 43,700 | 0 | 27,670 | 0 | ||||||||||||
Chesapeake Assets | Gastar Exploration USA | ||||||||||||||||
Schedule Of Quarterly Financial Information [Line Items] | ||||||||||||||||
Gain on acquisition of assets at fair value, net of income taxes | 27,670 | |||||||||||||||
Deferred tax liability | $16,042 | |||||||||||||||
[1] | Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million. |
Supplemental_Oil_and_Gas_Discl2
Supplemental Oil and Gas Disclosures - Unaudited (Narrative) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | |||
Extractive Industries [Abstract] | |||
Asset retirement costs | $2.40 | $3.40 | $4.80 |
Supplemental_Oil_and_Gas_Discl3
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved properties: | $1,124,367 | $935,773 | $671,193 |
Total proved properties | 128,274 | 96,220 | 67,892 |
Total oil and natural gas properties | 1,252,641 | 1,031,993 | 739,085 |
Accumulated depreciation, depletion and amortization | -223,555 | -177,790 | -145,631 |
Net capitalized costs | 691,147 | 516,264 | 255,515 |
United States | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved properties: | 1,124,367 | 935,773 | 671,193 |
Total proved properties | 128,274 | 96,220 | 67,892 |
Impairment of proved oil and natural gas properties | ($337,939) | ($337,939) | ($337,939) |
Supplemental_Oil_and_Gas_Discl4
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) (United States, USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
United States | ||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||
Proved property acquisition | $0 | [1] | $189,594,000 | [1] | $0 | [1] |
Unproved property acquisition | 41,475,000 | [2] | 71,472,000 | [2] | 25,676,000 | [2] |
Exploration | 127,384,000 | 36,893,000 | 10,041,000 | |||
Development | 57,913,000 | 53,058,000 | 111,878,000 | |||
Total costs incurred | 226,772,000 | 351,017,000 | 147,595,000 | |||
Downward adjustment for fair value of acquisition | -2,600,000 | |||||
Adjustment for fair value of acquisition | $46,300,000 | |||||
[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_Discl5
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Results of Operations for Oil and Gas Producing Activities) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Extractive Industries [Abstract] | |||
Oil, condensate, natural gas and NGLs sales, including commodity derivatives | $171,418 | $87,755 | $49,940 |
Production expenses | -29,735 | -18,113 | -13,408 |
Impairment of oil and natural gas properties | 0 | 0 | -150,787 |
Depreciation, depletion and amortization | -45,765 | -32,158 | -25,195 |
Results of producing activities | $95,918 | $37,484 | ($139,450) |
Depreciation, depletion and amortization per MBoe | 12.34 | 9.94 | 11.41 |
Supplemental_Oil_and_Gas_Discl6
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, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||
Natural gas (per MMBtu): | |||||||||||||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Key natural gas and oil prices | 4.35 | [1] | 4.24 | [1] | 4.1 | [1] | 3.99 | [1] | 3.67 | [1] | 3.61 | [1] | 3.44 | [1] | 2.95 | [1] | 2.76 | [1] | 2.83 | [1] | 3.15 | [1] | 3.73 | [1] | |||
Oil (per Bbl): | |||||||||||||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Key natural gas and oil prices | 94.99 | [1] | 99.08 | [1] | 100.11 | [1] | 98.3 | [1] | 96.78 | [1] | 91.69 | [1] | 88.13 | [1] | 89.17 | [1] | 91.21 | [1] | 91.48 | [1] | 92.17 | [1] | 94.65 | [1] | |||
Henry Hub | Natural gas (per MMBtu): | |||||||||||||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Key natural gas and oil prices | 4.35 | 3.67 | 2.76 | ||||||||||||||||||||||||
WTI spot | Oil (per Bbl): | |||||||||||||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||||||||||||||||||||||||||
Key natural gas and oil prices | 94.99 | 96.78 | 94.71 | ||||||||||||||||||||||||
[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_Discl7
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
MBoe | MBoe | MBoe | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||||
Proved reserves as of the beginning of the period, equivalents | 54,634,000 | [1],[2] | 30,152,000 | [1],[2] | 19,953,000 | [1],[2] |
Extensions and discoveries | 42,810,000 | [1],[2],[3] | 15,483,000 | [1],[2],[4] | 14,861,000 | [1],[2],[5] |
Revisions of previous estimates | -8,574,000 | [1],[2] | -1,729,000 | [1],[2] | -2,230,000 | [1],[2] |
Production | -3,708,000 | [1],[2] | -3,237,000 | [1],[2] | -2,208,000 | [1],[2] |
Purchases in place | 14,639,000 | [1],[2] | 7,000 | [1],[2] | ||
Sales in place | -247,000 | [1],[2] | -4,132,000 | [1],[2] | -231,000 | [1],[2] |
Proved reserves at the end of the period. equivalents | 102,063,000 | [1],[2] | 54,634,000 | [1],[2] | 30,152,000 | [1],[2] |
Proved developed reserves | 36,789,000 | [1],[2] | 30,892,000 | [1],[2] | 21,109,000 | [1],[2] |
Proved undeveloped reserves | 65,274,000 | [1],[2] | 23,742,000 | [1],[2] | 9,042,000 | [1],[2] |
Total | 102,063,000 | [1],[2] | 54,634,000 | [1],[2] | 30,151,000 | [1],[2] |
Percentage of extensions and discoveries from successful drilling results in Marcellus Shale | 69.00% | 74.00% | ||||
Natural Gas | ||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||||
Proved reserves as of the beginning of the period | 180,710 | [6] | 131,010 | [6] | 91,652 | [6] |
Extensions and discoveries | 121,672 | [3],[6] | 52,750 | [4],[6] | 57,835 | [5],[6] |
Revisions of previous estimates | 2,465 | [6] | -8,114 | [6] | -6,518 | [6] |
Production | -11,598 | [6] | -13,366 | [6] | -10,564 | [6] |
Purchases in place | 26,961 | [6] | 0 | [6] | ||
Sales in place | -1,314 | [6] | -24,759 | [6] | -1,395 | [6] |
Proved reserves as of the end of the period | 287,005 | [6] | 180,710 | [6] | 131,010 | [6] |
Proved developed reserves | 114,564 | [6] | 114,195 | [6] | 95,602 | [6] |
Proved undeveloped reserves | 172,441 | [6] | 66,515 | [6] | 35,408 | [6] |
Total | 287,005 | [6] | 180,710 | [6] | 131,010 | [6] |
Natural Gas Liquids | ||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||||
Proved reserves as of the beginning of the period | 9,798,000 | [7] | 4,922,000 | [7] | 2,757,000 | [7] |
Extensions and discoveries | 9,394,000 | [3],[7] | 2,306,000 | [4],[7] | 2,783,000 | [5],[7] |
Revisions of previous estimates | -7,205,000 | [7] | -714,000 | [7] | -348,000 | [7] |
Production | -800,000 | [7] | -494,000 | [7] | -270,000 | [7] |
Purchases in place | 2,350,000 | [7] | 0 | [7] | ||
Sales in place | -4,000 | [7] | 0 | [7] | 0 | [7] |
Proved reserves as of the end of the period | 25,593,000 | [7] | 9,798,000 | [7] | 4,922,000 | [7] |
Proved developed reserves | 10,726,000 | [7] | 6,025,000 | [7] | 3,216,000 | [7] |
Proved undeveloped reserves | 14,867,000 | [7] | 3,773,000 | [7] | 1,706,000 | [7] |
Total | 25,593,000 | [7] | 9,798,000 | [7] | 4,922,000 | [7] |
Oil | ||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||||
Proved reserves as of the beginning of the period | 14,718,000 | [7] | 3,394,000 | [7] | 1,921,000 | [7] |
Extensions and discoveries | 13,137,000 | [3],[7] | 4,385,000 | [4],[7] | 2,439,000 | [5],[7] |
Revisions of previous estimates | -1,780,000 | [7] | 337,000 | [7] | -796,000 | [7] |
Production | -975,000 | [7] | -515,000 | [7] | -177,000 | [7] |
Purchases in place | 7,796,000 | [7] | 7,000 | [7] | ||
Sales in place | -24,000 | [7] | -5,000 | [7] | 0 | [7] |
Proved reserves as of the end of the period | 28,636,000 | [7] | 14,718,000 | [7] | 3,394,000 | [7] |
Proved developed reserves | 6,968,000 | [7] | 5,834,000 | [7] | 1,959,000 | [7] |
Proved undeveloped reserves | 21,668,000 | [7] | 8,884,000 | [7] | 1,435,000 | [7] |
Total | 28,636,000 | [7] | 14,718,000 | [7] | 3,394,000 | [7] |
[1] | Thousand barrels of oil, condensate or NGLs equivalent. | |||||
[2] | 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. | |||||
[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 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery. | |||||
[6] | Million cubic feet or million cubic feet equivalent, as applicable | |||||
[7] | Thousand barrels |
Supplemental_Oil_and_Gas_Discl8
Supplemental Oil and Gas Disclosures - Unaudited (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves) (Details) (United States, USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
In Thousands, unless otherwise specified | |||||
United States | |||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||||
Future cash inflows | $3,855,227 | $2,103,023 | $672,142 | ||
Future production costs | -1,048,554 | -588,568 | -167,864 | ||
Future development costs | -611,602 | -296,666 | -83,697 | ||
Future income taxes | -486,593 | -215,502 | 0 | [1] | |
Future net cash flows | 1,708,478 | 1,002,287 | 420,581 | ||
10% annual discount for estimated timing of cash flows | -891,739 | -486,458 | -213,772 | ||
Standardized measure of discounted future cash flows | $816,739 | $515,829 | $206,809 | $212,783 | |
[1] | No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows. |
Supplemental_Oil_and_Gas_Discl9
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) (United States, USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
United States | |||
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Beginning of period | $515,829 | $206,809 | $212,783 |
Extensions and discoveries, less related costs | 369,806 | 196,448 | 112,390 |
Sale of natural gas and oil, net of production costs | -122,114 | -74,394 | -29,110 |
Purchases of reserves in place | 247,208 | 64 | |
Sales of reserves in place | -1,475 | -9,063 | -216 |
Revisions of previous quantity estimates | 101,044 | 6,191 | -30,959 |
Net change in income tax | -95,245 | -76,701 | 4,334 |
Net change in prices and production costs | 59,786 | 79,820 | -98,589 |
Accretion of discount | -3,996 | 1,211 | 1,152 |
Development costs incurred | 37,461 | 23,567 | 19,702 |
Net change in estimated future development costs | -1,277 | -97,461 | 2,518 |
Change in production rates (timing) and other | -43,081 | 12,194 | 12,740 |
End of period | $816,739 | $515,829 | $206,809 |