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•	financial position;

•	business strategy and budgets;

•	capital expenditures;

•	drilling of wells, including the scheduling and results of such operations;

•	oil, natural gas and natural gas liquids (“NGLs”) reserves;

•	timing and amount of future production of oil, condensate, natural gas and NGLs;

•	operating costs and other expenses;

•	cash flow and liquidity;

•	compliance with covenants under our indenture and credit agreements;

•	availability of capital;

•	prospect development; and

•	property acquisitions and sales.

•	the supply and demand for oil, condensate, natural gas and NGLs;

•	continued low or further declining prices for oil, condensate, natural gas and NGLs;

•	worldwide political and economic conditions and conditions in the energy market;

•	the extent to which we are able to realize the anticipated benefits from acquired assets;

•	our ability to raise capital to fund capital expenditures or repay or refinance debt upon maturity;

•	our ability to meet financial covenants under our indenture or credit agreements or the ability to obtain amendments or waivers to effect such compliance;

•	the ability and willingness of our current or potential counterparties, third-party operators or vendors to enter into transactions with us and/or to fulfill their obligations to us;

•	failure of our joint interest partners to fund any or all of their portion of any capital program;

•	the ability to find, acquire, market, develop and produce new oil and natural gas properties;

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•	uncertainties about the estimated quantities of oil and natural gas reserves and in the projection of future rates of production and timing of development expenditures of proved reserves;

•	strength and financial resources of competitors;

•	availability and cost of material and equipment, such as drilling rigs and transportation pipelines;

•	availability and cost of processing and transportation;

•	changes or advances in technology;

•	the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry wells, operating hazards inherent to the natural gas and oil business and down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

•	potential mechanical failure or under-performance of significant wells or pipeline mishaps;

•	environmental risks;

•

possible new legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to, national healthcare, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, changes in environmental regulations, environmental risks and liability under federal, state and local environmental laws and regulations;

•	effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;

•	potential losses from pending or possible future claims, litigation or enforcement actions;

•	potential defects in title to our properties or lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;

•	the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

•	our ability to find and retain skilled personnel; and

•	any other factors that impact or could impact the exploration of natural gas or oil resources, including, but not limited to, the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of natural gas and oil.

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•	exploitation and development of our Mid-Continent assets in the Hunton Limestone horizontal oil play;

•	continued exploitation of existing Marcellus Shale assets with a focus on areas that we believe are prospective for natural gas with relatively high condensate and NGLs content;

•	additional testing of the Utica Shale;

•	active management of our domestic drilling programs; and

•	effective management and utilization of technological expertise.

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(1)	Represents highest daily gross Boe rate.

(2)	Represents gross average production for actual producing days through February 28, 2015.

(3)	After payout working interest is 45.0%.

(4)	After payout working interest is 49.9%.

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(1)	Represents highest daily gross Boe rate.

(2)	Represents gross average production for actual producing days through February 28, 2015.

(1)	Represents highest daily gross Boe rate.

(2)	Represents gross average production for actual producing dates through February 28, 2015.

(3)	The Warsaw 33-1 is a vertical well.

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(1)	Excludes the impact of hedging activities.

(2)	Production costs include lease operating expense, insurance, transportation, treating and gathering and workover expense and excludes ad valorem and severance taxes.

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(1)	Average well lateral length approximates the actual average well lateral length for wells that have been completed and the estimated average well lateral length for wells that have not been completed.

(2)	The Goudy pad is projected to ultimately have nine gross wells, four of which were initially placed on production in August 2013 and three of which are awaiting completion.

(3)	The Hoyt pad is projected to ultimately have seven gross wells.

(4)	The Blake pad is projected to ultimately have nine gross wells.

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(2)	The year ended December 31, 2014 includes the benefit of a non-recurring revenue adjustment related to an arbitration settlement. Excluding the arbitration settlement adjustment impact, average sales prices would have been as follows:

(3)	The year ended December 31, 2014 includes a non-recurring adjustment to production taxes, lease operating expenses and transportation, treating and gathering related to an arbitration settlement. Excluding the arbitration settlement adjustment impact, production taxes, lease operating expenses and transportation, treating and gathering per Boe would have been as follows:

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(4)	Production costs include lease operating expense, insurance, transportation, treating and gathering and workover expense and excludes ad valorem and severance taxes. Excluding the arbitration settlement adjustment impact, production costs for the year ended December 31, 2014 would have been as follows:

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(1)	Excludes the impact of hedging activities.

(2)	Production costs include lease operating expense, insurance, gathering and workover expense and excludes ad valorem and severance taxes.

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•	Code of Conduct and Ethics;

•	Corporate Governance Guidelines;

•	Audit Committee Charter;

•	Nominating and Governance Committee Charter:

•	Compensation Committee Charter;

•	Reserves Review Committee Charter; and

•	Whistleblower Procedure.

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•	The domestic and foreign supply and demand of oil, condensate, natural gas and NGLs;

•	Volatile trading patterns in the commodity futures markets;

•	Overall economic conditions and market uncertainty;

•	Weather conditions;

•	The cost of exploring for, developing, producing, transporting and marketing natural gas, condensate, oil and NGLs;

•	The proximity to, and capacity of, natural gas pipelines and other transportation facilities;

•	Political conditions in the Middle East and other oil producing regions, such as Venezuela;

•	Domestic and foreign governmental regulations; and

•	The price and availability of competing alternative fuels.

•	Adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations and our ability to meet our financial covenants under our debt agreements;

•	Reducing the amount of oil, condensate, natural gas and NGLs that we can produce economically;

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•	Causing us to delay or postpone some of our capital projects;

•	Reducing our revenues, operating income or cash flows;

•	Reducing the amounts of our estimated proved oil and natural gas reserves;

•	Reducing the carrying value of our oil and natural gas properties;

•	Reducing the standardized measure of discounted future net cash flows relating to oil and natural gas reserves;

•	Reducing or eliminating our ability to pay dividends on our outstanding preferred stock; and

•	Limiting our access to sources of capital, such as equity and long-term debt.

•	Our estimated proved oil and natural gas reserves;

•	The amount of oil, condensate, natural gas and NGLs that we produce from existing wells;

•	The prices at which we sell our production;

•	The costs of developing and producing our oil and natural gas production;

•	Our ability to acquire, locate and produce new reserves;

•	The ability and willingness of banks to lend to us; and

•	Our ability to access the capital markets.

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•	Unexpected drilling conditions;

•	Blowouts, fires or explosions with resultant injury, death or environmental or natural resource damages;

•	Pressure or irregularities in formations;

•	Environmental hazards, such as natural gas leaks, crude oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment;

•	Uncontrollable flows of natural gas, oil, brine water or drilling fluids;

•	Equipment failures or accidents;

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•	Adverse weather conditions;

•	Compliance with existing and any future governmental laws and regulations; and

•	Shortages or delays in the availability of drilling rigs and the delivery of equipment or obtaining water for hydraulic fracturing operations.

•	Historical oil or natural gas production from that area, compared with production from other producing areas;

•	Assumptions concerning the effects of regulations by governmental agencies;

•	Assumptions concerning future prices;

•	Assumptions concerning future transportation and operating costs;

•	Assumptions concerning severance and excise taxes; and

•	Assumptions concerning development costs and workover and remedial costs.

•	The amount and timing of actual production;

•	Supply and demand for oil or natural gas;

•	Actual prices received for oil or natural gas in the future being different than those used in the estimate;

•	Curtailments or increases in consumption of oil or natural gas;

•	Changes in governmental regulations or taxation; and

•	The timing of both production and expenses in connection with the development and production of oil or natural gas properties.

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•	Timing and amount of capital expenditures;

•	The operator’s expertise and financial resources;

•	Approval of other participants in drilling wells; and

•	Selection of technology.

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•	Transfer or sell assets or use asset sale proceeds;

•	Incur or guarantee additional debt or issue preferred equity securities;

•	Pay dividends, redeem subordinated debt or make other restricted payments;

•	Make certain investments;

•	Create or incur certain liens on our assets;

•	Incur dividend or other payment restrictions affecting our restricted subsidiaries;

•	Enter into certain transactions with affiliates;

•	Merge, consolidate or transfer all or substantially all of our assets;

•	Enter into certain sale and leaseback transactions; and

•	Take or omit to take any actions that would adversely affect or impair in any material respect the collateral securing the Notes.

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•	Drilling and abandonment bonds or other financial responsibility assurances;

•	Restriction on types, quantities and concentration of materials that may be released into the environment;

•	Reports concerning operations;

•	Spacing of wells;

•	Limits or prohibitions on drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

•	The application of specific health and safety criteria addressing worker protection;

•	The imposition of substantial liabilities for pollution resulting from our operations;

•	Limitations on access to properties;

•	Taxation; and

•	Other regulatory controls on operating activities.

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•	Well blowouts, fires and explosions;

•	Surface craterings and casing collapses;

•	Road collapses;

•	Uncontrollable flows of natural gas, oil, brine, water or well fluids;

•	Pipe and cement failures;

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•	Formations with abnormal pressures;

•	Stuck drilling and service tools;

•	Pipeline or tank ruptures or spills;

•	Natural disasters; and

•	Environmental hazards, such as natural gas leaks, crude oil spills and unauthorized discharges of brine, toxic gases or well fluids.

•	Injury or death;

•	Damage to and destruction of property, natural resources and equipment;

•	Damage to natural resources due to underground migration of hydraulic fracturing fluids;

•	Pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids;

•	Regulatory investigations and penalties;

•	Suspension of operations; and

•	Repair, restoration and remediation costs.

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•	Mid-Continent area of the U.S. in Oklahoma;

•	Marcellus Shale in the Appalachian Basin in West Virginia and central and southwestern Pennsylvania; and

•	Utica Shale in the Appalachian Basin in West Virginia.

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(2)	The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented.

(4)

General and administrative expenses include non-recurring costs related to acquisitions, severance related to property divestment and corporate migration of $263,000, $4.2 million and $834,000 for the years ended December 31, 2014, 2013 and 2012, respectively. Excluding such costs, general and administrative expenses would have been $4.37 per Boe, $3.95 per Boe and $5.15 per Boe for each respective year.

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(2)	The Marcellus West acreage reflects that Atinum has earned their full joint venture interest.

(3)	Approximately 27,900 gross (11,500 net) acres of our Marcellus West acreage, of which approximately 4,300 gross (1,900 net) acres are pending lease finalization, should be prospective for high-pressure, high-deliverability dry natural gas development in the Utica Shale.

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(1)

PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proved reserves. PV-10 is a non-U.S. GAAP financial measure because it excludes the effects of income taxes. We believe that PV-10 is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may use the measure as a basis for comparison of the relative size and value of our reserves to other companies. PV-10 should not be considered as an alternative to standardized measure of discounted future net cash flows as defined under U.S. GAAP. At December 31, 2014, we presently have approximately $447.0 million of net operating loss carryforwards, $50.7 million of foreign tax credit carryforwards and $357.5 million of remaining property tax basis for Federal income tax purposes. Based on these carryforwards and current and future property tax basis, future income taxes discounted at 10% total $171.9 million, resulting in a standardized measure of discounted future net cash flows of $816.7 million as of December 31, 2014.

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(1)	Key benchmark base prices utilized were the Henry Hub price of $4.35 per MMBtu for natural gas and a WTI spot oil price of $94.99 per barrel.

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•	The level and success of exploration and development activity;

•	The sales prices of oil, condensate, natural gas and NGLs;

•	The level of total sales volumes of oil, condensate, natural gas and NGLs; and

•	The availability of and our ability to raise the capital necessary to meet our cash flow and liquidity needs.

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(2)	The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented.

(4)

General and administrative expenses include non-recurring costs related to acquisitions, severance related to property divestment and corporate migration of $263,000, $4.2 million and $834,000 for the years ended December 31, 2014, 2013 and 2012, respectively. Excluding such costs, general and administrative expenses would have been $4.37 per Boe, $3.95 per Boe and $5.15 per Boe for each respective year.

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(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.

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(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.

(1)	For the period April to December 2015.

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(1)	For a discussion of the Revolving Credit Facility and the Notes, see Item 8. “Financial Statements and Supplementary Data, Note 4. Long-Term Debt” included in this Form 10-K.

(2)	Interest payments have been calculated by applying the weighted average interest rate of 8.625% at December 31, 2014 to the outstanding Notes balance of $325.0 million at December 31, 2014 and by applying the weighted average interest rate of 2.42% at December 31, 2014 to the outstanding Revolving Credit Facility balance of $45.0 million at December 31, 2014.

(3)	In conjunction with certain crude commodity derivatives contracts, we deferred the payment of certain put premiums for the period January 2015 to August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month.

(4)	Our Houston office lease obligation expires August 31, 2016, our West Virginia office lease expires on December 31, 2018 and our Oklahoma office lease expires on October 31, 2018.

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•	It requires assumptions to be made that are uncertain at the time the estimate is made; and

•	Changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

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1.	Description of Business

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3.	Property, Plant and Equipment

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(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.

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4.	Long-Term Debt

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•	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.

•	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.

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•	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.

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6.	Fair Value Measurements

•	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

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(1)	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations.

7.	Derivative Instruments and Hedging Activity

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(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.

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(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.

(1)	For the period April to December 2015.

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8.	Capital Stock

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(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.

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(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.

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10.	Interest Expense

(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.

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(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.

16.	Statement of Cash Flows – Supplemental Information

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(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.

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(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.

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(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.

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(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.

(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.

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(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.

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(1)	Messrs. Porter, Gerlich and McCown are our only “Executive Officers” as such term is defined by the rules promulgated by the SEC.

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•	Review total direct compensation (base salary, annual incentives and long-term incentives) for the Named Executive Officers;

•	Assess the market competitiveness of executive compensation as compared to our peer group and published surveys of other companies in the oil and natural gas industry with revenues and capital assets comparable to our revenue and capital assets; and

•	Provide conclusions and recommended considerations for current total direct compensation packages for our Named Executive Officers.

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•	Stock-based compensation aligns the interests of our Named Executive Officers with those of the shareholders by providing equity participation to our Named Executive Officers; and

•	The vesting period incorporated into stock-based compensation fosters a longer-term perspective necessary for executive retention, stability and continuity.

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(1)

The dollar values of restricted stock and PBUs awards provided are equal to the aggregate grant date fair value of such grants awarded to Messrs. Porter and Gerlich during the years ended December 31, 2014, 2013 and 2012 and to Mr. McCown during the years ended December 31, 2014 and 2013 calculated in accordance with Accounting Standards Codification Topic 718 (“ASC 718”) prior to a deduction for estimated forfeitures related to service-based conditions. For a description of the assumptions used in calculating these amounts for 2014, see Item 8. “Financial Statements and Supplementary Data, Note 9. Equity Compensation Plans” included in this Form 10-K.

(2)	Mr. McCown was appointed as an executive officer on June 7, 2013.

(3)	All other compensation includes the Company's contribution to the named executive officer's retirement plan.

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(1)	The fair value of the respective restricted share and PBU grants as of the grant date is calculated in accordance with ASC 718. These shares and units are subject to a 3-year vesting schedule of 33.33% each year, beginning on the first anniversary date of the grant. Upon vesting, the PBUs can be settled at 0% to 200% depending upon our stock price performance.

(2)	The estimated future payout for PBUs assumes a target payout of 100% of units granted and a maximum payout of 200% of units granted. For additional information, see “Compensation Discussion & Analysis.”

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(1)	For purposes of this table, we assumed that the unvested PBUs granted on January 30, 2013 will vest at the target of 100% with a fair value of $4.66 per unit on December 31, 2014 the unvested PBUs granted on January 30, 2014 will vest at the target of 100% with a fair value of $0.73 per unit on December 31, 2014.

(2)	The closing price of our common shares on December 31, 2014 was $2.41.

(3)

The 41,966 unvested restricted common shares granted to Mr. Porter on March 15, 2011 vest 100% on March 15, 2015. The 84,459 unvested restricted shares granted to Mr. Porter on January 30, 2012 vest 100% on January 30, 2015. The 323,276 unvested restricted shares granted to Mr. Porter on January 30, 2013 vest 50.0% on January 30, 2015 and 2016, respectively. The 116,380 unvested restricted common shares granted to Mr. Porter on January 30, 2014 vest 33.3% on January 30, 2015, 2016 and 2017, respectively.

(4)	The 22,482 unvested restricted common shares granted to Mr. Gerlich on March 15, 2011 vest 100% on March 15, 2015. The 42,230 unvested restricted shares granted to Mr. Gerlich on January 30, 2012 vest 100% on January 30,

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(5)

The 12,230 unvested restricted common shares granted to Mr. McCown on March 15, 2011 vest 100% on March 15, 2015. The 29,279 unvested restricted common shares granted to Mr. McCown on January 30, 2012 vest 100% on January 30, 2015. The 112,069 unvested restricted common shares granted to Mr. McCown on January 30, 2013 vest 50% on January 30, 2015 and 2016, respectively. The 43,104 unvested restricted common shares granted to Mr. McCown on January 30, 2014 vest 33.3% on January 30, 2015, 2016 and 2017, respectively.

(1)	Equals the closing stock price of our common shares on the day prior to the applicable vesting date multiplied by the number of restricted shares vesting on such date.

(1)	The first tranche of the January 30, 2013 PBU grant vested at 200% of the amount granted.

(2)	Equals the closing stock price of our common shares on the day prior to the applicable vesting date multiplied by the number of PBUs vesting on such date.

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(1)

Per Mr. Porter’s employment agreement, if he is involuntarily terminated for any reason other than for Reasonable Cause (as defined below) and if proper notice is received, Mr. Porter will be entitled to a lump sum severance payment equal to the product of 4.5 multiplied by the highest annual base salary in effect at any time during the one year period preceding his termination. At December 31, 2014, Mr. Porter’s severance was calculated by multiplying $535,000 by 4.5. If Mr. Porter is considered a “specified employee” under Section 409A of the Code at the time of his termination, this payment will be delayed for a period of six months if necessary to avoid the additional excise tax under Section 409A of the Code. If Mr. Porter timely elects COBRA continuation coverage, he and his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan, which is currently 18 months (the “COBRA Continuation Period”). As of December 31, 2014, the cost for health and medical coverage for Mr. Porter as an employee was $1,791 per month. Mr. Porter currently is entitled to 20 working days of vacation per year. He would receive a lump-sum cash payment of his unused vacation time of up to 10 days that are not used during each year employed. As of December 31, 2014, Mr. Porter had available 2.2 days of accrued but unused vacation pay. In addition, effective on Mr. Porter’s termination for any reason other than if Mr. Porter elects to terminate his own employment, the unvested portion of all stock options held by Mr. Porter will immediately vest and be exercisable for a period of 90 days. All other terms and conditions of his stock options will remain

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(2)

The Severance Plan provides that if an employee incurs an involuntary termination within a two-year period following a change of control (or, in certain limited circumstances, during the six month period prior to a change of control), covered employees, including Named Executive Officers, will receive a lump-sum cash payment equal to the applicable severance period times the sum of the covered employee’s annual pay and target bonus, contingent on the employee executing a full release and settlement agreement. Mr. Porter’s severance period is 3 years, and his annual salary and 89% target bonus at December 31, 2014 were $535,000 and $476,150, respectively. Mr. Gerlich’s severance period is 2.5 years, and his annual salary and 88% target bonus at December 31, 2014 were $312,000 and $274,560, respectively. Mr. McCown’s severance period is 2.5 years, and his annual salary and 88% target bonus at December 31, 2014 were $312,000 and $274,560, respectively. The Employee Severance Plan provides that if there is a change of control, covered employees, including Named Executive Officers, will be eligible to receive reimbursement of COBRA costs. Other termination or severance compensation is determined by the individual Named Executive Officer’s employment agreement. The The Severance Plan does not change the specific, non-change of control severance payments in place under the existing employment agreements with our Named Executive Officers but does provide change of control severance benefits to the Named Executive Officers only if they are greater than the severance benefits provided under the employment agreement. The Severance Plan does not allow for any duplication of severance benefits. Additionally, the award agreements for the Named Executive Officers restricted stock, PBUs and stock option agreements provide for the acceleration of vesting upon a change of control, thus the

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(3)

Per their respective employment agreements, we are not obligated to pay any amounts to Messrs. Mr. Porter, Gerlich or McCown other than accrued and unused vacation days and their pro-rata base salary through the date of his termination of employment, as a result of a termination for Reasonable Cause (as defined below). Only the stock options held by Messrs. Porter and Gerlich that were already vested as of December 31, 2014, would remain eligible for exercise following his termination of employment.

(4)

Per their respective employment agreements, if Messrs. Porter’s, Gerlich’s or McCown’s employment terminates due to death, his eligible beneficiary will be entitled to receive his severance payment as described in Footnote 1 above. If Messrs. Porter’s, Gerlich’s or McCown’s employment terminates due to Disability (as defined below), he shall be entitled to receive a severance payment in the form and amount as determined in Footnote 1 above.

(5)

Our Severance Plan provides that if the Named Executive Officer receives a payment or benefit that is subject to the “golden parachute” excise tax, the Named Executive Officers will receive an additional payment under the severance plan to make him or her “whole” for that excise tax and any taxes on the additional parachute tax gross-up payment (the “gross-up payment”). If the total payments provided to an individual that were contingent on a change in control exceed three times an individual’s “base amount,” that individual is considered to be receiving a “parachute payment.” If the individual is considered to have received a “parachute payment,” then a tax will be imposed on any “excess parachute payment” amount, which is the amount in excess of one times the individual’s “base amount.” To determine Messrs. Porter’s and Gerlich’s amount of the gross-up payment, Messrs. Porter’s and Gerlich’s “base amount” was calculated using the five-year average of his compensation for the years 2010-2014. In making the calculation, the following assumptions were used: (a) the change of control occurred on December 31, 2014, (b) the closing price of our stock was $2.41 on such date, (c) the excise tax rate under Section 4999 of the Code is 20%, the federal income tax rate is 35%, the Medicare rate is 1.45%, the adjustment to reflect the phase-out of itemized deductions is 1.05%, and there is no state or local income taxes, (d) no amounts will be discounted as attributable to reasonable compensation, (e) all cash severance payments are contingent upon a change of control, (f) the presumption required under applicable regulations that the equity awards granted were contingent upon a change of control could be rebutted. To determine Mr. McCown’s amount of the gross-up payment, Mr. McCown’s “base amount” was calculated using the average of the 2010-2014 compensation. In making the calculation, the following assumptions were used: (a) the change of control occurred on December 31, 2014, (b) the closing price of our stock was $2.41 on such date, (c) the excise tax rate under Section 4999 of the Code is 20%, the federal income tax rate is 35%, the Medicare rate is 1.45%, the adjustment to reflect the phase-out of itemized deductions is 1.05%, and 6% state or local income taxes, (d) no amounts will be discounted as attributable to reasonable compensation, (e) all cash severance payments are contingent upon a change of control, (f) the presumption required under applicable regulations that the equity awards granted were contingent upon a change of control could be rebutted.

(6)

The award agreements for the Named Executive Officers restricted stock, PBUs and stock options agreements provide for the acceleration of vesting upon a change of control, thus the amounts in the table above reflect the acceleration of the outstanding PBUs and restricted stock awards each Named Executive Officer held as of December 31, 2014. As of December 31, 2014, no stock option awards were unvested so no value has been included in the table above with respect to the accelerated vesting of stock options. The amount shown is the product of the number of restricted shares and PBUs held by the Named Executive Officer times the closing price of our common shares on December 31, 2014 or $2.41 per common share.

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•	$3,750 per month, paid semi-annually;

•	An aggregate of $25,000 per year for the Chairman of the Board;

•	An aggregate of $15,000 for the Chairman of the Audit Committee;

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•	An aggregate of $9,000 per year for the Chairman of the Compensation Committee;

•	An aggregate of $7,500 for the Chairman of the Nominating and Corporate Governance Committee; and

•	$1,550 for each meeting of the Board attended in person, $1,000 for each meeting attended telephonically and $1,000 for each committee meeting attended in person.

(1)	Amounts reflect the grant date fair value of restricted common stock grants awarded to each of our outside directors during the year ended December 31, 2014, calculated in accordance with ASC 718 prior to a deduction for estimated forfeitures related to service-based vesting conditions.

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(1)	The closing price of our common shares on December 31, 2014 was $2.41.

(2)

The 4,496 unvested restricted common shares granted to Mr. Cassels on March 15, 2011 vest 100% on March 15, 2015. The 8,446 unvested restricted shares granted to Mr. Cassels on January 30, 2012 vest 100% on January 30, 2015. The 43,103 unvested restricted common shares granted to Mr. Cassels on January 30, 2013 vest 50% on January 30, 2015 and 2016, respectively. The 8,667 unvested restricted common shares granted to Mr. Cassels on November 11, 2013 vest 50% on November 11, 2015 and 2016, respectively. The 17,241 unvested restricted common shares granted to Mr. Cassels on January 30, 2014 vest 33.3% on January 30, 2015, 2016 and 2017, respectively.

(3)

The 4,496 unvested restricted common shares granted to Mr. Coley on March 15, 2011 vest 100% on March 15, 2015. The 8,446 unvested restricted common shares granted to Mr. Coley on January 30, 2012 vest 100% on January 30, 2015. The 43,103 unvested restricted common shares granted to Mr. Coley on January 30, 2013 vest 50% on January 30, 2015 and 2016, respectively. The 8,667 unvested restricted common shares granted to Mr. Coley on November 11, 2013 vest 50% on November 11, 2015 and 2016, respectively. The 17,241 unvested restricted common shares granted to Mr. Coley on January 30, 2014 vest 33.3% on January 30, 2015, 2016 and 2017, respectively.

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(4)	The 32,206 unvested restricted common shares granted to Mr. Holditch on August 8, 2014 vest 33.3% on August 8, 2015, 2016 and 2017, respectively.

(5)

The 4,496 unvested restricted common shares granted to Mr. Penner on March 15, 2011 vest 100% on March 15, 2015. The 8,446 unvested restricted common shares granted to Mr. Penner on January 30, 2012 vest 100% on January 30, 2015. The 43,103 unvested restricted common shares granted to Mr. Penner on January 30, 2013 vest 50% on January 30, 2015 and 2016, respectively. The 8,667 unvested restricted common shares granted to Mr. Penner on November 11, 2013 vest 50% on November 11, 2015 and 2016, respectively. The 17,241 unvested restricted common shares granted to Mr. Penner on January 30, 2014 vest 33.3% on January 30, 2015, 2016 and 2017, respectively.

(6)	The 32,206 unvested restricted common shares granted to Mr. Schuyler on August 8, 2014 vest 33.3% on August 8, 2015, 2016 and 2017, respectively.

(7)

The 4,496 unvested restricted common shares granted to Mr. Selser on March 15, 2011 vest 100% on March 15, 2015. The 8,446 unvested restricted common shares granted to Mr. Selser on January 30, 2012 vest 100% on January 30, 2015. The 43,103 unvested restricted common shares granted to Mr. Selser on January 30, 2013 vest 50% on January 30, 2015 and 2016, respectively. The 17,333 unvested restricted common shares granted to Mr. Selser on November 11, 2013 vest 50% on November 11, 2015 and 2016, respectively. The 17,241 unvested restricted common shares granted to Mr. Selser on January 30, 2014 vest 33.3% on January 30, 2015, 2016 and 2017, respectively.

•	Each of our directors;

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•	Each of our executive officers, as listed in the Summary Compensation Table, set forth under “Executive Compensation;”;

•	All of our executive officers and directors as a group; and

•	Each person known to us to be the beneficial owner of more than 5% of our outstanding common shares.

(1)	Based upon a Schedule 13D filed in respect of Gastar Exploration Inc. on January 22, 2015, as amended. Voting and dispositive power is shared with Kleinheinz Capital Partners, Inc., John B. Kleinheinz and Fred N. Reynolds.

(2)	Based upon a Schedule 13G filed in respect of Gastar Exploration Inc. on February 3, 2015.

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(3)	The contact address for our directors and executive officers is 1331 Lamar Street, Suite 650, Houston, Texas 77010. Individuals holding unvested restricted common shares have the right to vote those common shares.

(4)	As of March 11, 2015, Mr. Cassels owned 73,398 common shares directly and beneficially held 87,877 unvested restricted common shares. Individuals holding unvested restricted common shares have the right to vote those common shares.

(5)	As of March 11, 2015, Mr. Coley owned 80,253 common shares directly, beneficially held 87,877 unvested restricted common shares and held stock options to purchase 40,000 common shares, all of which currently are vested and exercisable as of March 11, 2015 regardless of trading price. Individuals holding unvested restricted common shares have the right to vote those common shares.

(6)	As of March 11, 2015, Mr. Holditch owned 26,950 common shares directly and beneficially held 73,873 unvested restricted common shares. Individuals holding unvested restricted common shares have the right to vote those common shares.

(7)	As of March 11, 2015, Mr. Penner owned 120,898 common shares directly, beneficially held 87,876 unvested restricted common shares, and held stock options to purchase 55,000 common shares, all of which currently are vested and exercisable as of March 11, 2015 regardless of trading price. Individuals holding unvested restricted common shares have the right to vote those common shares.

(8)	As of March 11, 2015, Mr. Schuyler beneficially held 73,873 unvested restricted common shares. Individuals holding unvested restricted common shares have the right to vote those common shares.

(9)

As of March 11, 2015, Mr. Selser owned 137,412 common shares directly, beneficially held 96,542 unvested restricted common shares and 6,600 common shares in trust, and held stock options to purchase 75,000 common shares, all of which currently are vested and exercisable as of March 11, 2015 regardless of trading price. Individuals holding unvested restricted common shares have the right to vote those common shares. Additionally, as of March 11, 2015, Mr. Selser directly owned 3,000 shares of Gastar 8.625% Series A Cumulative Preferred Stock.

(10)

As of March 11, 2015, Mr. Porter owned 1,383,479 common shares directly, beneficially held 567,650 unvested restricted common shares and 150,000 common shares in trust and held stock options to purchase 260,000 common shares, all of which currently are vested and exercisable as of March 11, 2015 regardless of trading price. As of March 11, 2015, Mr. Porter also held 491,371 unvested PBUs. Individuals holding unvested restricted common shares have the right to vote those common shares. Additionally, as of March 11, 2015, Mr. Porter directly owned 7,459 shares of Gastar USA 8.625% Series A Cumulative Preferred Stock and 2,000 shares of Gastar 10.75% Series B Cumulative Preferred Stock.

(11)

As of March 11, 2015, Mr. Gerlich owned 719,228 common shares directly, beneficially held 273,777 unvested restricted common shares and held stock options to purchase 150,000 common shares, all of which currently are vested and exercisable as of March 11, 2015 regardless of trading price. As of March 11, 2015, Mr. Gerlich also held 250,574 unvested PBUs. Individuals holding unvested restricted common shares have the right to vote those common shares. Additionally, as of March 11, 2015, Mr. Gerlich directly owned 2,525 shares of Gastar 8.625% Series A Cumulative Preferred Stock and 2,000 shares of Gastar 10.75% Series B Cumulative Preferred Stock.

(12)

As of March 11, 2015, Mr. McCown owned 306,486 common shares directly, beneficially held 242,834 unvested restricted common shares and held 219,108 unvested PBUs. Individuals holding unvested restricted common shares have the right to vote those common shares. Additionally, as of March 11, 2015, Mr. McCown directly owned 11,655 shares of Gastar 8.625% Series A Cumulative Preferred Stock and 1,535 shares of Gastar 10.75% Series B Cumulative Preferred Stock.

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(a)	Financial Statements and Schedules:

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(b)	Exhibits:

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