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FORM 10-K
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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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38-3531640
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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1331 Lamar Street, Suite 650
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Houston, Texas
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77010
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Name of exchange on which registered
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Common Stock, par value $0.001 per share
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NYSE MKT LLC
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8.625% Series A Cumulative Preferred Stock, par value $0.01 per share
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NYSE MKT LLC
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10.75% Series B Cumulative Preferred Stock, par value $0.01 per share
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NYSE MKT LLC
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Large accelerated filer
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¨
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Accelerated filer
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ý
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Non-accelerated filer
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¨
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Smaller reporting company
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¨
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Page
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PART I
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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PART II
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Item 5.
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Item 6.
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Item 7.
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Page
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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PART III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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PART IV
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Item 15.
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•
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financial position;
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•
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business strategy and budgets;
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•
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capital expenditures;
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•
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drilling of wells, including the scheduling and results of such operations;
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•
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oil, natural gas and natural gas liquids (“NGLs”) reserves;
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•
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timing and amount of future production of oil, condensate, natural gas and NGLs;
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•
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operating costs and other expenses;
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•
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cash flow and liquidity;
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•
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compliance with covenants under our indenture and credit agreements;
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•
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availability of capital;
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•
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prospect development; and
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•
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property acquisitions and sales.
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•
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the supply and demand for oil, condensate, natural gas and NGLs;
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•
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continued low or further declining prices for oil, condensate, natural gas and NGLs;
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•
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worldwide political and economic conditions and conditions in the energy market;
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•
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the extent to which we are able to realize the anticipated benefits from acquired assets;
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•
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our ability to raise capital to fund capital expenditures or repay or refinance debt upon maturity;
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•
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our ability to meet financial covenants under our indenture or credit agreements or the ability to obtain amendments or waivers to effect such compliance;
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•
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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;
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•
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failure of our joint interest partners to fund any or all of their portion of any capital program;
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•
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the ability to find, acquire, market, develop and produce new oil and natural gas properties;
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•
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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;
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•
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strength and financial resources of competitors;
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•
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availability and cost of material and equipment, such as drilling rigs and transportation pipelines;
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•
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availability and cost of processing and transportation;
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changes or advances in technology;
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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;
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•
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potential mechanical failure or under-performance of significant wells or pipeline mishaps;
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environmental risks;
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•
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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;
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•
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effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;
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potential losses from pending or possible future claims, litigation or enforcement actions;
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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;
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•
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the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;
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our ability to find and retain skilled personnel; and
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•
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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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AMI
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Area of mutual interest, an agreed designated geographic area where joint venturers or other industry partners have a right of participation in acquisitions and operations
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Bbl
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Barrel of oil, condensate or NGLs
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Bbl/d
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Barrels of oil, condensate or NGLs per day
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Bcf
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One billion cubic feet of natural gas
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Bcfe
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One billion cubic feet of natural gas equivalent, determined using the ratio of
six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs
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Boe
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One barrel of oil equivalent determined using the ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs
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Boe/d
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Barrels of oil equivalent per day
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Btu
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British thermal unit, typically used in measuring natural gas energy content
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CRP
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Central receipt point
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FASB
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Financial Accounting Standards Board
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GAAP
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Accounting principles generally accepted in the United States of America
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Gross acres
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Refers to acres in which we own a working interest
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Gross wells
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Refers to wells in which we have a working interest
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MBbl
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One thousand barrels of oil, condensate or NGLs
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MBbl/d
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One thousand barrels of oil, condensate or NGLs per day
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MBoe
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One thousand barrels of oil equivalent, calculated on the assumed energy equivalent basis of 6 Mcf of natural gas per MBoe
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MBoe/d
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One thousand barrels of oil equivalent per day
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Mcf
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One thousand cubic feet of natural gas
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Mcf/d
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One thousand cubic feet of natural gas per day
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Mcfe
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One thousand cubic feet of natural gas equivalent, calculated on the assumed energy equivalent basis of 1/6 of a barrel of oil per Mcfe
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MMBtu/d
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One million British thermal units per day
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MMcf
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One million cubic feet of natural gas
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MMcf/d
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One million cubic feet of natural gas per day
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MMcfe
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One million cubic feet of natural gas equivalent, calculated on the assumed energy equivalent basis of 1/6 of a barrel of oil per Mcfe
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MMcfe/d
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One million cubic feet of natural gas equivalent per day, calculated on the assumed energy equivalent basis of 1/6 of a barrel of oil per Mcfe
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Net acres
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Refers to our proportionate interest in acreage resulting from our ownership in gross acreage
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Net wells
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Refers to gross wells multiplied by our working interest in such wells
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NGLs
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Natural gas liquids
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NYMEX
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New York Mercantile Exchange
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PBU
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Performance based unit
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psi
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Pounds per square inch
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U.S.
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United States
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•
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exploitation and development of our Mid-Continent assets in the Hunton Limestone horizontal oil play;
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•
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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;
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•
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additional testing of the Utica Shale;
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•
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active management of our domestic drilling programs; and
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•
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effective management and utilization of technological expertise.
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Cumulative Production Averages
(2)
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Well Name
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Current Working Interest
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Approximate Lateral Length (in feet)
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Peak Production Rates
(1)
(Boe/d)
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Boe/d
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% Oil
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Date of First Production or Status
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Approximate Gross Costs to Drill & Complete ($ millions)
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Jett 1-12H
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47.4%
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3,900
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408
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231
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77%
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February 1, 2014
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$6.3
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Jones 1-21H
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48.4%
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4,200
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449
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157
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55%
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March 2, 2014
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$5.6
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Liebhart 1-31H
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48.8%
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4,400
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146
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71
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75%
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March 18, 2014
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$7.0
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Coronado 1-3H
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43.6%
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4,300
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224
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127
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71%
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March 19, 2014
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$5.3
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Gamebird 1-7H
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48.4%
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4,400
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764
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482
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76%
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April 2, 2014
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$5.5
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Sieber 1-31H
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33.7%
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4,400
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1,013
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438
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63%
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April 13, 2014
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$5.2
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Kodiak 1-29H
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45.3%
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4,300
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1,666
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507
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73%
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May 4, 2014
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$4.5
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Anna Lee 1-30H
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50.0%
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4,400
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220
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128
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73%
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May 20, 2014
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$5.1
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Vaverka 1-20H
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46.6%
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4,400
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315
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170
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67%
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July 10, 2014
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$5.7
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Sasquatch 1-23H
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44.2%
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4,800
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581
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242
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65%
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July 27, 2014
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$5.6
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Jam 1-4H
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33.1%
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4,900
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477
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245
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58%
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August 8, 2014
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$5.8
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Yeti 1-29H
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35.4%
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5,000
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|
1,015
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334
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61%
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August 26, 2014
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$5.3
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Danny Ray 1-30H
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40.3%
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5,000
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|
415
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|
210
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58%
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August 29, 2014
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$5.8
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Cline 1-13H
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54.3%
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5,100
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|
166
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109
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77%
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September 6, 2014
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$5.0
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Michael J 1-18H
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43.7%
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5,000
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740
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458
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66%
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September 29, 2014
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$5.2
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Shimanek 1-2H
|
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48.9%
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5,000
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|
1,829
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887
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64%
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October 9, 2014
|
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$6.0
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Hobbs Ranch 1-19H
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47.0%
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4,400
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|
875
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556
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77%
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October 13, 2014
|
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$5.2
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Snowman 1-19H
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48.9%
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4,900
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|
295
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188
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72%
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October 19, 2014
|
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$5.6
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Breckenridge 1-2H
|
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25.4%
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|
4,800
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|
207
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|
143
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76%
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November 7, 2014
|
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$5.0
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Bear Claw 1-28H
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50.0%
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5,000
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|
395
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|
296
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70%
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November 13,2014
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$6.2
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Joyce 1-10H
(3)
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51.7%
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5,300
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904
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519
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74%
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December 5, 2014
|
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$6.9
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Barry 1-6H
|
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47.8%
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|
5,000
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|
427
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307
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85%
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December 13, 2014
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$6.0
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LB 1-1H
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50.0%
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4,400
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N/A
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N/A
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N/A
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January 23, 2015
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$5.0
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Boss Hogg 1-14H
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42.0%
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4,400
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|
N/A
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68
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60%
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February 21, 2015
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$7.2
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Polar Bear 1-20H
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47.6%
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4,400
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|
N/A
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N/A
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N/A
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Awaiting completion
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$5.0
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Falcon 1-5H
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51.5%
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4,700
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|
N/A
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N/A
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N/A
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Awaiting completion
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$5.0
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The River 1-22H
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28.3%
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4,400
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|
N/A
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N/A
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N/A
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Awaiting completion
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$5.0
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Hubbard 1-23H
(4)
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57.0%
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4,600
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|
N/A
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N/A
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N/A
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Awaiting completion
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$5.0
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Bigfoot 1-9H
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43.0%
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|
4,800
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|
N/A
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|
N/A
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N/A
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Awaiting completion
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|
$5.0
|
Bo 1-23H
|
|
50.0%
|
|
4,900
|
|
N/A
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|
N/A
|
|
N/A
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Awaiting completion
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|
$5.0
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Dorothy 1-12H
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|
31.0%
|
|
5,000
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|
N/A
|
|
N/A
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|
N/A
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Awaiting completion
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|
$5.0
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Unruh 1-34H
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50.0%
|
|
4,900
|
|
N/A
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|
N/A
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N/A
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Awaiting completion
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$5.0
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(1)
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Represents highest daily gross Boe rate.
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(2)
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Represents gross average production for actual producing days through February 28, 2015.
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(3)
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After payout working interest is 45.0%.
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(4)
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After payout working interest is 49.9%.
|
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Cumulative Production Averages
(2)
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Well Name
|
|
Current Working Interest
|
|
Approximate Lateral Length (in feet)
|
|
Peak Production Rates
(1)
(BOE/d)
|
|
BOE/d
|
|
% Oil
|
|
Date of First Production or Status
|
|
Approximate Gross Costs to Drill & Complete ($ millions)
|
|
|
|
|
|
|
|
|
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Rosemary 1-3H
|
|
15.6%
|
|
3,400
|
|
476
|
|
220
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|
55%
|
|
February 22, 2014
|
|
$5.5
|
Grizzly 1-4H
|
|
8.8%
|
|
3,600
|
|
387
|
|
173
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|
55%
|
|
May 1, 2014
|
|
$4.8
|
Niemyer 1-2H
|
|
17.7%
|
|
5,000
|
|
422
|
|
248
|
|
56%
|
|
June 24, 2014
|
|
$5.7
|
Wolf 1-9H
|
|
16.1%
|
|
3,600
|
|
391
|
|
279
|
|
62%
|
|
January 3, 2015
|
|
$5.5
|
(1)
|
Represents highest daily gross Boe rate.
|
(2)
|
Represents gross average production for actual producing days through February 28, 2015.
|
|
|
|
|
|
|
|
|
Cumulative Production Averages
(2)
|
|
|
|
|
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Well Name
|
|
Current Working Interest
|
|
Approximate Lateral Length (in feet)
|
|
Peak Production Rates
(1)
(BOE/d)
|
|
BOE/d
|
|
% Oil
|
|
Date of First Production or Status
|
|
Approximate Gross Costs to Drill & Complete ($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taborek 22-1H
|
|
87.4%
|
|
3,000
|
|
270
|
|
127
|
|
37%
|
|
March 6, 2014
|
|
$10.0
|
Easton 22-1H
|
|
98.3%
|
|
4,900
|
|
673
|
|
318
|
|
90%
|
|
July 30, 2014
|
|
$7.8
|
Easton 22-2H
|
|
98.3%
|
|
6,500
|
|
855
|
|
287
|
|
92%
|
|
August 5, 2014
|
|
$3.9
|
Horseshoe 3-1H
|
|
99.3%
|
|
5,100
|
|
380
|
|
185
|
|
35%
|
|
September 16, 2014
|
|
$7.0
|
Deer Draw 21-4H
|
|
98.3%
|
|
5,900
|
|
495
|
|
413
|
|
81%
|
|
November 7, 2014
|
|
$4.9
|
Deer Draw 21-5H
|
|
98.3%
|
|
4,900
|
|
344
|
|
234
|
|
85%
|
|
November 9, 2014
|
|
$5.0
|
Warsaw 33-2H
|
|
98.3%
|
|
4,900
|
|
N/A
|
|
481
|
|
80%
|
|
February 12, 2015
|
|
$3.5
|
Warsaw 33-3H
|
|
98.3%
|
|
5,800
|
|
648
|
|
277
|
|
71%
|
|
February 13, 2015
|
|
$5.9
|
Warsaw 33-1
(3)
|
|
98.3%
|
|
N/A
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Awaiting completion
|
|
$3.5
|
Easton 22-3H
|
|
98.3%
|
|
6,500
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Drilling
|
|
$5.0
|
Blair Farms 31-1H
|
|
98.3%
|
|
6,500
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Drilling
|
|
$3.2
|
(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.
|
|
For the Years Ended December 31,
|
||||||||||
Mid-Continent
|
2014
|
|
2013
|
|
2012
|
||||||
Production:
|
|
|
|
|
|
||||||
Oil and condensate (MBbl)
|
792
|
|
|
189
|
|
|
2
|
|
|||
Natural gas (MMcf)
|
2,822
|
|
|
1,095
|
|
|
1
|
|
|||
NGLs (MBbl)
|
332
|
|
|
23
|
|
|
—
|
|
|||
Total Production (MBoe)
|
1,594
|
|
|
395
|
|
|
2
|
|
|||
Oil and condensate (MBbl/d)
|
2.2
|
|
|
0.5
|
|
|
—
|
|
|||
Natural gas (MMcf/d)
|
7.7
|
|
|
3.0
|
|
|
—
|
|
|||
NGLs (MBbl/d)
|
0.9
|
|
|
0.1
|
|
|
—
|
|
|||
Total daily production (MBoe/d)
|
4.4
|
|
|
1.1
|
|
|
0.01
|
|
|||
Average sales price per unit
(1)
:
|
|
|
|
|
|
||||||
Oil and condensate (per Bbl)
|
$
|
88.84
|
|
|
$
|
94.80
|
|
|
$
|
85.22
|
|
Natural gas (per Mcf)
|
$
|
4.24
|
|
|
$
|
4.75
|
|
|
$
|
3.47
|
|
NGLs (per Bbl)
|
$
|
31.79
|
|
|
$
|
33.06
|
|
|
$
|
36.15
|
|
Average sales price per Boe
(1)
|
$
|
58.27
|
|
|
$
|
60.53
|
|
|
$
|
75.58
|
|
|
|
|
|
|
|
||||||
Selected operating expenses (in thousands):
|
|
|
|
|
|
||||||
Production taxes
|
$
|
2,940
|
|
|
$
|
820
|
|
|
$
|
2
|
|
Lease operating expenses
|
$
|
15,112
|
|
|
$
|
4,019
|
|
|
$
|
33
|
|
Transportation, treating and gathering
|
$
|
40
|
|
|
$
|
3
|
|
|
$
|
—
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
||||||
Production taxes
|
$
|
1.84
|
|
|
$
|
2.08
|
|
|
$
|
1.22
|
|
Lease operating expenses
|
$
|
9.48
|
|
|
$
|
10.17
|
|
|
$
|
18.79
|
|
Transportation, treating and gathering
|
$
|
0.02
|
|
|
$
|
0.01
|
|
|
$
|
—
|
|
Production costs
(2)
|
$
|
9.50
|
|
|
$
|
10.17
|
|
|
$
|
18.79
|
|
(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.
|
Pad
|
|
Gross Well Count
|
|
Net Well Count
|
|
Working Interest
|
|
Estimated Net Revenue Interest
|
|
Average Lateral Length (in feet) (1)
|
|
Status
|
|
Estimated Production Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goudy
(2)
|
|
3.0
|
|
1.5
|
|
50.0%
|
|
40.0%
|
|
6,100
|
|
Awaiting completion
|
|
March 2015
|
Hoyt
(3)
|
|
2.0
|
|
1.0
|
|
50.0%
|
|
42.7%
|
|
5,000
|
|
Awaiting completion
|
|
April 2015
|
Blake
(4)
|
|
2.0
|
|
1.0
|
|
50.0%
|
|
41.9%
|
|
5,700
|
|
Awaiting completion
|
|
May 2015
|
|
|
7.0
|
|
3.5
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
For the Years Ended December 31,
|
||||||||||
Marcellus Shale
|
2014
|
|
2013
|
|
2012
|
||||||
Production:
|
|
|
|
|
|
||||||
Oil and condensate (MBbl)
|
182
|
|
|
315
|
|
|
160
|
|
|||
Natural gas (MMcf)
|
8,050
|
|
|
9,594
|
|
|
5,477
|
|
|||
NGLs (MBbl)
|
469
|
|
|
471
|
|
|
270
|
|
|||
Total production (MBoe)
|
1,993
|
|
|
2,385
|
|
|
1,343
|
|
|||
Oil and condensate (MBbl/d)
|
0.5
|
|
|
0.9
|
|
|
0.4
|
|
|||
Natural gas (MMcf/d)
|
22.1
|
|
|
26.3
|
|
|
15.0
|
|
|||
NGLs (MBbl/d)
|
1.3
|
|
|
1.3
|
|
|
0.7
|
|
|||
Total daily production (MBoe/d)
|
5.5
|
|
|
6.5
|
|
|
3.7
|
|
|||
Average sales price per unit
(1)(2)
:
|
|
|
|
|
|
||||||
Oil and condensate (per Bbl)
|
$
|
68.21
|
|
|
$
|
55.61
|
|
|
$
|
62.40
|
|
Natural gas (per Mcf)
|
$
|
4.28
|
|
|
$
|
2.86
|
|
|
$
|
2.33
|
|
NGLs (per Bbl)
|
$
|
23.11
|
|
|
$
|
31.52
|
|
|
$
|
28.22
|
|
Average sales price per Boe
(1)(2)
|
$
|
28.97
|
|
|
$
|
25.08
|
|
|
$
|
22.62
|
|
Selected operating expenses (in thousands):
|
|
|
|
|
|
||||||
Production taxes
(3)
|
$
|
3,685
|
|
|
$
|
3,805
|
|
|
$
|
2,138
|
|
Lease operating expenses
(3)
|
$
|
4,187
|
|
|
$
|
3,181
|
|
|
$
|
2,070
|
|
Transportation, treating and gathering
(3)
|
$
|
3,552
|
|
|
$
|
1,176
|
|
|
$
|
1,090
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
||||||
Production taxes
(3)
|
$
|
1.85
|
|
|
$
|
1.60
|
|
|
$
|
1.59
|
|
Lease operating expenses
(3)
|
$
|
2.10
|
|
|
$
|
1.33
|
|
|
$
|
1.54
|
|
Transportation, treating and gathering
(3)
|
$
|
1.78
|
|
|
$
|
0.49
|
|
|
$
|
0.81
|
|
Production costs
(4)
|
$
|
3.50
|
|
|
$
|
1.76
|
|
|
$
|
2.29
|
|
(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:
|
|
For the Year Ended December 31, 2014
|
||
Marcellus Shale
|
|
||
Average sales price per unit:
|
|
||
Oil and condensate (per Bbl)
|
$
|
50.96
|
|
Natural gas (per Mcf)
|
$
|
3.27
|
|
NGLs (per Bbl)
|
$
|
24.55
|
|
Average sales price per Boe
|
$
|
23.65
|
|
(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:
|
|
For the Year Ended December 31, 2014
|
||
Marcellus Shale
|
|
||
Selected operating expenses per Boe:
|
|
||
Production taxes
|
$
|
1.56
|
|
Lease operating expenses
|
$
|
2.19
|
|
Transportation, treating and gathering
|
$
|
0.99
|
|
(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:
|
|
For the Year Ended December 31, 2014
|
||
Marcellus Shale
|
|
||
Selected operating expenses per Boe:
|
|
||
Production costs
|
$
|
2.80
|
|
|
For the Year Ended December 31,
|
||
Utica Shale
|
2014
|
||
Production:
|
|
||
Natural gas (MMcf)
|
725
|
|
|
Total production (MBoe)
|
121
|
|
|
Natural gas (MMcf/d)
|
2.0
|
|
|
Total daily production (MBoe/d)
|
0.3
|
|
|
Average sales price per unit
(1)
:
|
|
||
Natural gas (per Mcf)
|
$
|
1.68
|
|
Average sales price per Boe
(1)
|
$
|
10.10
|
|
Selected operating expenses (in thousands):
|
|
||
Production taxes
|
$
|
109
|
|
Lease operating expenses
|
$
|
24
|
|
Transportation, treating and gathering
|
$
|
87
|
|
Selected operating expenses per Boe:
|
|
||
Production taxes
|
$
|
0.90
|
|
Lease operating expenses
|
$
|
0.20
|
|
Transportation, treating and gathering
|
$
|
0.72
|
|
Production costs
(2)
|
$
|
0.92
|
|
(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.
|
|
|
For the Years Ended December 31,
|
|||||||
|
|
2014
|
|
2013
|
|
2012
|
|||
SEI
|
|
50
|
%
|
|
56
|
%
|
|
47
|
%
|
Sunoco
|
|
37
|
%
|
|
16
|
%
|
|
—
|
%
|
Clearfield Appalachian
|
|
—
|
%
|
|
8
|
%
|
|
14
|
%
|
ETC
|
|
—
|
%
|
|
8
|
%
|
|
24
|
%
|
•
|
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.
|
•
|
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;
|
•
|
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.
|
•
|
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;
|
•
|
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.
|
•
|
Timing and amount of capital expenditures;
|
•
|
The operator’s expertise and financial resources;
|
•
|
Approval of other participants in drilling wells; and
|
•
|
Selection of technology.
|
•
|
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.
|
•
|
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.
|
•
|
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;
|
•
|
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.
|
•
|
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.
|
|
For the Years Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Production:
|
|
|
|
|
|
||||||
Oil and condensate (MBbl)
|
975
|
|
|
515
|
|
|
177
|
|
|||
Natural gas (MMcf)
|
11,598
|
|
|
13,366
|
|
|
10,564
|
|
|||
NGLs (MBbl)
|
801
|
|
|
494
|
|
|
270
|
|
|||
Total production (MBoe)
|
3,708
|
|
|
3,236
|
|
|
2,208
|
|
|||
Daily Production:
|
|
|
|
|
|
||||||
Oil and condensate (MBbl/d)
|
2.7
|
|
|
1.4
|
|
|
0.5
|
|
|||
Natural gas (MMcf/d)
|
31.8
|
|
|
36.6
|
|
|
28.9
|
|
|||
NGLs (MBbl/d)
|
2.2
|
|
|
1.4
|
|
|
0.7
|
|
|||
Total daily production (MBoe/d)
|
10.2
|
|
|
8.9
|
|
|
6.0
|
|
|||
Average sales price per unit
(1)
:
|
|
|
|
|
|
||||||
Oil and condensate per Bbl, excluding impact of hedging activities
|
$
|
84.98
|
|
|
$
|
70.91
|
|
|
$
|
65.45
|
|
Oil and condensate per Bbl, including impact of hedging activities
(2)
|
$
|
83.86
|
|
|
$
|
71.04
|
|
|
$
|
70.01
|
|
Natural gas per Mcf, excluding impact of hedging activities
|
$
|
4.11
|
|
|
$
|
3.02
|
|
|
$
|
2.21
|
|
Natural gas per Mcf, including impact of hedging activities
(2)
|
$
|
3.84
|
|
|
$
|
3.43
|
|
|
$
|
3.20
|
|
NGLs per Bbl, excluding impact of hedging activities
|
$
|
26.71
|
|
|
$
|
31.59
|
|
|
$
|
28.22
|
|
NGLs per Bbl, including impact of hedging activities
(2)
|
$
|
26.53
|
|
|
$
|
31.13
|
|
|
$
|
34.40
|
|
Average sales price per Boe, excluding impact of hedging activities
|
$
|
40.95
|
|
|
$
|
28.58
|
|
|
$
|
19.26
|
|
Average sales price per Boe, including impact of hedging activities
(2)
|
$
|
39.78
|
|
|
$
|
30.20
|
|
|
$
|
25.14
|
|
|
|
|
|
|
|
||||||
Selected operating expenses (in thousands):
|
|
|
|
|
|
||||||
Production taxes
(3)
|
$
|
6,733
|
|
|
$
|
4,651
|
|
|
$
|
2,269
|
|
Lease operating expenses
(3)
|
$
|
19,323
|
|
|
$
|
9,456
|
|
|
$
|
6,174
|
|
Transportation, treating and gathering
(3)
|
$
|
3,679
|
|
|
$
|
4,006
|
|
|
$
|
4,965
|
|
Depreciation, depletion and amortization
|
$
|
46,180
|
|
|
$
|
32,449
|
|
|
$
|
25,424
|
|
Impairment of natural gas and oil properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
150,787
|
|
General and administrative expense
|
$
|
16,485
|
|
|
$
|
16,961
|
|
|
$
|
12,211
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
||||||
Production taxes
(3)
|
$
|
1.82
|
|
|
$
|
1.44
|
|
|
$
|
1.03
|
|
Lease operating expenses
(3)
|
$
|
5.21
|
|
|
$
|
2.92
|
|
|
$
|
2.80
|
|
Transportation, treating and gathering
(3)
|
$
|
0.99
|
|
|
$
|
1.24
|
|
|
$
|
2.25
|
|
Depreciation, depletion and amortization
|
$
|
12.45
|
|
|
$
|
10.02
|
|
|
$
|
11.52
|
|
General and administrative expense
(4)
|
$
|
4.45
|
|
|
$
|
5.24
|
|
|
$
|
5.53
|
|
Production costs
(5)
|
$
|
6.00
|
|
|
$
|
4.05
|
|
|
$
|
4.81
|
|
|
For the Year Ended December 31, 2014
|
||
Average sales price per unit:
|
|
||
Oil and condensate per Bbl, excluding impact of hedging activities
|
$
|
81.75
|
|
Oil and condensate per Bbl, including impact of hedging activities
(2)
|
$
|
80.63
|
|
Natural gas per Mcf, excluding impact of hedging activities
|
$
|
3.41
|
|
Natural gas per Mcf, including impact of hedging activities
(2)
|
$
|
3.14
|
|
NGLs per Bbl, excluding impact of hedging activities
|
$
|
27.55
|
|
NGLs per Bbl, including impact of hedging activities
(2)
|
$
|
27.37
|
|
Average sales price per Boe, excluding impact of hedging activities
|
$
|
38.09
|
|
Average sales price per Boe, including impact of hedging activities
(2)
|
$
|
36.92
|
|
(2)
|
The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented.
|
|
For the Year Ended December 31, 2014
|
||
Selected operating expenses per Boe:
|
|
||
Production taxes
|
$
|
1.66
|
|
Lease operating expenses
|
$
|
5.26
|
|
Transportation, treating and gathering
|
$
|
0.56
|
|
(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.
|
|
For the Year Ended December 31, 2014
|
||
Selected operating expenses per Boe:
|
|
||
Production costs
|
$
|
5.62
|
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
30.0
|
|
|
14.9
|
|
|
11.0
|
|
|
5.7
|
|
|
6.0
|
|
|
1.7
|
|
Non-productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
30.0
|
|
|
14.9
|
|
|
11.0
|
|
|
5.7
|
|
|
6.0
|
|
|
1.7
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
11.0
|
|
|
6.0
|
|
|
17.0
|
|
|
8.5
|
|
|
31.0
|
|
|
14.2
|
|
Non-productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
11.0
|
|
|
6.0
|
|
|
17.0
|
|
|
8.5
|
|
|
31.0
|
|
|
14.2
|
|
|
Undeveloped Acreage
|
|
Developed Acreage
|
||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Appalachian Basin, West Virginia and Pennsylvania
(1)
|
|
|
|
|
|
|
|
||||
Marcellus West
(2)(3)
|
21,031
|
|
|
8,718
|
|
|
11,030
|
|
|
4,746
|
|
Marcellus East
|
38,869
|
|
|
34,870
|
|
|
3,185
|
|
|
2,936
|
|
Total Marcellus Shale area
|
59,900
|
|
|
43,588
|
|
|
14,215
|
|
|
7,682
|
|
Mid-Continent
|
156,613
|
|
|
74,397
|
|
|
69,159
|
|
|
43,439
|
|
Total
|
216,513
|
|
|
117,985
|
|
|
83,374
|
|
|
51,121
|
|
(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.
|
As of December 31,
|
|
Appalachian Basin
|
|
|
|
Total Expiring Gross Acres
|
|
% of Total Undeveloped
|
|||||||
West
|
|
East
|
Mid-Continent
|
Gross Acres
|
|||||||||||
2015
|
|
3,354
|
|
|
9,635
|
|
|
47,687
|
|
|
60,676
|
|
|
28
|
%
|
2016
|
|
2,981
|
|
|
13,315
|
|
|
80,014
|
|
|
96,310
|
|
|
44
|
%
|
2017
|
|
5,131
|
|
|
52
|
|
|
28,628
|
|
|
33,811
|
|
|
16
|
%
|
2018
|
|
5,813
|
|
|
7
|
|
|
242
|
|
|
6,062
|
|
|
3
|
%
|
2019
and thereafter
|
|
2,466
|
|
|
—
|
|
|
42
|
|
|
2,508
|
|
|
1
|
%
|
As of December 31,
|
|
Appalachian Basin
|
|
|
|
Total Expiring Net Acres
|
|
% of Total Undeveloped
|
|||||||
West
|
|
East
|
Mid-Continent
|
Net Acres
|
|||||||||||
2015
|
|
1,375
|
|
|
9,385
|
|
|
21,166
|
|
|
31,926
|
|
|
27
|
%
|
2016
|
|
1,517
|
|
|
10,945
|
|
|
35,581
|
|
|
48,043
|
|
|
41
|
%
|
2017
|
|
1,823
|
|
|
52
|
|
|
17,370
|
|
|
19,245
|
|
|
16
|
%
|
2018
|
|
2,092
|
|
|
7
|
|
|
217
|
|
|
2,316
|
|
|
2
|
%
|
2019
and thereafter
|
|
1,234
|
|
|
—
|
|
|
63
|
|
|
1,297
|
|
|
1
|
%
|
|
Productive Wells
|
||||||||||||||||
|
Natural Gas
|
|
Oil
|
|
Total Wells
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Appalachian Basin, West Virginia and Pennsylvania
|
110.0
|
|
|
53.1
|
|
|
—
|
|
|
—
|
|
|
110.0
|
|
|
53.1
|
|
Mid-Continent, Oklahoma
|
177.0
|
|
|
84.0
|
|
|
58.0
|
|
|
44.3
|
|
|
235.0
|
|
|
128.3
|
|
Total
|
287.0
|
|
|
137.1
|
|
|
58.0
|
|
|
44.3
|
|
|
345.0
|
|
|
181.4
|
|
|
Total Proved Reserves
|
||||||
|
Producing
|
|
Non-producing
|
|
Undeveloped
|
|
Total
|
Natural gas (MMcf)
|
114,101
|
|
463
|
|
172,441
|
|
287,005
|
NGLs (MBbls)
|
10,706
|
|
21
|
|
14,866
|
|
25,593
|
Oil and condensate (MBbls)
|
6,967
|
|
1
|
|
21,668
|
|
28,636
|
Total proved reserves (MBoe)
|
36,690
|
|
99
|
|
65,274
|
|
102,063
|
PV-10 (in thousands)
(1)
|
$444,765
|
|
$(483)
|
|
$544,404
|
|
$988,686
|
Standardized measure of discounted future net cash flows
(1)
|
|
|
|
|
|
|
$816,739
|
(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
.
|
|
Natural
Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Oil and Condensate
(MBbls)
|
|
MBoe
|
|
% Proved
Developed
|
|
PV-10
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|||||||||||
Appalachian Basin, West Virginia and Pennsylvania
|
244,141
|
|
|
19,309
|
|
|
8,067
|
|
|
68,066
|
|
|
38
|
%
|
|
$
|
353,507
|
|
|
|
||
Mid-Continent
|
42,864
|
|
|
6,284
|
|
|
20,569
|
|
|
33,997
|
|
|
33
|
%
|
|
635,179
|
|
|
|
|||
Total
|
287,005
|
|
|
25,593
|
|
|
28,636
|
|
|
102,063
|
|
|
36
|
%
|
|
$
|
988,686
|
|
|
$
|
816,739
|
|
(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.
|
|
Natural
Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Oil and Condensate
(MBbls)
|
|
MBoe
|
||||
PUDs as of December 31, 2013
|
66,516
|
|
|
3,773
|
|
|
8,884
|
|
|
23,743
|
|
Extensions and discoveries
|
115,042
|
|
|
8,201
|
|
|
10,618
|
|
|
37,993
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
PUDs converted to proved developed
|
(9,450
|
)
|
|
(532
|
)
|
|
(181
|
)
|
|
(2,288
|
)
|
Revisions of previous estimates
|
333
|
|
|
3,424
|
|
|
2,347
|
|
|
5,826
|
|
PUDs as of December 31, 2014
|
172,441
|
|
|
14,866
|
|
|
21,668
|
|
|
65,274
|
|
|
NYSE MKT LLC
|
||||||
|
High
|
|
Low
|
||||
2014:
|
|
|
|
||||
Fourth quarter
|
$
|
6.09
|
|
|
$
|
2.11
|
|
Third quarter
|
$
|
8.75
|
|
|
$
|
5.85
|
|
Second quarter
|
$
|
9.10
|
|
|
$
|
5.72
|
|
First quarter
|
$
|
7.13
|
|
|
$
|
5.05
|
|
2013:
|
|
|
|
||||
Fourth quarter
|
$
|
6.92
|
|
|
$
|
3.94
|
|
Third quarter
|
$
|
4.52
|
|
|
$
|
2.64
|
|
Second quarter
|
$
|
3.07
|
|
|
$
|
1.95
|
|
First quarter
|
$
|
1.79
|
|
|
$
|
1.05
|
|
Period
|
|
(a) Total Number of Shares Purchased
|
|
(b) Average Price Paid per Share
|
|
(c) Total Number of Shares Purchased as Part of Publicly Announced Plans
|
|
(d) Maximum Number of Shares that May Yet be Purchased Under the Plan
|
|||
January 1, 2014 - January 31, 2014
|
|
549,571
|
|
|
$
|
5.80
|
|
|
—
|
|
n/a
|
March 1, 2014 - March 31, 2014
|
|
88,090
|
|
|
$
|
5.28
|
|
|
—
|
|
n/a
|
June 1, 2014 - June 30, 2014
|
|
410
|
|
|
$
|
7.32
|
|
|
—
|
|
n/a
|
August 1, 2014 - August 31, 2014
|
|
7,967
|
|
|
$
|
6.63
|
|
|
—
|
|
n/a
|
November 1, 2014 - November 30, 2014
|
|
204,096
|
|
|
$
|
4.18
|
|
|
—
|
|
n/a
|
|
As of and for the Years Ended December 31,
|
||||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||||||
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
171,418
|
|
|
$
|
87,755
|
|
|
$
|
49,940
|
|
|
$
|
40,235
|
|
|
$
|
42,768
|
|
Income (loss) from operations
|
$
|
78,512
|
|
|
$
|
18,764
|
|
|
$
|
(153,528
|
)
|
|
$
|
(631
|
)
|
|
$
|
(15,019
|
)
|
Net income (loss) attributable to Common Stockholders
|
$
|
36,529
|
|
|
$
|
39,964
|
|
|
$
|
(160,868
|
)
|
|
$
|
(1,764
|
)
|
|
$
|
(12,460
|
)
|
Net income (loss) attributable to Common Stockholders per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
0.58
|
|
|
$
|
0.66
|
|
|
$
|
(2.53
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.25
|
)
|
Diluted
|
$
|
0.55
|
|
|
$
|
0.63
|
|
|
$
|
(2.53
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.25
|
)
|
Weighted average shares of common stock outstanding
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
63,271
|
|
|
60,220
|
|
|
63,538
|
|
|
63,004
|
|
|
49,814
|
|
|||||
Diluted
|
66,493
|
|
|
63,618
|
|
|
63,538
|
|
|
63,004
|
|
|
49,814
|
|
|||||
Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Property, plant and equipment, net
|
$
|
692,300
|
|
|
$
|
517,513
|
|
|
$
|
256,251
|
|
|
$
|
285,740
|
|
|
$
|
215,115
|
|
Total assets
|
$
|
775,794
|
|
|
$
|
589,935
|
|
|
$
|
290,068
|
|
|
$
|
334,503
|
|
|
$
|
247,352
|
|
Long-term liabilities
|
$
|
370,480
|
|
|
$
|
325,802
|
|
|
$
|
106,020
|
|
|
$
|
39,438
|
|
|
$
|
14,295
|
|
Total stockholders’ equity
|
$
|
350,286
|
|
|
$
|
210,029
|
|
|
$
|
126,536
|
|
|
$
|
235,194
|
|
|
$
|
207,391
|
|
•
|
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.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In thousands, except per unit
amounts)
|
||||||||||
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
|
|
|||
Gain (loss) on commodity derivatives contracts
|
19,569
|
|
|
(4,752
|
)
|
|
7,422
|
|
|||
Total revenues
|
$
|
171,418
|
|
|
$
|
87,755
|
|
|
$
|
49,940
|
|
|
|
|
|
|
|
||||||
Production:
|
|
|
|
|
|
||||||
Oil and condensate (MBbl)
|
975
|
|
|
515
|
|
|
177
|
|
|||
Natural gas (MMcf)
|
11,598
|
|
|
13,366
|
|
|
10,564
|
|
|||
NGLs (MBbl)
|
801
|
|
|
494
|
|
|
270
|
|
|||
Total production (MBoe)
|
3,708
|
|
|
3,236
|
|
|
2,208
|
|
|||
|
|
|
|
|
|
||||||
Oil and condensate (MBbl/d)
|
2.7
|
|
|
1.4
|
|
|
0.5
|
|
|||
Natural gas (MMcf/d)
|
31.8
|
|
|
36.6
|
|
|
28.9
|
|
|||
NGLs (MBbl/d)
|
2.2
|
|
|
1.4
|
|
|
0.7
|
|
|||
Total daily production (MBoe/d)
|
10.2
|
|
|
8.9
|
|
|
6.0
|
|
|||
|
|
|
|
|
|
||||||
Average sales price per unit
(1)
:
|
|
|
|
|
|
||||||
Oil and condensate per Bbl, excluding impact of hedging activities
|
$
|
84.98
|
|
|
$
|
70.91
|
|
|
$
|
65.45
|
|
Oil and condensate per Bbl, including impact of hedging activities
(2)
|
$
|
83.86
|
|
|
$
|
71.04
|
|
|
$
|
70.01
|
|
Natural gas per Mcf, excluding impact of hedging activities
|
$
|
4.11
|
|
|
$
|
3.02
|
|
|
$
|
2.21
|
|
Natural gas per Mcf, including impact of hedging activities
(2)
|
$
|
3.84
|
|
|
$
|
3.43
|
|
|
$
|
3.20
|
|
NGLs per Bbl, excluding impact of hedging activities
|
$
|
26.71
|
|
|
$
|
31.59
|
|
|
$
|
28.22
|
|
NGLs per Bbl, including impact of hedging activities
(2)
|
$
|
26.53
|
|
|
$
|
31.13
|
|
|
$
|
34.40
|
|
Average sales price per Boe, excluding impact of hedging activities
|
$
|
40.95
|
|
|
$
|
28.58
|
|
|
$
|
19.26
|
|
Average sales price per Boe, including impact of hedging activities
(2)
|
$
|
39.78
|
|
|
$
|
30.20
|
|
|
$
|
25.14
|
|
|
|
|
|
|
|
||||||
Selected operating expenses (in thousands):
|
|
|
|
|
|
||||||
Production taxes
(3)
|
$
|
6,733
|
|
|
$
|
4,651
|
|
|
$
|
2,269
|
|
Lease operating expenses
(3)
|
$
|
19,323
|
|
|
$
|
9,456
|
|
|
$
|
6,174
|
|
Transportation, treating and gathering
(3)
|
$
|
3,679
|
|
|
$
|
4,006
|
|
|
$
|
4,965
|
|
Depreciation, depletion and amortization
|
$
|
46,180
|
|
|
$
|
32,449
|
|
|
$
|
25,424
|
|
Impairment of natural gas and oil properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
150,787
|
|
General and administrative expenses
(4)
|
$
|
16,485
|
|
|
$
|
16,961
|
|
|
$
|
12,211
|
|
|
|
|
|
|
|
||||||
Selected operating expenses per Boe:
|
|
|
|
|
|
||||||
Production taxes
(3)
|
$
|
1.82
|
|
|
$
|
1.44
|
|
|
$
|
1.03
|
|
Lease operating expenses
(3)
|
$
|
5.21
|
|
|
$
|
2.92
|
|
|
$
|
2.80
|
|
Transportation, treating and gathering
(3)
|
$
|
0.99
|
|
|
$
|
1.24
|
|
|
$
|
2.25
|
|
Depreciation, depletion and amortization
|
$
|
12.45
|
|
|
$
|
10.02
|
|
|
$
|
11.52
|
|
General and administrative expenses
(4)
|
$
|
4.45
|
|
|
$
|
5.24
|
|
|
$
|
5.53
|
|
Production costs
(5)
|
$
|
6.00
|
|
|
$
|
4.05
|
|
|
$
|
4.81
|
|
|
For the Year Ended December 31, 2014
|
||
Average sales price per unit:
|
|
||
Oil and condensate per Bbl, excluding impact of hedging activities
|
$
|
81.75
|
|
Oil and condensate per Bbl, including impact of hedging activities
(2)
|
$
|
80.63
|
|
Natural gas per Mcf, excluding impact of hedging activities
|
$
|
3.41
|
|
Natural gas per Mcf, including impact of hedging activities
(2)
|
$
|
3.14
|
|
NGLs per Bbl, excluding impact of hedging activities
|
$
|
27.55
|
|
NGLs per Bbl, including impact of hedging activities
(2)
|
$
|
27.37
|
|
Average sales price per Boe, excluding impact of hedging activities
|
$
|
38.09
|
|
Average sales price per Boe, including impact of hedging activities
(2)
|
$
|
36.92
|
|
(2)
|
The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented.
|
|
For the Year Ended December 31, 2014
|
||
Selected operating expenses per Boe:
|
|
||
Production taxes
|
$
|
1.66
|
|
Lease operating expenses
|
$
|
5.26
|
|
Transportation, treating and gathering
|
$
|
0.56
|
|
(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.
|
|
For the Year Ended December 31, 2014
|
||
Selected operating expenses per Boe:
|
|
||
Production costs
|
$
|
5.62
|
|
|
Lease Operating Expense
For the Year Ended
December 31, 2014
|
|
Lease Operating Expense
For the Year Ended
December 31, 2013
|
|
% Change
of $ per Boe
|
|||||||||||||
|
(in thousands)
|
|
($ per Boe)
|
|
(in thousands)
|
|
($ per Boe)
|
|
||||||||||
Mid-Continent
|
$
|
15,112
|
|
|
$
|
9.48
|
|
|
$
|
4,018
|
|
|
$
|
10.17
|
|
|
(7
|
)%
|
Appalachian Basin
|
4,211
|
|
|
$
|
1.99
|
|
|
3,181
|
|
|
$
|
1.33
|
|
|
50
|
%
|
||
East Texas and other
|
—
|
|
|
$
|
—
|
|
|
2,257
|
|
|
$
|
4.95
|
|
|
(100
|
)%
|
||
Total
|
$
|
19,323
|
|
|
$
|
5.21
|
|
|
$
|
9,456
|
|
|
$
|
2.92
|
|
|
78
|
%
|
|
Lease Operating Expense
For the Year Ended
December 31, 2013
|
|
Lease Operating Expense
For the Year Ended
December 31, 2012
|
|
% Change
of $ per Mcfe and Boe
|
|||||||||||||
|
(in thousands)
|
|
($ per Boe)
|
|
(in thousands)
|
|
($ per Boe)
|
|
||||||||||
Mid-Continent
|
$
|
4,018
|
|
|
$
|
10.17
|
|
|
$
|
33
|
|
|
$
|
18.79
|
|
|
(46
|
)%
|
Appalachia
|
3,181
|
|
|
$
|
1.33
|
|
|
2,071
|
|
|
$
|
1.54
|
|
|
(13
|
)%
|
||
East Texas
|
2,253
|
|
|
$
|
4.97
|
|
|
3,624
|
|
|
$
|
4.35
|
|
|
14
|
%
|
||
Other
|
4
|
|
|
$
|
1.57
|
|
|
446
|
|
|
$
|
15.43
|
|
|
(90
|
)%
|
||
Total
|
$
|
9,456
|
|
|
$
|
2.92
|
|
|
$
|
6,174
|
|
|
$
|
2.80
|
|
|
4
|
%
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
|
Floor
(Long)
|
|
Short
Put
|
|
Ceiling
(Short)
|
||||||||||
|
|
|
|
(in MMBtu's)
|
|
|
|
|
|
|
|
|
||||||||||||
2015
(1)
|
|
Protective spread
|
|
10,000
|
|
|
900,000
|
|
|
$
|
4.46
|
|
|
$
|
—
|
|
|
$
|
3.70
|
|
|
$
|
—
|
|
2015
(1)
|
|
Call spread
|
|
10,000
|
|
|
900,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5.00
|
|
2015
|
|
Fixed price swap
|
|
400
|
|
|
146,000
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Fixed price swap
|
|
2,500
|
|
|
912,500
|
|
|
$
|
4.06
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Protective spread
|
|
2,600
|
|
|
949,000
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
2015
(1)
|
|
Producer three-way collar
|
|
3,750
|
|
|
337,500
|
|
|
$
|
—
|
|
|
$
|
4.60
|
|
|
$
|
3.50
|
|
|
$
|
5.34
|
|
2015
(1)
|
|
Producer three-way collar
|
|
2,500
|
|
|
337,500
|
|
|
$
|
—
|
|
|
$
|
4.40
|
|
|
$
|
3.65
|
|
|
$
|
5.00
|
|
2015
|
|
Producer three-way collar
|
|
2,000
|
|
|
760,000
|
|
|
$
|
—
|
|
|
$
|
4.00
|
|
|
$
|
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
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
2015
(3)
|
|
Producer three-way collar
|
|
2,500
|
|
|
687,500
|
|
|
$
|
—
|
|
|
$
|
3.70
|
|
|
$
|
3.00
|
|
|
$
|
4.09
|
|
2015
(3)
|
|
Producer three-way collar
|
|
5,000
|
|
|
1,375,000
|
|
|
$
|
—
|
|
|
$
|
3.77
|
|
|
$
|
3.00
|
|
|
$
|
4.11
|
|
2016
|
|
Protective spread
|
|
2,000
|
|
|
732,000
|
|
|
$
|
4.11
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
2016
|
|
Producer three-way collar
|
|
2,000
|
|
|
732,000
|
|
|
$
|
—
|
|
|
$
|
4.00
|
|
|
$
|
3.25
|
|
|
$
|
4.58
|
|
(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.
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily Volume (1) |
|
Total of
Notional Volume |
|
Base
Fixed Price |
|
Floor
(Long) |
|
Short
Put |
|
Ceiling
(Short) |
||||||||||
|
|
|
|
(in Bbls)
|
|
|
|
|
|
|
|
|
||||||||||||
2015
(2)
|
|
Costless collar
|
|
400
|
|
|
72,400
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
—
|
|
|
$
|
96.50
|
|
2015
(2)
|
|
Costless collar
|
|
366
|
|
|
66,300
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
—
|
|
|
$
|
97.80
|
|
2015
(2)
|
|
Costless collar
|
|
150
|
|
|
27,150
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
—
|
|
|
$
|
96.25
|
|
2015
(3)
|
|
Costless three-way collar
|
|
400
|
|
|
73,600
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
70.00
|
|
|
$
|
96.50
|
|
2015
(3)
|
|
Costless three-way collar
|
|
325
|
|
|
59,800
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
97.80
|
|
2015
(3)
|
|
Costless three-way collar
|
|
50
|
|
|
9,200
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
96.25
|
|
2015
(2)
|
|
Put spread
|
|
700
|
|
|
126,700
|
|
|
$
|
—
|
|
|
$
|
90.00
|
|
|
$
|
70.00
|
|
|
$
|
—
|
|
2015
|
|
Put spread
|
|
250
|
|
|
91,250
|
|
|
$
|
—
|
|
|
$
|
89.00
|
|
|
$
|
69.00
|
|
|
$
|
—
|
|
2015
(3)
|
|
Put spread
|
|
600
|
|
|
110,400
|
|
|
$
|
—
|
|
|
$
|
87.00
|
|
|
$
|
67.00
|
|
|
$
|
—
|
|
2016
|
|
Costless three-way collar
|
|
275
|
|
|
100,600
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
95.10
|
|
2016
|
|
Costless three-way collar
|
|
330
|
|
|
120,780
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
65.00
|
|
|
$
|
97.35
|
|
2016
|
|
Put spread
|
|
550
|
|
|
201,300
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
—
|
|
2016
|
|
Put spread
|
|
300
|
|
|
109,800
|
|
|
$
|
—
|
|
|
$
|
85.50
|
|
|
$
|
65.50
|
|
|
$
|
—
|
|
2017
|
|
Costless three-way collar
|
|
280
|
|
|
102,200
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
65.00
|
|
|
$
|
97.25
|
|
2017
|
|
Costless three-way collar
|
|
242
|
|
|
88,150
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
60.00
|
|
|
$
|
98.70
|
|
2017
|
|
Put spread
|
|
500
|
|
|
182,500
|
|
|
$
|
—
|
|
|
$
|
82.00
|
|
|
$
|
62.00
|
|
|
$
|
—
|
|
2018
(4)
|
|
Put spread
|
|
425
|
|
|
103,275
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
60.00
|
|
|
$
|
—
|
|
(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.
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
||||
|
|
|
|
(in Bbls)
|
|
|
||||||
2015
(1)
|
|
Fixed price swap
|
|
250
|
|
|
68,750
|
|
|
$
|
45.61
|
|
(1)
|
For the period April to December 2015.
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
Thereafter
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||
Long-term debt
(1)
|
$
|
370,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
45,000
|
|
|
$
|
325,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest on long-term debt
(2)
|
97,732
|
|
|
29,120
|
|
|
29,120
|
|
|
28,980
|
|
|
10,512
|
|
|
—
|
|
|
—
|
|
|||||||
Deferred put premiums
(3)
|
7,183
|
|
|
2,481
|
|
|
2,408
|
|
|
1,460
|
|
|
834
|
|
|
—
|
|
|
—
|
|
|||||||
Office space leases
(4)
|
1,464
|
|
|
631
|
|
|
490
|
|
|
182
|
|
|
161
|
|
|
—
|
|
|
—
|
|
|||||||
Office equipment leases
|
22
|
|
|
9
|
|
|
8
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Drilling rigs
|
434
|
|
|
434
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Total contractual obligations
|
$
|
476,835
|
|
|
$
|
32,675
|
|
|
$
|
32,026
|
|
|
$
|
75,627
|
|
|
$
|
336,507
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(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.
|
•
|
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.
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands, except share data)
|
||||||
ASSETS
|
|
|
|
||||
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
|
|
|
—
|
|
||
Prepaid expenses
|
2,083
|
|
|
1,145
|
|
||
Total current assets
|
63,619
|
|
|
55,194
|
|
||
PROPERTY, PLANT AND EQUIPMENT:
|
|
|
|
||||
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 natural gas and oil 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
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
||||
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
|
—
|
|
|
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
|
—
|
|
|
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:
|
|
|
|
||||
Preferred stock, 40,000,000 shares authorized
|
|
|
|
||||
Series A Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 4,045,000 and 3,958,160 shares issued and outstanding at December 31, 2014 and 2013, respectively, with liquidation preference of $25.00 per share
|
41
|
|
|
40
|
|
||
Series B Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 2,140,000 shares issued and outstanding at December 31, 2014 and 2013, respectively, with liquidation preference of $25.00 per share
|
21
|
|
|
21
|
|
||
Common stock, par value $0.001 per share; 275,000,000 shares authorized; 78,632,810 and 61,211,658 shares issued and outstanding at December 31, 2014 and 2013, respectively
|
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
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands, except share and per share data)
|
||||||||||
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
|
—
|
|
|
—
|
|
|
150,787
|
|
|||
Accretion of asset retirement obligation
|
506
|
|
|
468
|
|
|
388
|
|
|||
General and administrative expense
|
16,485
|
|
|
16,961
|
|
|
12,211
|
|
|||
Litigation settlement expense
|
—
|
|
|
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
|
—
|
|
|
27,670
|
|
|
—
|
|
|||
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
|
—
|
|
|
(16,042
|
)
|
|
—
|
|
|||
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
|
$
|
0.58
|
|
|
$
|
0.66
|
|
|
$
|
(2.53
|
)
|
Diluted
|
$
|
0.55
|
|
|
$
|
0.63
|
|
|
$
|
(2.53
|
)
|
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
|
|
|
|
|
|
||||||
Basic
|
63,270,733
|
|
|
60,220,115
|
|
|
63,538,362
|
|
|||
Diluted
|
66,492,589
|
|
|
63,618,401
|
|
|
63,538,362
|
|
|
Series A Preferred Stock
|
|
Series B Preferred Stock
|
|
Common Stock
|
|
Additional
Paid-in
Capital
|
|
Accumulated
Deficit
|
|
Total Equity
|
||||||
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|||
|
(in thousands, except share data)
|
||||||||||||||||
Balance at December 31, 2011
|
1,364,543
|
|
$14
|
|
—
|
|
$—
|
|
64,706,750
|
|
$316,346
|
|
$52,753
|
|
$(133,919)
|
|
$235,194
|
Issuance of preferred stock
|
2,586,711
|
|
26
|
|
—
|
|
—
|
|
—
|
|
—
|
|
49,224
|
|
—
|
|
49,250
|
Issuance of restricted stock
|
—
|
|
—
|
|
—
|
|
—
|
|
1,916,980
|
|
—
|
|
—
|
|
—
|
|
—
|
Forfeitures of restricted stock
|
—
|
|
—
|
|
—
|
|
—
|
|
(191,728)
|
|
—
|
|
(335)
|
|
—
|
|
(335)
|
Exercise of stock options, net of forfeitures
|
—
|
|
—
|
|
—
|
|
—
|
|
607
|
|
—
|
|
—
|
|
—
|
|
—
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,295
|
|
—
|
|
3,295
|
Preferred stock dividends
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(7,077)
|
|
(7,077)
|
Net loss
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(153,791)
|
|
(153,791)
|
Balance at December 31, 2012
|
3,951,254
|
|
$40
|
|
—
|
|
$—
|
|
66,432,609
|
|
$316,346
|
|
$104,937
|
|
$(294,787)
|
|
$126,536
|
Issuance of preferred stock
|
6,906
|
|
—
|
|
2,140,000
|
|
21
|
|
—
|
|
—
|
|
50,160
|
|
—
|
|
50,181
|
Repurchase of shares of common stock
|
—
|
|
—
|
|
—
|
|
—
|
|
(6,781,768)
|
|
(9,753)
|
|
—
|
|
—
|
|
(9,753)
|
Reclassification of par value of common stock
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(306,532)
|
|
306,532
|
|
—
|
|
—
|
Issuance of restricted stock
|
—
|
|
—
|
|
—
|
|
—
|
|
2,288,179
|
|
—
|
|
—
|
|
—
|
|
—
|
Forfeitures of restricted stock
|
—
|
|
—
|
|
—
|
|
—
|
|
(737,362)
|
|
—
|
|
(334)
|
|
—
|
|
(334)
|
Exercise of stock options, net of forfeitures
|
—
|
|
—
|
|
—
|
|
—
|
|
10,000
|
|
—
|
|
—
|
|
—
|
|
—
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,435
|
|
—
|
|
3,435
|
Preferred stock dividends
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(9,378)
|
|
(9,378)
|
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
49,342
|
|
49,342
|
Balance at December 31, 2013
|
3,958,160
|
|
$40
|
|
2,140,000
|
|
$21
|
|
61,211,658
|
|
$61
|
|
$464,730
|
|
$(254,823)
|
|
$210,029
|
Issuance of preferred stock
|
86,840
|
|
1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,065
|
|
—
|
|
2,066
|
Issuance of shares - cash, net of offering costs of $4,931
|
—
|
|
—
|
|
—
|
|
—
|
|
17,000,000
|
|
17
|
|
101,302
|
|
—
|
|
101,319
|
Issuance of shares - performance based units vesting, net of forfeitures
|
—
|
|
—
|
|
—
|
|
—
|
|
472,189
|
|
—
|
|
—
|
|
—
|
|
—
|
Issuance of restricted stock
|
—
|
|
—
|
|
—
|
|
—
|
|
601,473
|
|
—
|
|
—
|
|
—
|
|
—
|
Forfeitures of restricted stock
|
—
|
|
—
|
|
—
|
|
—
|
|
(659,227)
|
|
—
|
|
(4,562)
|
|
—
|
|
(4,562)
|
Exercise of stock options, net of forfeitures
|
—
|
|
—
|
|
—
|
|
—
|
|
6,717
|
|
—
|
|
15
|
|
—
|
|
15
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4,890
|
|
—
|
|
4,890
|
Preferred stock dividends
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(14,424)
|
|
(14,424)
|
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
50,953
|
|
50,953
|
Balance at December 31, 2014
|
4,045,000
|
|
$41
|
|
2,140,000
|
|
$21
|
|
78,632,810
|
|
$78
|
|
$568,440
|
|
$(218,294)
|
|
$350,286
|
|
For the years ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
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
|
—
|
|
|
—
|
|
|
150,787
|
|
|||
Stock-based compensation
|
4,890
|
|
|
3,435
|
|
|
3,295
|
|
|||
Mark to market of commodity derivatives contracts:
|
|
|
|
|
|
||||||
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
|
|
|
2,322
|
|
|
224
|
|
|||
Accretion of asset retirement obligation
|
506
|
|
|
468
|
|
|
388
|
|
|||
Settlement of asset retirement obligation
|
(588
|
)
|
|
(66
|
)
|
|
(636
|
)
|
|||
Gain on acquisition of assets at fair value
|
—
|
|
|
(27,670
|
)
|
|
—
|
|
|||
Deferred tax benefit
|
—
|
|
|
(16,042
|
)
|
|
—
|
|
|||
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
|
)
|
|
—
|
|
|||
Proceeds from sale of oil and natural gas properties
|
5,530
|
|
|
112,201
|
|
|
—
|
|
|||
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
|
|
|
—
|
|
|
—
|
|
|||
Repurchase of common stock
|
—
|
|
|
(9,753
|
)
|
|
—
|
|
|||
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
|
—
|
|
|
312,279
|
|
|
—
|
|
|||
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.
|
Description of Business
|
|
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
|
|
|
As of December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
|
||||||
Deferred charges
|
$
|
3,664
|
|
|
$
|
3,269
|
|
Accumulated amortization
|
(1,078
|
)
|
|
(319
|
)
|
||
Deferred charges, net
|
$
|
2,586
|
|
|
$
|
2,950
|
|
3.
|
Property, Plant and Equipment
|
|
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
|
|
|
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
|
|
|
|
2014
|
||||||||||||||||||
|
|
Total Impairment
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||||
Henry Hub natural gas price (per MMBtu)
(1)
|
|
|
|
$
|
4.35
|
|
|
$
|
4.24
|
|
|
$
|
4.10
|
|
|
$
|
3.99
|
|
||
West Texas Intermediate oil price (per Bbl)
(1)
|
|
|
|
$
|
94.99
|
|
|
$
|
99.08
|
|
|
$
|
100.11
|
|
|
$
|
98.30
|
|
||
Impairment recorded (pre-tax) (in thousands)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
2013
|
||||||||||||||||||
|
|
Total Impairment
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||||
Henry Hub natural gas price (per MMBtu)
(1)
|
|
|
|
$
|
3.67
|
|
|
$
|
3.61
|
|
|
$
|
3.44
|
|
|
$
|
2.95
|
|
||
West Texas Intermediate oil price (per Bbl)
(1)
|
|
|
|
$
|
96.78
|
|
|
$
|
91.69
|
|
|
$
|
88.13
|
|
|
$
|
89.17
|
|
||
Impairment recorded (pre-tax) (in thousands)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
2012
|
||||||||||||||||||
|
|
Total Impairment
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||||
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.
|
|
|
|
||
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
|
|
|
|
|
||
Consideration:
|
|
|
||
Cash consideration
|
|
$
|
177,778
|
|
|
|
|
||
Estimated Fair Value of Assets Acquired:
|
|
|
||
Unproved properties
|
|
$
|
13,026
|
|
Proved properties
|
|
164,752
|
|
|
Total assets acquired
|
|
$
|
177,778
|
|
|
|
Year Ended December 31, 2013
|
||
|
|
(in thousands)
|
||
Revenues
|
|
$
|
11,292
|
|
Excess of revenues over direct operating expenses
|
|
$
|
7,591
|
|
4.
|
Long-Term Debt
|
•
|
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.
|
•
|
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.
|
|
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
|
|
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
|
|
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
|
|
|
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.
|
7.
|
Derivative Instruments and Hedging Activity
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
|
Floor
(Long)
|
|
Short
Put
|
|
Ceiling
(Short)
|
||||||||||
|
|
|
|
(in MMBtu's)
|
|
|
|
|
|
|
|
|
||||||||||||
2015
(1)
|
|
Protective spread
|
|
10,000
|
|
|
900,000
|
|
|
$
|
4.46
|
|
|
$
|
—
|
|
|
$
|
3.70
|
|
|
$
|
—
|
|
2015
(1)
|
|
Call spread
|
|
10,000
|
|
|
900,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5.00
|
|
2015
|
|
Fixed price swap
|
|
400
|
|
|
146,000
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Fixed price swap
|
|
2,500
|
|
|
912,500
|
|
|
$
|
4.06
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Protective spread
|
|
2,600
|
|
|
949,000
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
2015
(1)
|
|
Producer three-way collar
|
|
3,750
|
|
|
337,500
|
|
|
$
|
—
|
|
|
$
|
4.60
|
|
|
$
|
3.50
|
|
|
$
|
5.34
|
|
2015
(1)
|
|
Producer three-way collar
|
|
2,500
|
|
|
337,500
|
|
|
$
|
—
|
|
|
$
|
4.40
|
|
|
$
|
3.65
|
|
|
$
|
5.00
|
|
2015
|
|
Producer three-way collar
|
|
2,000
|
|
|
760,000
|
|
|
$
|
—
|
|
|
$
|
4.00
|
|
|
$
|
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
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
2015
(3)
|
|
Producer three-way collar
|
|
2,500
|
|
|
687,500
|
|
|
$
|
—
|
|
|
$
|
3.70
|
|
|
$
|
3.00
|
|
|
$
|
4.09
|
|
2015
(3)
|
|
Producer three-way collar
|
|
5,000
|
|
|
1,375,000
|
|
|
$
|
—
|
|
|
$
|
3.77
|
|
|
$
|
3.00
|
|
|
$
|
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.
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume (1)
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
|
Floor
(Long)
|
|
Short
Put
|
|
Ceiling
(Short)
|
||||||||||
|
|
|
|
(in Bbls)
|
|
|
|
|
|
|
|
|
||||||||||||
2015
(2)
|
|
Costless collar
|
|
400
|
|
|
72,400
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
—
|
|
|
$
|
96.50
|
|
2015
(2)
|
|
Costless collar
|
|
366
|
|
|
66,300
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
—
|
|
|
$
|
97.80
|
|
2015
(2)
|
|
Costless collar
|
|
150
|
|
|
27,150
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
—
|
|
|
$
|
96.25
|
|
2015
(3)
|
|
Costless three-way collar
|
|
400
|
|
|
73,600
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
70.00
|
|
|
$
|
96.50
|
|
2015
(3)
|
|
Costless three-way collar
|
|
325
|
|
|
59,800
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
97.80
|
|
2015
(3)
|
|
Costless three-way collar
|
|
50
|
|
|
9,200
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
96.25
|
|
2015
(2)
|
|
Put spread
|
|
700
|
|
|
126,700
|
|
|
$
|
—
|
|
|
$
|
90.00
|
|
|
$
|
70.00
|
|
|
$
|
—
|
|
2015
|
|
Put spread
|
|
250
|
|
|
91,250
|
|
|
$
|
—
|
|
|
$
|
89.00
|
|
|
$
|
69.00
|
|
|
$
|
—
|
|
2015
(3)
|
|
Put spread
|
|
600
|
|
|
110,400
|
|
|
$
|
—
|
|
|
$
|
87.00
|
|
|
$
|
67.00
|
|
|
$
|
—
|
|
2016
|
|
Costless three-way collar
|
|
275
|
|
|
100,600
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
95.10
|
|
2016
|
|
Costless three-way collar
|
|
330
|
|
|
120,780
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
65.00
|
|
|
$
|
97.35
|
|
2016
|
|
Put spread
|
|
550
|
|
|
201,300
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
—
|
|
2016
|
|
Put spread
|
|
300
|
|
|
109,800
|
|
|
$
|
—
|
|
|
$
|
85.50
|
|
|
$
|
65.50
|
|
|
$
|
—
|
|
2017
|
|
Costless three-way collar
|
|
280
|
|
|
102,200
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
65.00
|
|
|
$
|
97.25
|
|
2017
|
|
Costless three-way collar
|
|
242
|
|
|
88,150
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
60.00
|
|
|
$
|
98.70
|
|
2017
|
|
Put spread
|
|
500
|
|
|
182,500
|
|
|
$
|
—
|
|
|
$
|
82.00
|
|
|
$
|
62.00
|
|
|
$
|
—
|
|
2018
(4)
|
|
Put spread
|
|
425
|
|
|
103,275
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
60.00
|
|
|
$
|
—
|
|
(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.
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
||||
|
|
|
|
(in Bbls)
|
|
|
||||||
2015
(1)
|
|
Fixed price swap
|
|
250
|
|
|
68,750
|
|
|
$
|
45.61
|
|
(1)
|
For the period April to December 2015.
|
|
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
|
|
|
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
|
|
|
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
Income on Derivatives
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
|
(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
|
|
|
|
|
|
|
|
|
|
8.
|
Capital Stock
|
|
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.
|
|
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.
|
|
Shares
|
|
Weighted Average
Exercise Price
per Share
|
|
Weighted Average
Remaining
Contractual Term
(in years)
|
|
Aggregate
Intrinsic Value
(in thousands)
|
|||||
Outstanding at December 31, 2013
|
874,100
|
|
|
$
|
11.68
|
|
|
|
|
|
||
Granted
|
—
|
|
|
—
|
|
|
|
|
|
|||
Exercised
|
(7,500
|
)
|
|
2.60
|
|
|
|
|
|
|||
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
Fair Value
per Share
|
|
Weighted Average
Exercise Price
per Share
|
|
Weighted Average
Remaining
Contractual Term
(in years)
|
|
Aggregate
Intrinsic Value
(in thousands)
|
|||||||
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
|
|
$
|
—
|
|
|
Shares
|
|
Weighted Average
Fair Value
per Share
|
|
Weighted Average
Remaining
Contractual Term
(in years)
|
|
Aggregate
Intrinsic Value (in thousands)
|
|||||
Outstanding non-vested restricted shares at December 31, 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
|
|
|
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
|
|
|
$
|
1.30
|
|
|
$
|
2.09
|
|
Total fair value of restricted shares vested
|
$
|
3,497
|
|
|
$
|
2,725
|
|
|
$
|
2,492
|
|
|
|
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
|
|
|
Amount
|
||
|
(in thousands)
|
||
2015
|
$
|
2,034
|
|
2016
|
663
|
|
|
2017
|
59
|
|
|
Total
|
$
|
2,756
|
|
10.
|
Interest Expense
|
|
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.
|
|
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
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
$
|
—
|
|
|
$
|
(15,299
|
)
|
|
$
|
—
|
|
State
|
—
|
|
|
(743
|
)
|
|
—
|
|
|||
Foreign
|
—
|
|
|
—
|
|
|
—
|
|
|||
Income tax expense (benefit)
|
$
|
—
|
|
|
$
|
(16,042
|
)
|
|
$
|
—
|
|
|
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
|
)
|
|
$
|
—
|
|
|
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
|
$
|
—
|
|
|
$
|
—
|
|
|
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
|
|
2015
|
$
|
640
|
|
2016
|
498
|
|
|
2017
|
187
|
|
|
2018
|
161
|
|
|
|
$
|
1,486
|
|
|
|
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.
|
|
|
For the Years Ended December 31,
|
|||||||
|
|
2014
|
|
2013
|
|
2012
|
|||
SEI
|
|
50
|
%
|
|
56
|
%
|
|
47
|
%
|
Sunoco
|
|
37
|
%
|
|
16
|
%
|
|
—
|
%
|
Clearfield Appalachian
|
|
—
|
%
|
|
8
|
%
|
|
14
|
%
|
ETC
|
|
—
|
%
|
|
8
|
%
|
|
24
|
%
|
16.
|
Statement of Cash Flows – Supplemental Information
|
|
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
|
)
|
|
2014
|
||||||||||||||
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
|
(in thousands, except share and per share data)
|
||||||||||||||
Revenues
|
$
|
32,327
|
|
|
$
|
35,897
|
|
|
$
|
41,746
|
|
|
$
|
61,448
|
|
Income from operations
|
8,497
|
|
|
12,539
|
|
|
20,413
|
|
|
37,063
|
|
||||
Income before provision for income taxes
|
1,611
|
|
|
5,627
|
|
|
13,425
|
|
|
30,290
|
|
||||
Net income
|
1,611
|
|
|
5,627
|
|
|
13,425
|
|
|
30,290
|
|
||||
Dividend on preferred stock
|
3,576
|
|
|
3,611
|
|
|
3,618
|
|
|
3,619
|
|
||||
Net (loss) income attributable to common stockholders
|
(1,965
|
)
|
|
2,016
|
|
|
9,807
|
|
|
26,671
|
|
||||
Net (loss) income per share of common stock attributable to common stockholders:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.03
|
)
|
|
$
|
0.03
|
|
|
$
|
0.16
|
|
|
$
|
0.35
|
|
Diluted
|
$
|
(0.03
|
)
|
|
$
|
0.03
|
|
|
$
|
0.15
|
|
|
$
|
0.34
|
|
Weighted average shares of common stock outstanding:
|
|
|
|
|
|
|
|
||||||||
Basic
|
58,204,532
|
|
|
58,702,982
|
|
|
60,006,903
|
|
|
75,994,979
|
|
||||
Diluted
|
58,204,532
|
|
|
61,922,874
|
|
|
63,399,446
|
|
|
78,577,762
|
|
|
2013
|
||||||||||||||
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
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
.
|
|
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
|
|
|
|
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.
|
|
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
|
|
|
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
|
|
Change in Proved Reserves
|
Natural Gas
(MMcf) (1)
|
|
NGLs
(MBbl) (2)
|
|
Condensate and Oil
(MBbl) (2)
|
|
MBoe (3) Equivalents (4)
|
||||
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
|
|
(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
(MMcf) (1)
|
|
NGLs
(MBbl) (2)
|
|
Condensate and Oil
(MBbl) (2)
|
|
MBoe (3) Equivalents (4)
|
||||
December 31, 2012
|
|
|
|
|
|
|
|
||||
Proved developed reserves
|
95,602
|
|
|
3,215.8
|
|
|
1,959
|
|
|
21,109
|
|
Proved undeveloped reserves
|
35,408
|
|
|
1,706
|
|
|
1,435
|
|
|
9,042
|
|
Total
|
131,010
|
|
|
4,922
|
|
|
3,394
|
|
|
30,151
|
|
December 31, 2013
|
|
|
|
|
|
|
|
||||
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
|
|
December 31, 2014
|
|
|
|
|
|
|
|
||||
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
|
|
(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.
|
|
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
|
|
|
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.
|
|
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
|
|
|
December 31, 2012
|
$
|
206,809
|
|
Extensions and discoveries, less related costs
|
196,448
|
|
|
Sale of natural gas and oil, net of production costs
|
(74,394
|
)
|
|
Purchases of reserves in place
|
247,208
|
|
|
Sales of reserves in place
|
(9,063
|
)
|
|
Revisions of previous quantity estimates
|
6,191
|
|
|
Net change in income tax
|
(76,701
|
)
|
|
Net change in prices and production costs
|
79,820
|
|
|
Accretion of discount
|
1,211
|
|
|
Development costs incurred
|
23,567
|
|
|
Net change in estimated future development costs
|
(97,461
|
)
|
|
Change in production rates (timing) and other
|
12,194
|
|
|
December 31, 2013
|
$
|
515,829
|
|
Extensions and discoveries, less related costs
|
369,806
|
|
|
Sale of natural gas and oil, net of production costs
|
(122,114
|
)
|
|
Sales of reserves in place
|
(1,475
|
)
|
|
Revisions of previous quantity estimates
|
101,044
|
|
|
Net change in income tax
|
(95,245
|
)
|
|
Net change in prices and production costs
|
59,786
|
|
|
Accretion of discount
|
(3,996
|
)
|
|
Development costs incurred
|
37,461
|
|
|
Net change in estimated future development costs
|
(1,277
|
)
|
|
Change in production rates (timing) and other
|
(43,081
|
)
|
|
December 31, 2014
|
$
|
816,739
|
|
GASTAR EXPLORATION INC.
|
||
/s/ J. RUSSELL PORTER
|
|
/s/ MICHAEL A. GERLICH
|
J. Russell Porter
|
|
Michael A. Gerlich
|
President and Chief Executive Officer
|
|
Senior Vice President and Chief Financial Officer
|
March 12, 2015
|
|
March 12, 2015
|
Name
|
|
Age
|
|
Position
|
J. Russell Porter (1)
|
|
53
|
|
President and Chief Executive Officer
|
Michael A. Gerlich (1)
|
|
60
|
|
Senior Vice President, Chief Financial Officer and Corporate Secretary
|
Michael McCown (1)
|
|
60
|
|
Senior Vice President and Chief Operating Officer
|
Keith R. Blair
|
|
60
|
|
Vice President and Exploration Manager
|
Henry J. Hansen
|
|
59
|
|
Vice President - Land
|
John M. Selser Sr.
|
|
56
|
|
Chairman of the Board
|
John H. Cassels
|
|
67
|
|
Director
|
Randolph C. Coley
|
|
68
|
|
Director
|
Stephen A. Holditch
|
|
68
|
|
Director
|
Robert D. Penner
|
|
71
|
|
Director
|
Jerry R. Schuyler
|
|
59
|
|
Director
|
(1)
|
Messrs. Porter, Gerlich and McCown are our only “Executive Officers” as such term is defined by the rules promulgated by the SEC.
|
•
|
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.
|
Goal
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Actual
|
|
Weighting
|
|||||||||
Target average annual production (MMcfe/d)
|
|
56.5
|
|
|
62.8
|
|
|
69.1
|
|
|
61.0
|
|
|
10
|
%
|
||||
Target proved reserves additions (Bcfe)
|
|
85.8
|
|
|
95.3
|
|
|
104.9
|
|
|
307.9
|
|
|
10
|
%
|
||||
Average finding costs ($/Mcfe)
|
|
$
|
2.60
|
|
|
$
|
2.36
|
|
|
$
|
2.12
|
|
|
$
|
0.72
|
|
|
5
|
%
|
Average controllable lifting costs ($/Mcfe)
|
|
$
|
0.80
|
|
|
$
|
0.73
|
|
|
$
|
0.66
|
|
|
$
|
0.84
|
|
|
5
|
%
|
Operating cash flow ($ in millions)
|
|
$
|
72.5
|
|
|
$
|
80.5
|
|
|
$
|
88.6
|
|
|
$
|
65.9
|
|
|
20
|
%
|
Operating cash flow per share
|
|
$
|
1.15
|
|
|
$
|
1.27
|
|
|
$
|
1.40
|
|
|
$
|
1.04
|
|
|
10
|
%
|
Production per share (Mcfe)
|
|
0.33
|
|
|
0.36
|
|
|
0.40
|
|
|
0.35
|
|
|
20
|
%
|
||||
Reserves per share (Mcfe)
|
|
5.97
|
|
|
6.64
|
|
|
7.30
|
|
|
9.68
|
|
|
20
|
%
|
•
|
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.
|
Name and Principal Position
|
|
Year
|
|
Base Salary
|
|
Bonus
|
|
Restricted Stock and PBUs
(1)
|
|
All Other Compensation
(3)
|
|
Total
|
||||||||||
J. Russell Porter
|
|
2014
|
|
$
|
535,000
|
|
|
$
|
472,202
|
|
|
$
|
1,529,006
|
|
|
$
|
10,400
|
|
|
$
|
2,546,608
|
|
President and Chief
|
|
2013
|
|
$
|
500,000
|
|
|
$
|
489,378
|
|
|
$
|
1,158,393
|
|
|
$
|
10,200
|
|
|
$
|
2,157,971
|
|
Executive Officer
|
|
2012
|
|
$
|
500,000
|
|
|
$
|
393,750
|
|
|
$
|
750,000
|
|
|
$
|
10,000
|
|
|
$
|
1,653,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Michael A. Gerlich
|
|
2014
|
|
$
|
312,000
|
|
|
$
|
273,380
|
|
|
$
|
690,980
|
|
|
$
|
10,400
|
|
|
$
|
1,286,760
|
|
Senior Vice President and
|
|
2013
|
|
$
|
300,000
|
|
|
$
|
234,901
|
|
|
$
|
656,111
|
|
|
$
|
10,200
|
|
|
$
|
1,201,212
|
|
Chief Financial Officer
|
|
2012
|
|
$
|
300,000
|
|
|
$
|
189,000
|
|
|
$
|
375,000
|
|
|
$
|
10,000
|
|
|
$
|
874,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Michael McCown
(2)
|
|
2014
|
|
$
|
312,000
|
|
|
$
|
273,380
|
|
|
$
|
566,379
|
|
|
$
|
10,400
|
|
|
$
|
1,162,159
|
|
Senior Vice President and
|
|
2013
|
|
$
|
300,000
|
|
|
$
|
221,851
|
|
|
$
|
403,449
|
|
|
$
|
10,033
|
|
|
$
|
935,333
|
|
Chief Operating Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
|
Estimated Future Payout Under Equity Incentive Plan Awards
(2)
|
|
|
|
|
||||||||||||||
Name
|
|
Date
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Grant Date Fair Value of PBUs
(1)
|
|
All Other Equity Awards: Number of Shares of Stock
|
|
Grant Date Fair Value of Stock Awards
(1)
|
||||||||
J. Russell Porter
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
116,380
|
|
|
$
|
675,004
|
|
|
J. Russell Porter
|
|
1/30/2014
|
|
—
|
|
|
116,379
|
|
|
232,758
|
|
|
$
|
854,222
|
|
|
—
|
|
|
$
|
—
|
|
Michael A. Gerlich
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52,586
|
|
|
$
|
305,000
|
|
|
Michael A. Gerlich
|
|
1/30/2014
|
|
—
|
|
|
52,586
|
|
|
105,172
|
|
|
$
|
385,981
|
|
|
—
|
|
|
$
|
—
|
|
Michael McCown
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,104
|
|
|
$
|
250,003
|
|
|
Michael McCown
|
|
1/30/2014
|
|
—
|
|
|
43,103
|
|
|
86,206
|
|
|
$
|
316,376
|
|
|
—
|
|
|
$
|
—
|
|
(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.”
|
|
Base Salary and Cash Bonuses as a Percentage of Total Compensation
|
|
|
|
|
J. Russell Porter
|
40
|
%
|
Michael A. Gerlich
|
46
|
%
|
Michael McCown
|
51
|
%
|
|
|
|
|
Option Awards
|
|
PBU Awards
|
|
Stock Awards
|
|||||||||||||||||||||
Name
|
|
Grant Date
|
|
Number of Securities Underlying Unexercised Options Exercisable
|
|
Number of Securities Underlying Unexercised Options Unexercisable
|
|
Option Exercise Price
|
|
Option Expiration Date
|
|
Number of PBUs That Have Not Vested
(1)
|
|
Market Value of PBUs That Have Not Vested
(1)
|
|
Number of Shares of Restricted Stock That Have Not Vested
|
|
Market Value of Shares of Restricted Stock That Have Note Vested
(2)
|
|||||||||||
J. Russell Porter
(3)
|
|
4/5/2006
|
|
30,000
|
|
|
—
|
|
|
$
|
20.51
|
|
|
4/5/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
7/14/2006
|
|
200,000
|
|
|
—
|
|
|
$
|
11.60
|
|
|
7/14/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
3/19/2009
|
|
30,000
|
|
|
—
|
|
|
$
|
2.60
|
|
|
3/19/2019
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
254,655
|
|
|
$
|
1,186,692
|
|
|
—
|
|
|
—
|
|
||
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
116,379
|
|
|
$
|
84,956.67
|
|
|
—
|
|
|
—
|
|
||
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41,966
|
|
|
$
|
101,138
|
|
||
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
84,459
|
|
|
$
|
203,546
|
|
||
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
323,276
|
|
|
$
|
779,095
|
|
||
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
116,380
|
|
|
$
|
280,476
|
|
||
Michael A. Gerlich
(4)
|
|
1/16/2006
|
|
50,000
|
|
|
—
|
|
|
$
|
21.60
|
|
|
1/16/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
4/5/2006
|
|
20,000
|
|
|
—
|
|
|
$
|
20.51
|
|
|
4/5/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
7/14/2006
|
|
60,000
|
|
|
—
|
|
|
$
|
11.60
|
|
|
7/14/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
3/19/2009
|
|
20,000
|
|
|
—
|
|
|
$
|
2.60
|
|
|
3/19/2019
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
160,201
|
|
|
$
|
746,537
|
|
|
—
|
|
|
—
|
|
||
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52,586
|
|
|
$
|
38,387.78
|
|
|
—
|
|
|
—
|
|
||
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,482
|
|
|
$
|
54,182
|
|
||
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42,230
|
|
|
$
|
101,774
|
|
||
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
161,638
|
|
|
$
|
389,548
|
|
||
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52,586
|
|
|
$
|
126,732
|
|
||
Michael McCown
(5)
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
89,080
|
|
|
$
|
415,113
|
|
|
—
|
|
|
—
|
|
||
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,103
|
|
|
$
|
31,465.19
|
|
|
—
|
|
|
—
|
|
||
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,230
|
|
|
$
|
29,474
|
|
||
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29,279
|
|
|
$
|
70,562
|
|
||
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
112,069
|
|
|
$
|
270,086
|
|
||
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,104
|
|
|
$
|
103,881
|
|
(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,
|
(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.
|
|
|
Stock Awards
|
|||||||||
Name
|
|
Grant Date
|
|
Vesting Date
|
|
Number of Shares Acquired on Vesting
|
|
Value Realized on Vesting
(1)
|
|||
J. Russell Porter
|
|
3/26/2010
|
|
3/26/2014
|
|
31,250
|
|
|
$
|
171,875
|
|
|
|
3/15/2011
|
|
3/15/2014
|
|
41,967
|
|
|
$
|
216,969
|
|
|
|
1/30/2012
|
|
1/30/2014
|
|
84,460
|
|
|
$
|
489,868
|
|
|
|
1/30/2013
|
|
1/30/2014
|
|
161,638
|
|
|
$
|
937,500
|
|
Michael A. Gerlich
|
|
3/26/2010
|
|
3/26/2014
|
|
21,875
|
|
|
$
|
120,313
|
|
|
|
3/15/2011
|
|
3/15/2014
|
|
22,482
|
|
|
$
|
116,232
|
|
|
|
1/30/2012
|
|
1/30/2014
|
|
42,229
|
|
|
$
|
244,928
|
|
|
|
1/30/2013
|
|
1/30/2014
|
|
80,819
|
|
|
$
|
468,750
|
|
Michael McCown
|
|
8/5/2010
|
|
8/5/2014
|
|
5,000
|
|
|
$
|
33,250
|
|
|
|
3/15/2011
|
|
3/15/2014
|
|
12,230
|
|
|
$
|
63,229
|
|
|
|
1/30/2012
|
|
1/30/2014
|
|
29,280
|
|
|
$
|
169,824
|
|
|
|
1/30/2013
|
|
1/30/2014
|
|
56,034
|
|
|
$
|
324,997
|
|
(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.
|
|
|
Performance Based Units
|
|||||||||
Name
|
|
Grant Date
|
|
Vesting Date
|
|
Number of Shares Acquired on Vesting
(1)
|
|
Value Realized on Vesting
(2)
|
|||
J. Russell Porter
|
|
1/30/2013
|
|
1/30/2014
|
|
254,656
|
|
|
$
|
1,477,005
|
|
Michael A. Gerlich
|
|
1/30/2013
|
|
1/30/2014
|
|
160,202
|
|
|
$
|
929,172
|
|
Michael McCown
|
|
1/30/2013
|
|
1/30/2014
|
|
89,082
|
|
|
$
|
516,676
|
|
(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.
|
Named Executive Officer and Post Termination Benefits
|
|
Termination for other than Reasonable Cause
(1)
|
|
Constructive Termination and Termination in Connection with Change of Control
(2)
|
|
Termination for Reasonable Cause
(3)
|
|
Death
(1)(4)
|
|
Disability
(1)(4)
|
||||||||||
J. Russell Porter:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Salary
|
|
$
|
2,407,500
|
|
|
$
|
3,033,450
|
|
|
$
|
—
|
|
|
$
|
2,407,500
|
|
|
$
|
2,407,500
|
|
Accrued Vacation
|
|
5,144
|
|
|
5,144
|
|
|
5,144
|
|
|
5,144
|
|
|
5,144
|
|
|||||
Paid health and medical
|
|
32,238
|
|
|
32,238
|
|
|
—
|
|
|
32,238
|
|
|
32,238
|
|
|||||
Parachute tax gross-up payment
(5)
|
|
—
|
|
|
1,247,663
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity compensation
(6)
|
|
—
|
|
|
2,258,450
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
2,444,882
|
|
|
$
|
6,576,945
|
|
|
$
|
5,144
|
|
|
$
|
2,444,882
|
|
|
$
|
2,444,882
|
|
Michael A. Gerlich:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Salary
|
|
$
|
1,466,400
|
|
|
$
|
1,466,400
|
|
|
$
|
—
|
|
|
$
|
1,466,400
|
|
|
$
|
1,466,400
|
|
Accrued Vacation
|
|
16,500
|
|
|
16,500
|
|
|
16,500
|
|
|
16,500
|
|
|
16,500
|
|
|||||
Paid health and medical
|
|
32,238
|
|
|
32,238
|
|
|
—
|
|
|
32,238
|
|
|
32,238
|
|
|||||
Parachute tax gross-up payment
(5)
|
|
—
|
|
|
813,395
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity compensation
(6)
|
|
—
|
|
|
1,185,052
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
1,515,138
|
|
|
$
|
3,513,585
|
|
|
$
|
16,500
|
|
|
$
|
1,515,138
|
|
|
$
|
1,515,138
|
|
Michael McCown:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Salary
|
|
$
|
780,000
|
|
|
$
|
1,466,400
|
|
|
$
|
—
|
|
|
$
|
780,000
|
|
|
$
|
780,000
|
|
Accrued Vacation
|
|
1,350
|
|
|
1,350
|
|
|
1,350
|
|
|
1,350
|
|
|
1,350
|
|
|||||
Paid health and medical
|
|
32,238
|
|
|
32,238
|
|
|
—
|
|
|
32,238
|
|
|
32,238
|
|
|||||
Parachute tax gross-up payment
(5)
|
|
—
|
|
|
931,622
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity compensation
(6)
|
|
—
|
|
|
792,565
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
813,588
|
|
|
$
|
3,224,175
|
|
|
$
|
1,350
|
|
|
$
|
813,588
|
|
|
$
|
813,588
|
|
(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
|
(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
|
(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.
|
•
|
$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;
|
•
|
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.
|
Director
|
|
Fees Earned or Paid in Cash
|
|
Shares of Common Stock
(1)
|
|
Total
|
||||||
John H. Cassels
|
|
$
|
67,750
|
|
|
$
|
100,000
|
|
|
$
|
167,750
|
|
Randolph C. Coley
|
|
$
|
69,800
|
|
|
$
|
100,000
|
|
|
$
|
169,800
|
|
Stephen A. Holditch
|
|
$
|
23,850
|
|
|
$
|
200,000
|
|
|
$
|
223,850
|
|
Robert D. Penner
|
|
$
|
74,700
|
|
|
$
|
100,000
|
|
|
$
|
174,700
|
|
Jerry R. Schuyler
|
|
$
|
24,850
|
|
|
$
|
200,000
|
|
|
$
|
224,850
|
|
John M. Selser
|
|
$
|
86,300
|
|
|
$
|
100,000
|
|
|
$
|
186,300
|
|
(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.
|
|
|
|
|
Option Awards
|
|
Stock Awards
|
||||||||||||||||
Name
|
|
Grant Date
|
|
Number of Securities Underlying Unexercised Options Exercisable
|
|
Number of Securities Underlying Unexercised Options Unexercisable
|
|
Option Exercise Price
|
|
Option Expiration Date
|
|
Number of Shares of Restricted Stock That Have Not Vested
|
|
Market Value of Shares of Restricted Stock That Have Not Vested
(1)
|
||||||||
John H. Cassels
(2)
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,496
|
|
|
$
|
10,835
|
|
|
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,446
|
|
|
$
|
20,355
|
|
|
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,103
|
|
|
$
|
103,878
|
|
|
|
|
11/11/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,667
|
|
|
$
|
20,887
|
|
|
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,241
|
|
|
$
|
41,551
|
|
|
Randolph C. Coley
(3)
|
|
1/14/2010
|
|
40,000
|
|
|
—
|
|
|
$
|
4.27
|
|
|
1/14/2020
|
|
|
—
|
|
|
—
|
|
|
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,496
|
|
|
$
|
10,835
|
|
|
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,446
|
|
|
$
|
20,355
|
|
|
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,103
|
|
|
$
|
103,878
|
|
|
|
|
11/11/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,667
|
|
|
$
|
20,887
|
|
|
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,241
|
|
|
$
|
41,551
|
|
|
Stephen A. Holditch
(4)
|
|
8/8/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,206
|
|
|
$
|
77,616
|
|
|
Robert D. Penner
(5)
|
|
7/9/2007
|
|
40,000
|
|
|
—
|
|
|
$
|
10.95
|
|
|
7/9/2017
|
|
|
—
|
|
|
—
|
|
|
|
|
3/19/2009
|
|
15,000
|
|
|
—
|
|
|
$
|
2.60
|
|
|
3/19/2019
|
|
|
—
|
|
|
—
|
|
|
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,496
|
|
|
$
|
10,835
|
|
|
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,446
|
|
|
$
|
20,355
|
|
|
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,103
|
|
|
$
|
103,878
|
|
|
|
|
11/11/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,667
|
|
|
$
|
20,887
|
|
|
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,241
|
|
|
$
|
41,551
|
|
|
Jerry R. Schuyler
(6)
|
|
8/8/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,206
|
|
|
$
|
77,616
|
|
|
John M. Selser Sr.
(7)
|
|
3/30/2007
|
|
40,000
|
|
|
—
|
|
|
$
|
10.85
|
|
|
3/30/2017
|
|
|
—
|
|
|
—
|
|
|
|
|
7/3/2007
|
|
20,000
|
|
|
—
|
|
|
$
|
11.00
|
|
|
7/3/2017
|
|
|
—
|
|
|
—
|
|
|
|
|
3/19/2009
|
|
15,000
|
|
|
—
|
|
|
$
|
2.60
|
|
|
3/19/2019
|
|
|
—
|
|
|
—
|
|
|
|
|
3/15/2011
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,496
|
|
|
$
|
10,835
|
|
|
|
|
1/30/2012
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,446
|
|
|
$
|
20,355
|
|
|
|
|
1/30/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,103
|
|
|
$
|
103,878
|
|
|
|
|
11/11/2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,333
|
|
|
$
|
41,773
|
|
|
|
|
1/30/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,241
|
|
|
$
|
41,551
|
|
(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.
|
(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.
|
Annual director retainer
|
|
$
|
70,000
|
|
Chairman of Board annual retainer
|
|
$
|
35,000
|
|
Chairman of Audit Committee annual retainer
|
|
$
|
15,000
|
|
Chairman of Compensation Committee annual retainer
|
|
$
|
10,000
|
|
Chairman of Nominating and Corporate Governance Committee annual retainer
|
|
$
|
10,000
|
|
Chairman of Reserves Review Committee
|
|
$
|
10,000
|
|
•
|
Each of our directors;
|
•
|
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.
|
|
|
Common Stock
|
|
Series A Preferred Stock
|
|
Series B Preferred Stock
|
|||||||
Name and Address of Beneficial Owner
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Shares Outstanding
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Shares Outstanding
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Shares Outstanding
|
|
Our greater than 5% shareholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Global Undervalued Securities Master Fund, L.P.
(1)
|
|
6,256,580
|
|
|
7.8%
|
|
|
|
|
|
|
|
|
301 Commerce Street, Suite 1900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fort Worth, Texas 76109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BlackRock, Inc.
(2)
|
|
4,189,832
|
|
|
5.2%
|
|
|
|
|
|
|
|
|
55 East 52nd Street
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New York, NY 10022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our non-employee directors
(3)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John H. Cassels
(4)
|
|
161,275
|
|
|
*
|
|
—
|
|
—%
|
|
—
|
|
—%
|
Randolph C. Coley
(5)
|
|
208,130
|
|
|
*
|
|
—
|
|
—%
|
|
—
|
|
—%
|
Stephen A. Holditch
(6)
|
|
100,823
|
|
|
*
|
|
—
|
|
—%
|
|
—
|
|
—%
|
Robert D. Penner
(7)
|
|
263,774
|
|
|
*
|
|
—
|
|
—%
|
|
—
|
|
—%
|
Jerry R. Schuyler
(8)
|
|
73,873
|
|
|
*
|
|
—
|
|
—%
|
|
—
|
|
—%
|
John M. Selser Sr.
(9)
|
|
315,554
|
|
|
*
|
|
3,000
|
|
*
|
|
—
|
|
—%
|
Our executive officers
(2)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J. Russell Porter, President and Chief Executive Officer
(10)
|
|
2,852,500
|
|
|
3.5%
|
|
7,459
|
|
*
|
|
2,000
|
|
*
|
Michael A. Gerlich, Senior Vice President and Chief Financial Officer
(11)
|
|
1,393,579
|
|
|
1.7%
|
|
2,525
|
|
*
|
|
2,000
|
|
*
|
Michael McCown, Senior Vice President and Chief Operating Officer
(12)
|
|
767,978
|
|
|
*
|
|
11,655
|
|
*
|
|
1,535
|
|
*
|
Our directors and executive officers, as a group (9 persons)
|
|
5,962,790
|
|
|
7.4%
|
|
24,639
|
|
*
|
|
5,535
|
|
*
|
(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.
|
(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.
|
Plan Category
|
|
Number of Securities to be issued upon exercise of outstanding options, warrants and rights (a)
|
|
Weighted-average exercise price of outstanding options, warrants and rights (b)
|
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
|
||||
Equity compensation plans approved by security holders
|
|
866,600
|
|
|
$
|
11.75
|
|
|
5,428,108
|
|
Equity compensation plans approved by security holders
|
|
990,658
|
|
|
n/a
|
|
|
6,418,766
|
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
1,857,258
|
|
|
5.49
|
|
|
6,418,766
|
|
|
For the Years Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Audit fees
|
$
|
365
|
|
|
$
|
609
|
|
Audit-related fees
|
—
|
|
|
—
|
|
||
Tax fees
|
—
|
|
|
—
|
|
||
All other fees
|
—
|
|
|
—
|
|
||
Total
|
$
|
365
|
|
|
$
|
609
|
|
(a)
|
Financial Statements and Schedules:
|
(b)
|
Exhibits:
|
Exhibit Number
|
|
Description
|
2.1**
|
|
Purchase and Sale Agreement, dated March 28, 2013, by and among Chesapeake Exploration, L.L.C., Arcadia Resources, L.P., Jamestown Resources, L.L.C., Larchmont Resources, L.L.C. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 2.1 of the Quarterly Report on Form 10-Q filed with the SEC on May 2, 2013. File No. 001-35211).
|
|
|
|
2.2**
|
|
Amendment to Purchase and Sale Agreement, dated as of June 7, 2013, by and among Chesapeake Exploration, L.L.C., Arcadia Resources, L.P., Jamestown Resources, L.L.C., Larchmont Resources, L.L.C. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on June 12, 2013. File No. 001-35211).
|
|
|
|
2.3**
|
|
Purchase and Sale Agreement, dated April 19, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.2 of the Quarterly Report on Form 10-Q filed with the SEC on May 2, 2013. File No. 001-35211).
|
|
|
|
2.4
|
|
First Amendment of Purchase and Sale Agreement, dated as of June 11, 2013 but effective as of June 5, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.2 of the Current Report on Form 8-K filed with the SEC on June 12, 2013. File No. 001-35211).
|
|
|
|
2.5
|
|
Second Amendment of Purchase and Sale Agreement, dated as of June 27, 2013 but effective as of June 5, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on July 3, 2013. File No. 001-35211).
|
|
|
|
2.6
|
|
Third Amendment of Purchase and Sale Agreement, dated as of July 11, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on July 17, 2013. File No. 001-35211).
|
|
|
|
2.7
|
|
Fourth Amendment of Purchase and Sale Agreement, dated as of July 31, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on August 6, 2013. File No. 001-35211).
|
|
|
|
2.8
|
|
Fifth Amendment of Purchase and Sale Agreement, dated as of August 29, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on September 3, 2013. File No. 001-35211).
|
|
|
|
2.9
|
|
Sixth Amendment of Purchase and Sale Agreement, dated as of September 20, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on September 23, 2013. File No. 001-35211).
|
|
|
|
2.10
|
|
Letter Agreement to Purchase and Sale Agreement, dated September 30, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on October 4, 2013. File No. 001-35211).
|
|
|
|
2.11
|
|
Purchase and Sale Agreement, dated as of July 2, 2013, by and among Newfield Exploration Mid-Continent Inc. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on August 12, 2013. File No. 001-35211).
|
|
|
|
2.12**
|
|
Agreement of Sale and Purchase, dated September 4, 2013, by and among Gastar Exploration USA, Inc., Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on October 28, 2013. File No. 001-35211).
|
|
|
|
2.13
|
|
Amended and Restated Plan of Arrangement Under Section 193 of the Business Corporations Act (Alberta), effective as of November 14, 2013 (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on November 15, 2013. File No. 001-32714).
|
|
|
|
Exhibit Number
|
|
Description
|
2.14
|
|
Agreement and Plan of Merger, dated as of January 31, 2014, among Gastar Exploration, Inc. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on January 31, 2014. File No. 000-55138).
|
|
|
|
3.1
|
|
Amended and Restated Certificate of Incorporation of Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) (incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K filed with the SEC on October 28, 2013. File No. 001-35211).
|
|
|
|
3.2
|
|
Second Amended and Restated Bylaws of Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) (incorporated by reference to Exhibit 3.2 of the Current Report on Form 8-K filed with the SEC on October 28, 2013. File No. 001-35211).
|
|
|
|
3.3
|
|
Certificate of Merger (incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K filed with the SEC on January 31, 2014. File No. 000-55138).
|
|
|
|
3.4
|
|
Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.3 of Gastar Exploration USA, Inc.'s Form 8A filed on June 20, 2011. File No. 001-35211).
|
|
|
|
3.5
|
|
Certificate of Designation of Rights and Preferences of 10.75% Series B Cumulative Preferred Stock (incorporated by reference to Exhibit 3.4 of the Form 8-A filed with the SEC on November 1, 2013. File No. 001-35211).
|
|
|
|
4.1
|
|
Indenture, dated as of May 15, 2013, among Gastar Exploration USA, Inc., the Subsidiary Guarantors (as defined therein) and Wells Fargo Bank, National Association, and any and all successors thereto, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed with the SEC on May 15, 2013. File No. 001-35211).
|
|
|
|
4.2
|
|
Form of 8 5/8% Senior Secured Notes due 2018 (incorporated by reference to Exhibit A to Exhibit 4.1 of the Current Report on Form 8-K filed with the SEC on May 15, 2013. File No. 001-35211).
|
|
|
|
10.1
|
|
Amended and Restated Collateral Agency and Intercreditor Agreement dated August 27, 2012, by and among BP Energy Company, Shell Energy North America (US), L.P., Gastar Exploration USA, Inc., Gastar Exploration Ltd., each of the Guarantors party thereto and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q filed with the SEC on November 7, 2012. File No. 001-35211).
|
|
|
|
10.2
|
|
Intercreditor Agreement, dated as of June 7, 2013, among Gastar Exploration USA, Inc., certain subsidiaries party thereto, Wells Fargo Bank, National Association, as First Priority Agent and Wells Fargo Bank, National Association, as Second Priority Agent (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8-K filed with the SEC on June 12, 2013. File No. 001-35211).
|
|
|
|
10.3
|
|
Second Amended and Restated Credit Agreement, dated as of June 7, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on June 12, 2013. File No. 001-35211).
|
|
|
|
10.4
|
|
Waiver, Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of July 31, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q filed with the SEC on August 5, 2013. File No. 001-35211).
|
|
|
|
10.5
|
|
Agreement and Amendment No. 2 to Second Amended and Restated Credit Agreement, dated as of
October 18, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on October 22, 2013. File No. 001-35211).
|
|
|
|
10.6
|
|
Agreement, Waiver and Amendment No. 3 to Second Amended and Restated Credit Agreement, dated as of March 12, 2014, among the Company, the Guarantors party thereto, the Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender, and as Issuing Lender (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on March 13, 2014. File No. 001-35211).
|
|
|
|
Exhibit Number
|
|
Description
|
10.7
|
|
Master Assignment, Agreement and Amendment No. 4 to Second Amended and Restated Credit Agreement, dated as of August 13, 2014, among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender, Issuing Lender, and Lender, IBERIABANK as Lender, Comerica Bank as Lender, and ING Capital LLC as Lender (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on August 15, 2014. File No. 001-35211).
|
|
|
|
10.8†
|
|
Master Assignment, Agreement and Amendment No. 5 to Second Amended and Restated Credit Agreement, dated as of March 9, 2015, among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender, Issuing Lender, and Lender, IBERIABANK as Lender, Comerica Bank as Lender, ING Capital LLC as Lender and Barclays Bank PLC as Lender.
|
|
|
|
10.9
|
|
Form of the Final Settlement Agreement between Chesapeake Exploration, L.L.C., Chesapeake Energy Corporation, Gastar Exploration Ltd., Gastar Exploration Texas, LP and Gastar Exploration Texas, LLC, effective March 28, 2013 (incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q filed with the SEC on May 2, 2013. File No. 001-35211).
|
|
|
|
10.10
|
|
First Lien Guaranty Agreement, dated as of December 18, 2013, between Gastar Exploration, Inc. and Wells Fargo Bank, National Association, as Collateral Agent (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on December 24, 2013. File No. 001-35211).
|
|
|
|
10.11
|
|
Parent Guarantee, dated as of December 23, 2013, of Gastar Exploration, Inc. (incorporated by reference to Exhibit 10.2 of the Current Report on Form 10-K filed with the SEC on December 24, 2013. File No. 001-35211).
|
|
|
|
10.12
|
|
Purchase and Sale Agreement, dated September 21, 2010, by and between Gastar Exploration USA, Inc. and Atinum Marcellus I LLC (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on September 24, 2010. File No. 001-32714).
|
|
|
|
10.13
|
|
Form of Participation Agreement (incorporated by reference to Exhibit 2.2 of the Current Report on Form 8-K filed with the SEC on September 24, 2010. File No. 001-32714).
|
|
|
|
10.14
|
|
Guarantee Agreement, dated November 7, 2013, by and between Gastar Exploration Ltd. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on November 7, 2013. File No. 001-35211).
|
|
|
|
10.15*
|
|
Employment Agreement dated March 23, 2005 by and among First Sourcenergy Wyoming, Inc., Gastar Exploration Ltd. and J. Russell Porter (incorporated by reference to Exhibit 10.2 of the Registration Statement on Form S-1, filed with the SEC on August 12, 2005. Registration No. 333-127498).
|
|
|
|
10.16*
|
|
First Amendment to Employment Agreement entered into by and between Gastar Exploration, Ltd, Gastar Exploration USA, Inc., f/k/a First Sourcenergy Wyoming, Inc., and J. Russell Porter as of July 25, 2008 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on July 28, 2008. File No. 001-32714).
|
|
|
|
10.17*
|
|
Second Amendment to Employment Agreement entered into by and between Gastar Exploration Ltd., Gastar Exploration USA, Inc. and J. Russell Porter as of February 3, 2011 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on February 7, 2011. File No. 001-32714).
|
|
|
|
10.18*
|
|
Employment Agreement dated April 26, 2005 by and among First Sourcenergy Wyoming, Inc., Gastar Exploration Ltd. and Michael A Gerlich (incorporated by reference to Exhibit 10.3 of the Registration Statement on Form S-1, filed with the SEC on August 12, 2005. Registration No. 333-127498).
|
|
|
|
10.19*
|
|
First Amendment to Employment Agreement entered into by and between Gastar Exploration, Ltd, Gastar Exploration USA, Inc., f/k/a First Sourcenergy Wyoming, Inc., and Michael A. Gerlich as of July 25, 2008 (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8-K filed with the SEC on July 28, 2008. File No. 001-32714).
|
|
|
|
10.20*
|
|
Second Amendment to Employment Agreement entered into by and between Gastar Exploration Ltd., Gastar Exploration USA, Inc. and Michael A. Gerlich as of April 10, 2012 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on April 12, 2012. File No. 001-32714).
|
|
|
|
10.21*†
|
|
Third Amendment to Employment Agreement entered into by and between Gastar Exploration Inc. and Michael A. Gerlich as of March 10, 2015.
|
|
|
|
10.22*
|
|
Employment Agreement, dated as of June 19, 2014, between Gastar Exploration Inc. and Michael McCown (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on June 23, 2014. File No. 001-35211).
|
|
|
|
Exhibit Number
|
|
Description
|
10.23*
|
|
Form of Gastar Officer Stock Option Grant (incorporated by reference to Exhibit 10.10 of the Annual Report on Form 10-K for the fiscal year ended December 31, 2005 filed with the SEC on March 31, 2006. File No. 001-32714).
|
|
|
|
10.24*†
|
|
Form of Gastar Exploration Inc. Performance Unit Agreement (graded vesting).
|
|
|
|
10.25*†
|
|
Form of Gastar Exploration Inc. Performance Unit Agreement (cliff vesting).
|
|
|
|
10.26*
|
|
Gastar Exploration Inc. Long-Term Incentive Plan, adopted January 31, 2014 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on January 31, 2014. File No. 000-55138).
|
|
|
|
10.27*
|
|
Amended and Restated Gastar Exploration Inc. Long-Term Incentive Plan (incorporated by reference to Annex A of the Definitive Proxy Statement on Schedule 14A filed with the SEC on May 2, 2014. File No. 001-35211).
|
|
|
|
10.28*
|
|
Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on September 15, 2014. File No. 001-35211).
|
|
|
|
10.29*
|
|
Gastar Exploration Ltd. Employee Change of Control Severance Plan effective as of March 23, 2007 and as amended and restated effective February 15, 2008 (incorporated by reference to Exhibit 10.18 of the Annual Report on Form 10-K for the fiscal year ended December 31, 2007, filed with the SEC on March 17, 2008. File No. 001-32714).
|
|
|
|
10.30*
|
|
First Amendment to Amended and Restated Gastar Exploration Ltd. Employee Change of Control Severance Plan, dated April 11, 2012 and effective January 1, 2012 (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8-K filed with the SEC on April 12, 2012. File No. 001-35211).
|
|
|
|
10.31*
|
|
Second Amendment to Amended and Restated Gastar Exploration Inc. Employee Change of Control Severance Plan, dated March 12, 2014 and effective March 1, 2014 (incorporated by reference to Exhibit 10.27 of the Annual Report on Form 10-K filed with SEC on March 13, 2014. File No. 001-35211).
|
|
|
|
10.32*†
|
|
Third Amendment to Amended and Restated Gastar Exploration Inc. Employee Change of Control Severance Plan, dated March 10, 2015.
|
|
|
|
10.33*
|
|
Gastar Exploration Ltd. Annual Bonus Plan (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed with the SEC on August 8, 2011. File No. 001-32714).
|
|
|
|
10.34*
|
|
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of the Registration Statement on Form S-8 filed with the SEC on December 4, 2006. File No. 333-139112).
|
|
|
|
10.35
|
|
Settlement Agreement, dated March 12, 2014, by Gastar Exploration Inc., Kleinheinz Capital Partners, Inc., Global Undervalued Securities Master Fund, L.P., John B. Kleinheinz and Fred N. Reynolds (incorporated by reference to Exhibit 10.30 of the Annual Report on Form 10-K filed with the SEC on March 13, 2014. File No. 001-35211).
|
|
|
|
12.1†
|
|
Computation of Ratio of Earnings to Fixed Charges
|
|
|
|
12.2†
|
|
Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
|
|
|
|
21.1†
|
|
Subsidiaries of Gastar Exploration Inc.
|
|
|
|
23.1†
|
|
Consent of BDO USA, LLP
|
|
|
|
23.2†
|
|
Consent of Wright & Company, Inc.
|
|
|
|
31.1†
|
|
Certification of Chief Executive Officer of Gastar Exploration Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
31.2†
|
|
Certification of Chief Financial Officer of Gastar Exploration Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
32.1††
|
|
Certification of Chief Executive Officer and Chief Financial Officer of Gastar Exploration Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
99.1††
|
|
Report of Wright & Company, Inc. dated January 19, 2015.
|
|
|
|
/s/ J. RUSSELL PORTER
|
|
J. Russell Porter, President and Chief Executive Officer
|
|
(Duly authorized officer and principal executive officer)
|
|
March 12, 2015
|
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ J. RUSSELL PORTER
|
|
President, Chief Executive Officer, Chief Operating Officer (principal executive officer) and Director
|
|
March 12, 2015
|
J. Russell Porter
|
|
|
|
|
|
|
|
|
|
/s/ MICHAEL A. GERLICH
|
|
Senior Vice President, Chief Financial Officer and Corporate Secretary (principal financial and accounting officer)
|
|
March 12, 2015
|
Michael A. Gerlich
|
|
|
|
|
|
|
|
|
|
/s/ JOHN M. SELSER SR.
|
|
Chairman of the Board
|
|
March 12, 2015
|
John M. Selser Sr.
|
|
|
|
|
|
|
|
|
|
/s/ JOHN H. CASSELS
|
|
Director
|
|
March 12, 2015
|
John H. Cassels
|
|
|
|
|
|
|
|
|
|
/s/ RANDOLPH C. COLEY
|
|
Director
|
|
March 12, 2015
|
Randolph C. Coley
|
|
|
|
|
|
|
|
|
|
/s/ STEPHEN A. HOLDITCH
|
|
Director
|
|
March 12, 2015
|
Stephen A. Holditch
|
|
|
|
|
|
|
|
|
|
/s/ ROBERT D. PENNER
|
|
Director
|
|
March 12, 2015
|
Robert D. Penner
|
|
|
|
|
|
|
|
|
|
/s/ JERRY R. SCHUYLER
|
|
Director
|
|
March 12, 2015
|
Jerry R. Schuyler
|
|
|
|
|
Lenders:
|
Pro Rata Share of existing Borrowing Base
|
Pro Rata Share of Borrowing Base
*
|
Wells Fargo Bank, National Association
|
$44,750,000
|
$50,000,000
|
Comerica Bank
|
$36,250,000
|
$40,000,000
|
IBERIABANK
|
$35,000,000
|
$35,000,000
|
ING Capital LLC
|
$29,000,000
|
$40,000,000
|
Barclays Bank PLC
|
$0
|
$35,000,000
|
Total:
|
$145,000,000
|
$200,000,000
|
|
Utilization Level*
|
Reference Rate Advances
|
Eurodollar Rate Advances
|
Commitment Fee Rate
|
Level I
|
Less than 25%
|
1.00%
|
2.00%
|
0.50%
|
Level II
|
Greater than or equal to 25% but less than 50%
|
1.25%
|
2.25%
|
0.50%
|
Level III
|
Greater than or equal to 50% but less than 75%.
|
1.50%
|
2.50%
|
0.50%
|
Level IV
|
Greater than or equal to 75% but less than 90%
|
1.75%
|
2.75%
|
0.50%
|
Level V
|
Greater than or equal to 90
|
2.00%
|
3.00%
|
0.50%
|
Lenders:
|
Commitments
|
Percentage of Total
|
|||
Wells Fargo Bank, National Association
|
|
$125,000,000
|
|
25.00
|
%
|
Comerica Bank
|
|
$100,000,000
|
|
20.00
|
%
|
IBERIABANK
|
|
$87,500,000
|
|
17.50
|
%
|
ING Capital LLC
|
|
$100,000,000
|
|
20.00
|
%
|
Barclays Bank PLC
|
|
$87,500,000
|
|
17.50
|
%
|
Total:
|
|
$500,000,000
|
|
100.000000
|
%
|
(a)
|
The consolidated Indebtedness of the Borrower
|
(b)
|
Borrower’s consolidated Available Cash $
|
(c)
|
Borrower’s consolidated EBITDAX for four fiscal
|
1
|
Calculated as of each fiscal quarter end, commencing with the quarter ending June 30, 2013.
|
2
|
In accordance with the Credit Agreement, EBITDAX shall be subject to pro forma adjustments for acquisitions and asset sales assuming that such transactions had occurred on the first day of the determination period.
|
3
|
Items (ii) - (viii) shall be included to the extent deducted in determining Consolidated Net Income.
|
4
|
“non-cash charges” shall include any provision for the reduction in the carrying value of assets recorded in accordance with GAAP and including non-cash charges resulting from the requirements of ASC 410, 718 and 815.
|
5
|
“non-cash items of income” shall include non-cash income resulting from the requirements of ASC 410, 718 and 815.
|
6
|
Use (a) 4.50 for the fiscal quarter ending June 30, 2013, (b) 4.25 for the fiscal quarter ending September 30, 2013, (c) 4.00 for each fiscal quarter ending on or after December 31, 2013 but prior to March 31, 2015, (d) 5.25 for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016, (e) 5.00 for the fiscal quarter ending on September 30, 2016, (f) 4.75 for the fiscal quarter ending on December 31, 2016, (g) 4.25 for the fiscal quarter ending on March 31, 2017, and (h) 4.00 for each fiscal quarter ending on or after June 30, 2017.
|
a.
consolidated EBITDAX =
See I(b) above
=
|
$
|
(b) consolidated Interest Expense =
See I(c)(ii) above
|
$
|
7
|
Calculated as of each fiscal quarter end, commencing with the quarter ending June 30, 2013.
|
8
|
Use (a) 2.50 for each fiscal quarter ending on or after June 30, 2013 but prior to March 31, 2015, (b) 2.00 for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016, and (c) 2.50 for each fiscal quarter ending on or after March 31, 2016.
|
(a) consolidated current assets
10
|
$
|
(b) consolidated current liabilities
11
|
$
|
9
|
Calculated as of each fiscal quarter end, commencing with the quarter ending June 30, 2013.
|
10
|
“
current assets
”
shall not include non-cash derivative current assets arising from any Hedge Contract.
|
11
|
“
current liabilities
”
shall not include current maturities in respect of the Obligations, both principal and interest, non-cash derivative current liabilities arising from any Hedge Contract, and current maturities of Indebtedness of the Borrower under the Second Lien Notes.
|
(a)
The consolidated secured Indebtedness of the Borrower
(excluding all Second Lien Debt) as of such fiscal
quarter end
|
$
|
b.
Consolidated Available Cash of the Borrower as of such fiscal quarter end=
|
$
|
c.
An amount equal to the lesser of (b) and $5,000,000 =
|
$
|
d.
An amount equal to (a) minus (c) =
|
$
|
e.
consolidated EBITDAX =
See I(b) above
=
|
$
|
12
|
Calculated as of each fiscal quarter end, commencing with the quarter ending March 31, 2015.
|
13
|
Use (a) 2.25 for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016, and (b) 2.00 for each fiscal quarter ending on or after June 30, 2016.
|
14
|
The Borrower shall no longer need to comply with this ratio commencing with the first fiscal quarter end occurring after June 30, 2016 for which the Leverage Ratio in I above is equal to or less than 4.00 to 1.00
|
Performance Delta (1)
|
Payout as a % of the Number of Initial Performance Units for which Measurement Date is Occurring
|
25 or Greater
|
200%
|
20
|
180%
|
15
|
160%
|
10
|
140%
|
5
|
120%
|
0
|
100%
|
-5
|
80%
|
-10
|
60%
|
-15
|
40%
|
-20
|
20%
|
-25 or Less
|
0%
|
Measurement Date
|
Number of Initial Performance Units Measured
|
[
date
]
|
[
number
] Units (100% of the total Units)
|
Performance Delta
|
Payout as a % of the Number of Initial Performance Units for which Measurement Date is Occurring
|
Payout if Share Price Appreciation During the Period Is Not Positive
|
30 or Greater
|
200%
|
100%
|
25
|
180%
|
90%
|
20
|
160%
|
80%
|
15
|
140%
|
70%
|
10
|
120%
|
60%
|
0
|
100%
|
50%
|
-5
|
75%
|
38%
|
-10
|
50%
|
25%
|
Less than -10.01
|
0%
|
0%
|
Position of Covered Employee
|
Severance Period (in years)
|
Bonus Target
|
CEO
|
3.00
|
89%
**
|
CFO
|
2.50
|
88%
**
|
COO
|
2.50
|
88%
**
|
VP
|
2.00
|
25%
|
Director
|
1.50
|
25%
|
Manager
|
1.25
|
0%
|
Supervisor
|
1.00
|
0%
|
Staff
|
0.75
|
0%
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
|
(in thousands, except ratios)
|
||||||||||||||||||
Earnings (Loss):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss)
|
|
$
|
50,953
|
|
|
$
|
49,342
|
|
|
$
|
(153,791
|
)
|
|
$
|
(740
|
)
|
|
$
|
(13,264
|
)
|
Add: Fixed Charges
|
|
54,329
|
|
|
31,026
|
|
|
13,228
|
|
|
2,558
|
|
|
853
|
|
|||||
Add: Amortization of capitalized interest
|
|
594
|
|
|
883
|
|
|
7,119
|
|
|
460
|
|
|
178
|
|
|||||
Less: Interest capitalized
|
|
(4,347
|
)
|
|
(3,284
|
)
|
|
(1,946
|
)
|
|
(818
|
)
|
|
(633
|
)
|
|||||
Net income (loss), as adjusted
|
|
$
|
101,529
|
|
|
$
|
77,967
|
|
|
$
|
(135,390
|
)
|
|
$
|
1,460
|
|
|
$
|
(12,866
|
)
|
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total interest expensed
|
|
$
|
28,851
|
|
|
$
|
14,130
|
|
|
$
|
1,992
|
|
|
$
|
682
|
|
|
$
|
500
|
|
Amortization of financing costs
|
|
3,067
|
|
|
2,322
|
|
|
224
|
|
|
248
|
|
|
283
|
|
|||||
Estimated interest portion of operating leases
|
|
220
|
|
|
146
|
|
|
124
|
|
|
53
|
|
|
70
|
|
|||||
Dividends on preferred stock
(1)
|
|
22,191
|
|
|
14,428
|
|
|
10,888
|
|
|
1,575
|
|
|
—
|
|
|||||
Total fixed charges
|
|
$
|
54,329
|
|
|
$
|
31,026
|
|
|
$
|
13,228
|
|
|
$
|
2,558
|
|
|
$
|
853
|
|
Fixed Charges and Fixed Charge Ratio:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings (deficiency) to fixed charges
|
|
$
|
47,200
|
|
|
$
|
46,941
|
|
|
$
|
(148,618
|
)
|
|
$
|
(1,098
|
)
|
|
$
|
(13,719
|
)
|
Earnings to fixed charges ratio
|
|
1.9x
|
|
|
2.5x
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Computed as the dividend requirement divided by (1 minus the statutory tax rate).
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
|
(in thousands, except ratios)
|
||||||||||||||||||
Earnings (Loss):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss)
|
|
$
|
50,953
|
|
|
$
|
49,342
|
|
|
$
|
(153,791
|
)
|
|
$
|
(740
|
)
|
|
$
|
(13,264
|
)
|
Add: Fixed Charges
|
|
32,138
|
|
|
16,598
|
|
|
2,340
|
|
|
983
|
|
|
853
|
|
|||||
Add: Amortization of capitalized interest
|
|
594
|
|
|
883
|
|
|
7,119
|
|
|
460
|
|
|
178
|
|
|||||
Less: Interest capitalized
|
|
(4,347
|
)
|
|
(3,284
|
)
|
|
(1,946
|
)
|
|
(818
|
)
|
|
(633
|
)
|
|||||
Net income (loss), as adjusted
|
|
$
|
79,338
|
|
|
$
|
63,539
|
|
|
$
|
(146,278
|
)
|
|
$
|
(115
|
)
|
|
$
|
(12,866
|
)
|
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total interest expensed
|
|
$
|
28,851
|
|
|
$
|
14,130
|
|
|
$
|
1,992
|
|
|
$
|
682
|
|
|
$
|
500
|
|
Amortization of financing costs
|
|
3,067
|
|
|
2,322
|
|
|
224
|
|
|
248
|
|
|
283
|
|
|||||
Estimated interest portion of operating leases
|
|
220
|
|
|
146
|
|
|
124
|
|
|
53
|
|
|
70
|
|
|||||
Total fixed charges
|
|
$
|
32,138
|
|
|
$
|
16,598
|
|
|
$
|
2,340
|
|
|
$
|
983
|
|
|
$
|
853
|
|
Dividends on preferred stock
(1)
|
|
22,191
|
|
|
14,428
|
|
|
10,888
|
|
|
1,575
|
|
|
—
|
|
|||||
Total fixed charges and dividends
|
|
$
|
54,329
|
|
|
$
|
31,026
|
|
|
$
|
13,228
|
|
|
$
|
2,558
|
|
|
$
|
853
|
|
Fixed Charges and Fixed Charge Ratio:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings (deficiency) to fixed charges
|
|
$
|
25,009
|
|
|
$
|
32,513
|
|
|
$
|
(159,506
|
)
|
|
$
|
(2,673
|
)
|
|
$
|
(13,719
|
)
|
Earnings to fixed charges ratio
|
|
1.5x
|
|
|
2.0x
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Computed as the dividend requirement divided by (1 minus the statutory tax rate).
|
1.
|
I have reviewed this Annual Report on Form 10-K of Gastar Exploration Inc. (the “Registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
|
4.
|
The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
|
5.
|
The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
|
/
S
/ J. RUSSELL PORTER
|
J. Russell Porter
|
Principal Executive Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K of Gastar Exploration Inc. (the “Registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
|
4.
|
The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
|
5.
|
The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
|
/
S
/ MICHAEL A. GERLICH
|
Michael A. Gerlich
|
Principal Financial Officer
|
/S/ J. RUSSELL PORTER
|
J. Russell Porter
|
Principal Executive Officer
|
/S/ MICHAEL A. GERLICH
|
Michael A. Gerlich
|
Principal Financial Officer
|
Gastar Exploration Inc.
SEC Parameters
|
Proved Developed
|
Total
Proved Developed
(PDP & PDNP)
|
Proved
Undeveloped
(PUD)
|
Total
Proved
(PDP, PDNP & PUD)
|
|
Producing
(PDP)
|
Nonproducing (PDNP)
|
||||
Net Reserves to the
|
|
|
|
|
|
Evaluated Interests
|
|
|
|
|
|
Oil, Mbbl:
|
6,967.091
|
1.183
|
6,968.274
|
21,667.590
|
28,635.863
|
Gas, MMcf:
|
114,100.898
|
462.841
|
114,563.750
|
172,441.188
|
287,004.969
|
NGL, Mbbl:
|
10,705.684
|
20.571
|
10,726.256
|
14,866.378
|
25,592.637
|
Gas Equivalent, MMcfe:
|
220,137.548
|
593.365
|
220,730.930
|
391,644.996
|
612,375.969
|
(1 bbl = 6 Mcfe)
|
|
|
|
|
|
Cash Flow (BTAX), M$
|
|
|
|
|
|
Undiscounted:
|
764,796.750
|
149.521
|
764,945.875
|
1,430,027.000
|
2,194,973.000
|
Discounted at 10%
|
|
|
|
|
|
Per Annum:
|
444,764.875
|
-483.212
|
444,281.688
|
544,404.250
|
988,685.625
|
|
|
Very truly yours,
|
|
|
|
Wright & Company, Inc.
|
|
TX Reg. No. F-12302
|
|
|
|
|
|
By:
|
/s/ D. Randall Wright
|
|
D. Randall Wright
|
|
President
|