10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________

FORM 10-Q

____________________________________________________

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED March 31, 2015

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM                    TO                    

Commission File Number: 001-35211

____________________________________________________

GASTAR EXPLORATION INC.

(Exact name of registrant as specified in its charter)

____________________________________________________

Delaware	38-3531640
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1331 Lamar Street, Suite 650
Houston, Texas	77010
(Address of principal executive offices)	(Zip Code)

(713) 739-1800

(Registrant’s telephone number, including area code)

____________________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    

Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	ý
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   

Yes o No ý

The total number of outstanding common shares, $0.001 par value per share, as of May 4, 2015 was 81,145,775.

GASTAR EXPLORATION INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31,2015

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	5
	Gastar Exploration Inc. Condensed Consolidated Balance Sheets as of March 31, 2015 (unaudited) and December 31, 2014	5
	Gastar Exploration Inc. Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014 (unaudited)	7
	Gastar Exploration Inc. Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014 (unaudited)	8
	Notes to the Condensed Consolidated Financial Statements (unaudited)	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	35
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Mine Safety Disclosure	37
Item 5.	Other Information	37
Item 6.	Exhibits	37
SIGNATURES		38

2

On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” On January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc., its direct subsidiary, as part of a reorganization to eliminate Gastar Exploration, Inc.’s holding company corporate structure. Pursuant to the merger agreement, shares of Gastar Exploration, Inc.’s common stock were converted into an equal number of shares of common stock of Gastar Exploration USA, Inc., and Gastar Exploration USA, Inc. changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc. owns and continues to conduct Gastar Exploration, Inc.’s business in substantially the same manner as was being conducted prior to the merger.

Unless otherwise indicated or required by the context, (i) for any date or period prior to the January 31, 2014 merger described above,“Gastar,” the “Company,” “we,” “us,” “our” and similar terms refer collectively to Gastar Exploration, Inc.(formerly known as Gastar Exploration Ltd.) and its subsidiaries, including Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.), and for any date or period after January 31, 2014, such terms refer collectively to Gastar Exploration Inc. and its subsidiaries, (ii) “Gastar USA” refers to Gastar Exploration USA, Inc., which until January 31, 2014 was a first-tier subsidiary of Gastar Exploration, Inc. and its primary operating company, (iii) “Parent” refers to Gastar Exploration, Inc., (iv) all dollar amounts appearing in this Form 10-Q are stated in United States dollars (“U.S. dollars”) unless otherwise noted and (v) all financial data included in this Form 10-Q have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).

General information about us can be found on our website at www.gastar.com. The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the U.S. Securities and Exchange Commission (“SEC”), as well as any amendments and exhibits to those reports, will be available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our U.S. filings.

3

Glossary of Terms

AMI	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
Bbl	Barrel of oil, condensate or NGLs
Bbl/d	Barrels of oil, condensate or NGLs per day
Bcf	One billion cubic feet of natural gas
Bcfe	One billion cubic feet of natural gas equivalent, determined using the ratio ofsix thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs
Boe	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
Boe/d	Barrels of oil equivalent per day
Btu	British thermal unit, typically used in measuring natural gas energy content
CRP	Central receipt point
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
Gross acres	Refers to acres in which we own a working interest
Gross wells	Refers to wells in which we have a working interest
MBbl	One thousand barrels of oil, condensate or NGLs
MBbl/d	One thousand barrels of oil, condensate or NGLs per day
MBoe	One thousand barrels of oil equivalent, calculated on the assumed energy equivalent basis of 6 MMcf of natural gas per MBoe
MBoe/d	One thousand barrels of oil equivalent per day
Mcf	One thousand cubic feet of natural gas
Mcf/d	One thousand cubic feet of natural gas per day
Mcfe	One thousand cubic feet of natural gas equivalent, calculated on the assumed energy equivalent basis of 1/6 of a barrel of oil per Mcf
MMBtu/d	One million British thermal units per day
MMcf	One million cubic feet of natural gas
MMcf/d	One million cubic feet of natural gas per day
MMcfe	One million cubic feet of natural gas equivalent, calculated on the assumed energy equivalent basis of 1/6 of a barrel of oil per Mcf
MMcfe/d	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 Mcf
Net acres	Refers to our proportionate interest in acreage resulting from our ownership in gross acreage
Net wells	Refers to gross wells multiplied by our working interest in such wells
NGLs	Natural gas liquids
NYMEX	New York Mercantile Exchange
PBU	Performance based unit
psi	Pounds per square inch
U.S.	United States

4

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2015			December 31, 2014
	(Unaudited)
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12,143		$	11,008
Accounts receivable, net of allowance for doubtful accounts of $0, respectively	18,187			30,841
Commodity derivative contracts	18,815			19,687
Prepaid expenses	1,808			2,083
Total current assets	50,953			63,619
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	120,341			128,274
Proved properties	1,174,581			1,124,367
Total oil and natural gas properties	1,294,922			1,252,641
Furniture and equipment	3,013			3,010
Total property, plant and equipment	1,297,935			1,255,651
Accumulated depreciation, depletion and amortization	(577,822		)	(563,351		)
Total property, plant and equipment, net	720,113			692,300
OTHER ASSETS:
Commodity derivative contracts	13,404			7,815
Deferred charges, net	2,682			2,586
Advances to operators and other assets	2,770			9,474
Total other assets	18,856			19,875
TOTAL ASSETS	$	789,922		$	775,794
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	19,780		$	28,843
Revenue payable	8,258			9,122
Accrued interest	10,550			3,528
Accrued drilling and operating costs	6,598			5,977
Advances from non-operators	1,025			1,820
Commodity derivative contracts	56			—
Commodity derivative premium payable	2,472			2,481
Asset retirement obligation	84			82
Other accrued liabilities	1,975			3,175
Total current liabilities	50,798			55,028
LONG-TERM LIABILITIES:
Long-term debt	380,916			360,303
Commodity derivative contracts	340			—
Commodity derivative premium payable	4,809			4,702
Asset retirement obligation	5,676			5,475
Total long-term liabilities	391,741			370,480
Commitments and contingencies (Note 11)
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 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share	41			41
Series B Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 2,140,000 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share	21			21
Common stock, par value $0.001 per share; 275,000,000 shares authorized; 80,145,775 and 78,632,810 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively	78			78
Additional paid-in capital	568,541			568,440
Accumulated deficit	(221,298		)	(218,294		)
Total stockholders’ equity	347,383			350,286
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	789,922		$	775,794

5

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2015			2014
	(in thousands, except share and per share data)
REVENUES:
Oil and condensate	$	15,353		$	16,778
Natural gas	6,700			15,419
NGLs	2,096			6,644
Total oil, condensate, natural gas and NGLs revenues	24,149			38,841
Gain (loss) on commodity derivatives contracts	10,223			(6,514		)
Total revenues	34,372			32,327
EXPENSES:
Production taxes	840			1,894
Lease operating expenses	6,019			4,044
Transportation, treating and gathering	497			625
Depreciation, depletion and amortization	14,471			12,382
Accretion of asset retirement obligation	125			122
General and administrative expense	4,248			4,763
Total expenses	26,200			23,830
INCOME FROM OPERATIONS	8,172			8,497
OTHER INCOME (EXPENSE):
Interest expense	(7,561		)	(6,891		)
Investment income and other	3			7
Foreign transaction loss	—			(2		)
INCOME BEFORE PROVISION FOR INCOME TAXES	614			1,611
Provision for income taxes	—			—
NET INCOME	614			1,611
Dividends on preferred stock	(3,618		)	(3,576		)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(3,004	)	$	(1,965	)
NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic	$	(0.04	)	$	(0.03	)
Diluted	$	(0.04	)	$	(0.03	)
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic	77,114,826			58,204,532
Diluted	77,114,826			58,204,532

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	614		$	1,611
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	14,471			12,382
Stock-based compensation	1,526			1,533
Mark to market of commodity derivatives contracts:
Total (gain) loss on commodity derivatives contracts	(10,223		)	6,514
Cash settlements of matured commodity derivatives contracts, net	5,277			(3,015		)
Cash premiums paid for commodity derivatives contracts	—			(71		)
Amortization of deferred financing costs	822			733
Accretion of asset retirement obligation	125			122
Settlement of asset retirement obligation	—			(257		)
Changes in operating assets and liabilities:
Accounts receivable	14,279			(750		)
Prepaid expenses	275			81
Accounts payable and accrued liabilities	5,957			4,169
Net cash provided by operating activities	33,123			23,052
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties	(46,121		)	(25,812		)
Advances to operators	(1,753		)	(5,001		)
Acquisition of oil and natural gas properties - refund	—			4,209
Proceeds from (payment related to) sale of oil and natural gas properties	2,008			(341		)
(Payments to) proceeds from non-operators	(795		)	4,930
Purchase of furniture and equipment	(3		)	(148		)
Net cash used in investing activities	(46,664		)	(22,163		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	25,000			—
Repayment of revolving credit facility	(5,000		)	—
Proceeds from issuance of preferred stock, net of issuance costs	—			886
Dividends on preferred stock	(3,618		)	(3,576		)
Deferred financing charges	(281		)	(135		)
Tax withholding related to restricted stock and PBU vestings	(1,425		)	(3,544		)
Net cash provided by (used in) financing activities	14,676			(6,369		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,135			(5,480		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	11,008			32,393
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	12,143		$	26,913

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

GASTAR EXPLORATION INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Description of Business

Gastar Exploration Inc. (the “Company” or “Gastar,” and before January 31, 2014, “Gastar USA”) is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Gastar’s principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expects to test other prospective formations on the same acreage, including the Woodford Shale and the Meramec Shale (middle Mississippi Lime), which Gastar refers to as the Stack Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled and completed its first successful dry gas Utica Shale/Point Pleasant well on its acreage.

On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” At December 31, 2013, Gastar Exploration, Inc. was a holding company and substantially all of its operations were conducted through, and substantially all of its assets were held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Subsequently, on January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc. as part of a reorganization to eliminate the holding company corporate structure. Pursuant to the merger agreement, shares of Gastar Exploration, Inc.'s common stock were converted into an equal number of shares of common stock of Gastar Exploration USA, Inc. and Gastar Exploration USA, Inc. changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc. owns and continues to conduct business in substantially the same manner as was being conducted by Gastar Exploration, Inc. and its subsidiaries prior to the merger. All references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration Inc. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) and its wholly-owned subsidiaries and all references to “Parent” refer solely to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.).

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2014 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material item included in those notes has changed except as a result of normal transactions in the interim or as disclosed within this report.

The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows.

The unaudited interim condensed consolidated financial statements of the Company include the consolidated accounts of all of its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.

Certain reclassifications of prior year balances have been made to conform to the current year presentation; these reclassifications have no impact on net income (loss).

The results of operations for the three months endedMarch 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate.

9

Recent Accounting Developments

The following recently issued accounting pronouncement may impact the Company in future periods:

Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB's due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

3. Property, Plant and Equipment

The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of West Virginia, Pennsylvania and Oklahoma.

The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:

	March 31, 2015		December 31, 2014
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	17,468	$	29,193
Acreage acquisition costs	94,079		91,362
Capitalized interest	8,794		7,719
Total unproved properties excluded from amortization	$	120,341	$	128,274

For the three months endedMarch 31, 2015, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $35,000 of unproved properties to proved properties for the three months endedMarch 31, 2015 related to acreage in Marcellus East.

10

The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company's capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:

	2015
	Total Impairment		March 31
Henry Hub natural gas price (per MMBtu)(1)			$	3.88
West Texas Intermediate oil price (per Bbl)(1)			$	82.72
Impairment recorded (pre-tax) (in thousands)	$	—	$	—

	2014
	Total Impairment		March 31
Henry Hub natural gas price (per MMBtu)(1)			$	3.99
West Texas Intermediate oil price (per Bbl)(1)			$	98.30
Impairment recorded (pre-tax) (in thousands)	$	—	$	—

 _________________________________

(1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Future declines in the 12-month average of oil, condensate, natural gas and NGLs prices could result in the recognition of future ceiling impairments.

Mid-Continent Divestiture

On May 1, 2015, the Company entered into a purchase and sale agreement with an undisclosed private third party to sell certain non-core assets comprised of 38 gross (16.7 net) wells producing approximately net 170 Boe/d (41% oil) for the three months ended March 31, 2015 and approximately 29,300 gross (19,000 net) acres in Kingfisher County, Oklahoma for approximately $46.2 million, subject to customary closing adjustments. The transaction is expected to close on or before June 22, 2015, with an effective date of April 1, 2015. The sale will be reflected as a reduction to the full cost pool and the Company does not anticipate recording a gain or loss related to the divestiture as it is not significant to the full cost pool.

Atinum Joint Venture

In September 2010, the Company entered into a joint venture (the “Atinum Joint Venture”) pursuant to which the Company ultimately assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum”), for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, the Company acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay the Company on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million.

The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, Atinum and the Company agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells. At March 31, 2015, 70 gross operated horizontal Marcellus Shale wells and one gross operated horizontal Utica Shale/Point

11

Pleasant well were capable of production under the Atinum Joint Venture. The Atinum Joint Venture Agreement expires on November 1, 2015.

4. Long-Term Debt

Second Amended and Restated Revolving Credit Facility

On June 7, 2013, the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). At the Company's election, borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent, (ii) the federal funds rate plus50 basis points or (iii) LIBOR plus 1.0%. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base and subject to adjustments based on the Company's leverage ratio. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity of November 14, 2017.

The Revolving Credit Facility will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on all domestic oil and natural gas properties currently owned by or later acquired by the Company and its subsidiaries, excluding de minimis value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of the Company.

The Revolving Credit Facility contains various covenants, including, among others:

• Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments;

• Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted;

• Maintenance of a maximum ratio of net indebtedness to EBITDA of not greater than 4.0 to 1.0, subject to the modifications in Amendment No. 5 set forth below; and

• Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0, subject to the modifications in Amendment No. 5 set forth below.

All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including, among others:

• Failure to make payments;

• Non-performance of covenants and obligations continuing beyond any applicable grace period; and

• The occurrence of a change in control of the Company, as defined under the Revolving Credit Facility.

OnMarch 9, 2015, the Company, together with the parties thereto, entered into a Master Assignment, Agreement and Amendment No. 5(“Amendment No. 5”) to Second Amended and Restated Credit Agreement. Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million, (ii) adjust the leverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016, to 5.25 to 1.00; for the fiscal quarter ending on September 30, 2016, to 5.00 to 1.00; for the fiscal quarter ending on December 31, 2016, to 4.75 to 1.00; for the fiscal quarter ending on March 31, 2017, to 4.25 to 1.00; and for each fiscal quarter ending on or after June 30, 2017, to 4.00 to 1.00, (iii) adjust the interest coverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016, to 2.00 to 1.00 and for each fiscal quarter ending on or after March 31, 2016, to 2.50 to 1.00, and (iv) add the senior secured leverage ratio covenant, such ratio not to exceed, (a) for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016, 2.25 to 1.00 and (b) for each fiscal quarter ending on or after June 30, 2016, 2.00 to 1.00 provided that this senior secured leverage ratio shall cease to apply commencing with the first fiscal quarter end occurring after June 30, 2016 for which the total leverage ratio is equal to or less than 4.00 to 1.00.

Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. The Company and its lenders may request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At March 31, 2015, the Revolving Credit Facility had a borrowing base of $200.0 million, with $65.0 million borrowings outstanding and availability of $135.0 million. The next regularly scheduled redetermination is set for November

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2015. Future increases in the borrowing base in excess of the original $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the Notes agreement (as discussed below in “Senior Secured Notes”).

At March 31, 2015, the Company was in compliance with all financial covenants under the Revolving Credit Facility.

Senior Secured Notes

The Company has $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. The Notes will mature on May 15, 2018.

In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.

The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to the Company's unsecured indebtedness and effectively subordinated to the Company's and Guarantors' under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation.

The Indenture contains covenants that, among other things, limit the Company's ability and the ability of its subsidiaries to:

• Transfer or sell assets or use asset sale proceeds;

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

• Make certain investments; incur or guarantee additional debt or issue preferred equity securities;

• Create or incur certain liens on the Company's assets;

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

• Merge, consolidate or transfer all or substantially all of the Company's assets;

• Enter into certain transactions with affiliates; and

• Enter into certain sale and leaseback transactions.

These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.

At March 31, 2015, the Notes reflected a balance of $315.9 million, net of unamortized discounts of $9.1 million, on the condensed consolidated balance sheets.

5. Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties or estimated market data based on area transactions, which are Level 3 inputs. For the three months endedMarch 31, 2015, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $35,000 of unproved properties to proved properties for the three months endedMarch 31, 2015 related to acreage in Marcellus East. For the three months endedMarch 31, 2014, management's evaluation of unproved properties resulted in an impairment of $194,000 related to Marcellus East. As no other fair value measurements are required to be recognized on a non-recurring basis at March 31, 2015, no additional disclosures are provided at March 31, 2015.

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As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

• Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods.

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The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:

	Fair value as of March 31, 2015
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	12,143	$	—	$	—		$	12,143
Commodity derivative contracts	—		—		32,219			32,219
Liabilities:
Commodity derivative contracts	—		—		(396		)	(396		)
Total	$	12,143	$	—	$	31,823		$	43,966
	Fair value as of December 31, 2014
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	11,008	$	—	$	—		$	11,008
Commodity derivative contracts	—		—		27,502			27,502
Liabilities:
Commodity derivative contracts	—		—		—			—
Total	$	11,008	$	—	$	27,502		$	38,510

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at March 31, 2015 and 2014.

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Balance at beginning of period	$	27,502		$	3,764
Total gains (losses) included in earnings	10,223			(6,514		)
Purchases	866			71
Issuances	(186		)	—
Settlements(1)	(6,582		)	3,299
Balance at end of period	$	31,823		$	620
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$	4,252		$	(3,155	)

 _________________________________

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

At March 31, 2015, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at March 31, 2015 was $371.7 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximates the current market rate (Level 2).

The Company has consistently applied the valuation techniques discussed above in all periods presented.

The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivative Instruments and Hedging Activity.”

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6. Derivative Instruments and Hedging Activity

The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk.

All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the condensed consolidated statements of operations in gain (loss) on commodity derivatives contracts. For the three months ended March 31, 2015 and 2014, the Company reported a gain of $4.3 million and a loss of $3.2 million, respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts still held at March 31, 2015 and 2014.

As of March 31, 2015, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume(1)	Total of Notional Volume	Base Fixed Price		Floor (Long)		Short Put		Ceiling (Short)
		(in Bbls)
2015(2)	Costless collar	400	48,800	$	—	$	85.00	$	—	$	96.50
2015(2)	Costless collar	360	43,920	$	—	$	85.00	$	—	$	97.80
2015(2)	Costless collar	150	18,300	$	—	$	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	85,400	$	—	$	90.00	$	70.00	$	—
2015	Put spread	250	68,750	$	—	$	89.00	$	69.00	$	—
2015	Costless three-way collar	750	206,250	$	—	$	52.50	$	40.00	$	62.05
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	Costless three-way collar	450	164,700	$	—	$	57.50	$	42.50	$	80.00
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	Costless three-way collar	200	73,000	$	—	$	60.00	$	42.50	$	85.00
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 April to June 2015.

(3) For the period July to December 2015.

(4) For the period January to August 2018.

As of March 31, 2015, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

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Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price			Floor (Long)		Short Put		Call (Long)		Ceiling (Short)
		(in MMBtus)
2015	Fixed price swap	400	110,000	$	4.00		$	—	$	—	$	—	$	—
2015	Fixed price swap	2,500	687,500	$	4.06		$	—	$	—	$	—	$	—
2015	Protective spread	2,600	715,000	$	4.00		$	—	$	3.25	$	—	$	—
2015	Fixed price swap	5,000	1,375,000	$	3.49		$	—	$	—	$	—	$	—
2015	Fixed price swap	2,000	550,000	$	3.53		$	—	$	3.25	$	—	$	—
2015	Producer three-way collar	2,500	687,500	$	—		$	3.70	$	3.00	$	—	$	4.09
2015	Producer three-way collar	5,000	1,375,000	$	—		$	3.77	$	3.00	$	—	$	4.11
2015(1)	Producer three-way collar	2,000	428,000	$	—		$	3.00	$	2.25	$	—	$	3.34
2015(1)	Fixed price swap	10,000	2,140,000	$	2.94		$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.12	)	$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.11	)	$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.14	)	$	—	$	—	$	—	$	—
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
2016	Producer three-way collar	5,000	1,830,000	$	—		$	3.40	$	2.65	$	—	$	4.10
2016	Basis swap(3)	2,500	915,000	$	(1.10	)	$	—	$	—	$	—	$	—
2017	Short call	10,000	3,650,000	$	—		$	—	$	—	$	—	$	4.75

 _______________________________

(1) For the period April to October 2015.

(2) Represents basis swaps at the sales point of Dominion South.

(3) Represents basis swaps at the sales point of TetcoM2.

As of March 31, 2015, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price
		(in Bbls)
2015	Fixed price swap	250	68,750	$	45.61

As of March 31, 2015, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features.

In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period April 2015 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated:

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	March 31, 2015		December 31, 2014
	(in thousands)
Current commodity derivative premium put payable	$	2,472	$	2,481
Long-term commodity derivative premium payable	4,809		4,702
Total unamortized put premium liabilities	$	7,281	$	7,183

	For the Three Months Ended March 31, 2015
	(in thousands)
Put premium liabilities, beginning balance	$	7,183
Amortization of put premium liabilities	(582		)
Additional put premium liabilities	680
Put premium liabilities, ending balance	$	7,281

The following table provides information regarding the amortization of the deferred put premium liabilities by year as of March 31, 2015:

	Amortization
	(in thousands)
April to December 2015	1,714
January to December 2016	3,050
January to December 2017	1,684
January to August 2018	833
Total unamortized put premium liabilities	$	7,281

Additional Disclosures about Derivative Instruments and Hedging Activities

The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:

	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
		Fair Value
	Balance Sheet Location	March 31, 2015			December 31, 2014
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	18,815		$	19,687
Commodity derivative contracts	Other assets	13,404			7,815
Commodity derivative contracts	Current liabilities	(56		)	—
Commodity derivative contracts	Long-term liabilities	(340		)	—
Total derivatives not designated as hedging instruments		$	31,823		$	27,502

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		Amount of Gain (Loss) Recognized in Income on Derivatives For the Three Months Ended March 31,
	Location of Gain (Loss) Recognized in Income on Derivatives	2015		2014
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Gain (loss) on commodity derivatives contracts	$	10,223	$	(6,514	)
Total		$	10,223	$	(6,514	)

7. Capital Stock

Preferred Stock

The Company currently has 40,000,000 shares of preferred stock authorized for issuance under its certificate of incorporation. The Company has designated 10,000,000 shares to constitute its 8.625% Series A Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 shares to constitute its 10.75% Series B Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share.

Series A Preferred Stock

At March 31, 2015, there were 4,045,000 shares of the Series A Preferred Stock issued and outstanding.

The Series A Preferred Stock ranks senior to the Company's common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock.

The Series A Preferred Stock cannot be converted into common stock, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends.

There is no mandatory redemption of the Series A Preferred Stock.

The Company pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three months endedMarch 31, 2015, the Company recognized dividend expense of $2.2 million for the Series A Preferred Stock.

Series B Preferred Stock

At March 31, 2015, there were 2,140,000 shares of the Series B Cumulative Preferred Stock issued and outstanding.

The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with the Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock.

Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company will have the option to redeem the Series B Preferred Stock, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If the Company does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into up to an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption.

There is no mandatory redemption of the Series B Preferred Stock.

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The Company pays cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the three months endedMarch 31, 2015, the Company recognized dividend expense of $1.4 million for the Series B Preferred Stock.

Other Share Issuances

The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the period indicated:

	For the Three Months Ended March 31, 2015
Other share issuances:
Shares of restricted common stock granted	1,421,224
Shares of restricted common stock vested	1,274,872
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
Shares of restricted common stock surrendered upon vesting/exercise(1)	382,238
Shares of restricted common stock forfeited	23,657

 __________________

(1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

On June 12, 2014, the Company's stockholders approved an amendment and restatement to the Gastar Exploration Inc. Long-Term Incentive Plan (the “LTIP”), effective April 24, 2014, to, among other things, increase the number of shares reserved for issuance under the LTIP by 3,000,000 shares. There were 2,849,434 shares available for issuance under the LTIP at March 31, 2015.

Shares Reserved

At March 31, 2015, the Company had 866,600 common shares reserved for the exercise of stock options.

8. Interest Expense

The following table summarizes the components of interest expense for the periods indicated:

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Interest expense:
Cash and accrued	$	7,928		$	7,134
Amortization of deferred financing costs(1)	822			733
Capitalized interest	(1,189		)	(976		)
Total interest expense	$	7,561		$	6,891

 _________________________________

(1) The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

9. Income Taxes

For the three months endedMarch 31, 2015 and 2014, respectively, the Company did not recognize a current income tax benefit or provision as the Company has a full valuation allowance against assets created by net operating losses generated. The Company believes it more likely than not that the assets will not be utilized.

10. Earnings per Share

In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common

20

shares for all potentially dilutive securities.

	For the Three Months Ended March 31,
	2015			2014
	(in thousands, except per share and share data)
Net loss attributable to common stockholders	$	(3,004	)	$	(1,965	)
Weighted average common shares outstanding - basic	77,114,826			58,204,532
Incremental shares from unvested restricted shares	—			—
Incremental shares from outstanding stock options	—			—
Incremental shares from outstanding PBUs	—			—
Weighted average common shares outstanding - diluted	77,114,826			58,204,532
Net loss per share of common stock attributable to common stockholders:
Basic	$	(0.04	)	$	(0.03	)
Diluted	$	(0.04	)	$	(0.03	)
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares	450,556			119,496
Stock options	—			—
Unvested PBUs	373,325			—
Total	823,881			119,496

11. Commitments and Contingencies

Litigation

Gastar Exploration Ltd vs. U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No.2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage is $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Fourteenth Court of Appeals, which that court denied. The insurers then sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The insurers recently filed in the Texas Supreme Court a motion for rehearing of their denied petition for review, which the court has not ruled on. If the court denies the motion, the case will be remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements.

The Company has been expensing legal costs on these proceedings as they are incurred.

The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

21

12. Statement of Cash Flows – Supplemental Information

The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash paid for interest, net of capitalized amounts	$	(282	)	$	(697	)
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	$	(10,366	)	$	(299	)
Capital expenditures included in accounts receivable	—			4,077
Asset retirement obligation included in oil and natural gas properties	77			28
Application of advances to operators	8,457			9,490
Other	23			78

22

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including, without limitation, all statements regarding future plans, business objectives, strategies, expected future financial position or performance, future covenant compliance, expected future operational position or performance, budgets and projected costs, future competitive position or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology.

The forward-looking statements contained in this report are largely based on our expectations and beliefs concerning future developments and their potential effect on us, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Forward-looking statements may include statements that relate to, among other things, our:

• financial position;

• business strategy and budgets;

• capital expenditures;

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

• oil, natural gas and NGLs reserves;

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

• operating costs and other expenses;

• cash flow and liquidity;

• compliance with covenants under our indenture and credit agreements;

• availability of capital;

• prospect development; and

• property acquisitions and sales.

Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

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

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

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

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

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

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

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

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

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

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

• strength and financial resources of competitors;

23

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

• availability and cost of processing and transportation;

• changes or advances in technology;

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

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

• environmental risks;

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

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

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

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

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

• our ability to find and retain skilled personnel; and

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

For a more detailed description of the risks and uncertainties that we face and other factors that could affect our financial performance or cause our actual results to differ materially from our projected results please see (i) Part II, Item 1A. “Risk Factors” and elsewhere in this report, (ii) Part I, Item 1A. “Risk Factors” and elsewhere in our 2014 Form 10-K, (iii) our subsequent reports and registration statements filed from time to time with the SEC and (iv) other announcements we make from time to time.

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly update, revise or release any revisions to these forward-looking statements after the date on which they are made to reflect new information, events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Our principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, we are developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expect to test other prospective formations on the same acreage, including the Woodford Shale and the Meramec Shale (middle Mississippi Lime), which we refer to as the Stack Play. In West Virginia, we are developing liquids-rich natural gas in the Marcellus Shale and have drilled and completed our first successful dry gas Utica Shale/Point Pleasant well on our acreage.

Our current operational activities are conducted in, and our consolidated revenues are generated from, markets exclusively in the U.S. As of March 31, 2015, our major assets consist of approximately 230,700 gross (122,700 net) acres in Oklahoma and approximately 72,700 gross (50,500 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, of which approximately 26,200 gross (10,600 net) acres have Utica Shale/Point Pleasant potential, of which approximately 4,300 gross (1,900 net) acres are pending lease finalization.

The following discussion addresses material changes in our results of operations for the three months endedMarch 31, 2015 compared to the three months endedMarch 31, 2014 and material changes in our financial condition since December 31,

24

2014. This discussion should be read in conjunction with our condensed consolidated financial statements and the notes thereto included in Part I, Item 1. “Financial Statements” of this report, as well as our 2014 Form 10-K, which includes important disclosures regarding our critical accounting policies as part of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Oil and Natural Gas Activities

The following provides an overview of our major oil and natural gas projects. While actively pursuing specific exploration and development activities in each of the following areas, there is no assurance that new drilling opportunities will be identified or that any new drilling opportunities will be successful if drilled.

Mid-Continent Horizontal Oil Play.

The Hunton Limestone is a limestone formation stretching over approximately 2.7 million acres mainly in Oklahoma, but also in the neighboring states of Texas, New Mexico and Arkansas. Hunton Limestone economics are attractive due to the high quality oil production and the associated production of high BTU content natural gas in the area. At March 31, 2015, we held leases covering approximately 230,700 gross (122,700 net) acres in Major, Garfield, Canadian, Kingfisher, Logan, Blaine and Oklahoma Counties, Oklahoma within the Hunton Limestone horizontal oil play.

In our initial AMI with our Mid-Continent partner, we currently pay 50% of lease acquisition costs for a 50% working interest. We pay 54.25% of the lease acquisition costs in the two additional prospect areas for a 50% working interest. In the initial prospect area, we are currently responsible for paying only the drilling and completion costs associated with our 50% working interest (our approximate net revenue interest is 39.0%). In all subsequent prospect areas, we pay 54.25% of gross drilling and completion costs to earn a 50% working interest. Our AMI partner handles all drilling, completion and production activities, and we handle leasing and permitting activities in certain areas of the AMI. For 2015, our focus is to drill in areas that we believe will result in the most significant proved reserve recognition to capital dollars spent and renew acreage in areas that our past drilling has proven to provide attractive returns and production rates and substantial reserve additions. We may elect to sell in the future any acreage that is determined to provide less attractive returns, productions and reserve additions or is outside of our drilling focus to reduce net capital expenditures.

On May 1, 2015, we entered into a purchase and sale agreement with an undisclosed private third party to sell certain non-core assets comprised of 38 gross (16.7 net) wells producing approximately net 170 Boe/d (41% oil) for the three months ended March 31, 2015 and approximately 29,300 gross (19,000 net) acres in Kingfisher County, Oklahoma for approximately $46.2 million, subject to customary closing adjustments. The transaction is expected to close on or before June 22, 2015, with an effective date of April 1, 2015. The sale will be reflected as a reduction to the full cost pool and we do not anticipate recording a gain or loss related to the divestiture as it is not significant to the full cost pool.

As of March 31, 2015 and currently as of the date of this report, we had initial production and drilling operations at various stages on the following wells in our original AMI in the Hunton Limestone formation:

				Cumulative Production Averages(2)
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)
LB 1-1H	47.6%	4,400	791	356	69%	January 23, 2015	$5.0
Boss Hogg 1-14H	54.3%	4,400	129	68	66%	February 21, 2015	$7.4
Hubbard 1-23H(3)	57.0%	4,600	N/A	19	100%	March 6, 2015	$6.1
The River 1-22H	43.1%	4,400	1,250	1,109	46%	March 14, 2015	$5.0
Bo 1-23H	54.3%	4,900	547	398	55%	March 15, 2015	$5.0
Bigfoot 1-9H	51.5%	4,800	N/A	127	67%	March 17, 2015	$5.0
Falcon 1-5H	51.5%	4,700	770	616	87%	April 1, 2015	$5.0
Dorothy 1-12H	53.7%	5,000	N/A	N/A	N/A	April 10, 2015	$5.0
Polar Bear 1-20H	47.7%	4,400	N/A	N/A	N/A	Awaiting completion	$5.0
Unruh 1-34H	49.0%	4,900	N/A	N/A	N/A	Awaiting re-drill	$7.1

_________________________________

(1) Represents highest daily gross Boe rate.

(2) Represents gross cumulative production divided by actual producing days through April 22, 2015.

25

(3) After payout working interest is 49.9%.

In addition to the wells above, we also participated on a non-operated basis in wells outside of the AMI operated by our AMI partner. As of March 31, 2015 and currently as of the date of this report, we had initial production and drilling operations at various stages on the following non-operated wells outside the original AMI in the Hunton Limestone formation:

				Cumulative Production Averages(2)
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)
Wolf 1-9H	16.7%	3,600	391	257	60%	January 3, 2015	$5.5

 _________________________________

(1) Represents highest daily gross Boe rate.

(2) Represents gross cumulative production divided by actual producing days through April 22, 2015.

As of March 31, 2015 and currently as of the date of this report, we had production and drilling operations at various stages on the following operated wells on our acquired West Edmond Hunton Lime Unit (“WEHLU”) acreage in the lower Hunton Limestone formation:

				Cumulative Production Averages(2)
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)
Warsaw 33-2H	98.3%	4,900	615	348	72%	February 12, 2015	$3.8
Warsaw 33-3H	98.3%	5,800	663	297	67%	February 13, 2015	$6.2
Warsaw 33-1(3)	98.3%	N/A	30	21	60%	March 13, 2015	$3.5
Easton 22-3H	98.3%	6,500	N/A	N/A	N/A	Awaiting completion	$5.0
Easton 22-4H	98.3%	6,500	N/A	N/A	N/A	Awaiting completion	$3.1
Blair Farms 31-1H	98.3%	6,500	N/A	N/A	N/A	Awaiting completion	$3.3
Davis 9-2H	98.3%	6,800	N/A	N/A	N/A	Drilling	$4.5
Jetson 8-1H	98.3%	6,800	N/A	N/A	N/A	Drilling	$5.5

 _________________________________

(1) Represents highest daily gross Boe rate.

(2) Represents gross cumulative production divided by actual producing days through April 22, 2015.

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

We continue to target our horizontal laterals in the Hunton Limestone formation and increase the number of fracturing stages in the horizontal lateral as warranted by log analysis. We are continuing to monitor well flow back results on recently drilled and completed wells and remain encouraged by the overall well results to date.

26

The following table provides production and operational information about the Mid-Continent for the periods indicated:

	For the Three Months Ended March 31,
Mid-Continent	2015		2014
Net Production:
Oil and condensate (MBbl)	297		136
Natural gas (MMcf)	797		659
NGLs (MBbl)	96		47
Total net production (MBoe)	527		293
Net Daily Production:
Oil and condensate (MBbl/d)	3.3		1.5
Natural gas (MMcf/d)	8.9		7.3
NGLs (MBbl/d)	1.1		0.5
Total net daily production (MBoe/d)	5.9		3.3
Average sales price per unit(1):
Oil and condensate (per Bbl)	$	46.87	$	98.03
Natural gas (per Mcf)	$	3.18	$	5.67
NGLs (per Bbl)	$	14.35	$	44.33
Average sales price per Boe(1)	$	33.91	$	65.38
Selected operating expenses (in thousands):
Production taxes	$	351	$	616
Lease operating expenses	$	5,026	$	2,840
Transportation, treating and gathering	$	4	$	10
Selected operating expenses per Boe:
Production taxes	$	0.67	$	2.10
Lease operating expenses	$	9.54	$	9.69
Transportation, treating and gathering	$	0.01	$	0.03
Production costs(2)	$	9.55	$	9.73

 _________________________________

(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.

Appalachian Basin.

Marcellus Shale. The Marcellus Shale is Devonian aged shale that underlies much of the Appalachian region of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration target in the Appalachian Basin. Advancements in horizontal drilling and stimulation have produced promising results in the Marcellus Shale. These developments have resulted in increased leasing and drilling activity in the area. As of March 31, 2015, our acreage position in the play was approximately 72,700 gross (50,500 net) acres. We refer to the approximately 30,800 gross (12,800 net) acres reflecting our interest in our Marcellus Shale assets in West Virginia and Pennsylvania subject to the Atinum Joint Venture described below as our Marcellus West acreage. We refer to the approximately 41,900 gross (37,700 net) acres in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia as our Marcellus East acreage. The entirety of our acreage is believed to be in the core, over-pressured area of the Marcellus play. We continue to opportunistically swap acreage with adjacent operators in order to optimize our acreage and maximize horizontal lateral lengths.

On September 21, 2010, we entered into the Atinum Joint Venture pursuant to which we ultimately assigned to Atinum, for $70.0 million in total consideration, a 50% working interest in certain undeveloped acreage and shallow producing wells. Atinum has the right to participate in any future leasehold acquisitions made by us within Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the existing Atinum Joint Venture. We are the operator and are obligated to offer any future lease

27

acquisitions to Atinum on a 50/50 basis. Atinum will pay us on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs, up to $20.0 million, and 5% of such costs on activities above $20.0 million.

The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, we and Atinum agreed to reduce the minimum wells to be drilled requirements from 60 gross wells to 51 gross wells. At March 31, 2015, 70gross (35.0net) operated Marcellus Shale horizontal wells were capable of production.All of our Marcellus Shale well operations to date were drilled under the Atinum Joint Venture. The Atinum Joint Venture agreement expires on November 1, 2015.

As of March 31, 2015 and currently as of the date of this report, we had drilling operations at various stages on the following Marcellus Shale wells in Marshall County, West Virginia:

Pad	Gross Well Count	Net Well Count	Working Interest	Estimated Net Revenue Interest	Average Lateral Length (in feet)(1)	Status	Estimated Production Date
Hoyt(2)	2.0	1.0	50.0%	42.7%	5,000	Completed	April 22, 2015
Blake(3)	2.0	1.0	50.0%	41.9%	5,700	Awaiting completion	May 2015
	4.0	2.0

_________________________________

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

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

28

The following table provides production and operational information for the Marcellus Shale for the periods indicated:

	For the Three Months Ended March 31,
Marcellus Shale	2015		2014
Net Production:
Oil and condensate (MBbl)	70		67
Natural gas (MMcf)	2,158		2,413
NGLs (MBbl)	122		108
Total net production (MBoe)	552		577
Net Daily Production:
Oil and condensate (MBbl/d)	0.8		0.7
Natural gas (MMcf/d)	24.0		26.8
NGLs (MBbl/d)	1.4		1.2
Total net daily production (MBoe/d)	6.1		6.4
Average sales price per unit (1):
Oil and condensate (per Bbl)	$	20.27	$	51.41
Natural gas (per Mcf)	$	1.69	$	4.84
NGLs (per Bbl)	$	5.82	$	42.12
Average sales price per Boe (1)	$	10.46	$	34.10
Selected operating expenses (in thousands):
Production taxes	$	442	$	1,278
Lease operating expenses	$	989	$	1,204
Transportation, treating and gathering	$	459	$	615
Selected operating expenses per Boe:
Production taxes	$	0.80	$	2.21
Lease operating expenses	$	1.79	$	2.08
Transportation, treating and gathering	$	0.83	$	1.07
Production costs (2)	$	1.95	$	2.76

_________________________________

(1) Excludes the impact of hedging activities.

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

Utica Shale/Point Pleasant. The Utica Shale is Ordovician aged shale that underlies much of the Appalachian region of Pennsylvania, Ohio and West Virginia. The depth of the Utica Shale and its low permeability make it an unconventional exploration target in the Appalachian Basin. Advancements in horizontal drilling and hydraulic fracture stimulation have produced promising results in the Utica Shale, some in close proximity to our existing Marcellus West acreage. Based on log analysis of offsetting wells, recent Utica Shale completions by other nearby operators and the drilling and completion of our first horizontal Utica Shale/Point Pleasant well, we believe that our Marcellus West acreage should be prospective for high-pressure, high-deliverability dry natural gas development in the Utica Shale. We spudded our first Utica Shale/Point Pleasant well, the Simms U-5H, on April 3, 2014. We drilled the Simms U-5H to a total vertical depth of 11,500 feet and drilled an approximate 4,400-foot lateral and completed it with a 25-stage fracture stimulation. The Simms U-5H was producing at a last five-day average rate of 7.0 MMcf/d of natural gas and had total cumulative production of 2.5 Bcf as of April 19, 2015. Our working interest in the Simms U-5H is 50.0% (43.2% net revenue interest). We spudded our second Utica Shale/Point Pleasant well, the Blake U-7H, in late November 2014, in which we own a 50% working interest (41.1% net revenue interest). Currently, we are projecting flow back operations will commence in late May 2015. The estimated cost to drill and complete the Blake U-7H was approximately $13.5 million. At March 31, 2015, one gross (0.5 net) operated Utica Shale/Point Pleasant horizontal well was capable of production and one gross (0.5 net) operated Utica Shale/Point Pleasant well was awaiting completion. All of our Utica Shale/Point Pleasant well operations to date were drilled under the Atinum Joint Venture. The Atinum Joint Venture agreement expires on November 1, 2015.

29

The following table provides production and operational information for Appalachia for the periods indicated:

	For the Three Months Ended March 31,
Utica Shale	2015		2014
Net Production:
Natural gas (MMcf)	340		—
Total net production (MBoe)	57		—
Net Daily Production:
Natural gas (MMcf/d)	3.8		—
Total net daily production (MBoe/d)	0.6		—
Average sales price per unit (1):
Natural gas (per Mcf)	$	1.53	$	—
Average sales price per Boe (1)	$	9.18	$	—
Selected operating expenses (in thousands):
Production taxes	$	46	$	—
Lease operating expenses	$	5	$	—
Transportation, treating and gathering	$	35	$	—
Selected operating expenses per Boe:
Production taxes	$	0.81	$	—
Lease operating expenses	$	0.09	$	—
Transportation, treating and gathering	$	0.61	$	—
Production costs (2)	$	0.70	$	—

_________________________________

(1) Excludes the impact of hedging activities.

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

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the condensed consolidated financial statements and the related notes to the condensed consolidated financial statements found elsewhere in this report.

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The following table provides information about production volumes, average prices of oil and natural gas and operating expenses for the periods indicated:

	For the Three Months Ended March 31,
	2015		2014
	(In thousands, except per unit amounts)
Net Production:
Oil and condensate (MBbl)	367		203
Natural gas (MMcf)	3,295		3,072
NGLs (MBbl)	219		155
Total net production (MBoe)	1,135		870
Net Daily production:
Oil and condensate (MBbl/d)	4.1		2.3
Natural gas (MMcf/d)	36.6		34.1
NGLs (MBbl/d)	2.4		1.7
Total net daily production (MBoe/d)	12.6		9.7
Average sales price per unit:
Oil and condensate per Bbl, excluding impact of hedging activities	$	41.82	$	82.61
Oil and condensate per Bbl, including impact of hedging activities (1)	$	47.50	$	79.57
Natural gas per Mcf, excluding impact of hedging activities	$	2.03	$	5.02
Natural gas per Mcf, including impact of hedging activities (1)	$	2.58	$	4.34
NGLs per Bbl, excluding impact of hedging activities	$	9.58	$	42.79
NGLs per Bbl, including impact of hedging activities (1)	$	19.10	$	38.63
Average sales price per Boe, excluding impact of hedging activities	$	21.28	$	44.62
Average sales price per Boe, including impact of hedging activities (1)	$	26.54	$	40.76
Selected operating expenses:
Production taxes	$	840	$	1,894
Lease operating expenses	$	6,019	$	4,044
Transportation, treating and gathering	$	497	$	625
Depreciation, depletion and amortization	$	14,471	$	12,382
General and administrative expense	$	4,248	$	4,763
Selected operating expenses per Boe:
Production taxes	$	0.74	$	2.18
Lease operating expenses	$	5.30	$	4.65
Transportation, treating and gathering	$	0.44	$	0.72
Depreciation, depletion and amortization	$	12.75	$	14.23
General and administrative expense	$	3.74	$	5.47
Production costs(2)	$	5.42	$	5.10

_________________________________

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

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

Three Months Ended March 31, 2015 compared to the Three Months Ended March 31, 2014

Revenues. Total oil, condensate, natural gas and NGLs revenues (exclusive of the effects of hedging) were $24.1 million for the three months ended March 31, 2015, down38% from $38.8 million for the three months ended March 31, 2014. The decrease in revenues was the result of a 52%decrease in weighted average realized prices offset by a 30%increase in production. Average daily production on an equivalent basis was 12.6 MBoe/d for the three months ended March 31, 2015 compared to 9.7 MBoe/d for the same period in 2014. Oil, condensate and NGLs production represented approximately 52% of

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total production for the three months ended March 31, 2015 compared to 41% of total production for the three months ended March 31, 2014.

Liquids revenues (oil, condensate and NGLs) represented approximately 72% of our total oil, condensate, natural gas and NGLs revenues for the three months ended March 31, 2015 compared to 60% for the three months ended March 31, 2014. We continue to focus our drilling activity in the Mid-Continent oil play and the liquids-rich portions of the Marcellus Shale. We expect our liquids revenues to continue to be a significant percentage of total oil, condensate, natural gas and NGLs revenues during the remainder of 2015.

During the three months ended March 31, 2015, we had commodity derivative contracts covering approximately 23% of our oil and condensate production. The impact of hedging on oil and condensate sales during the three months ended March 31, 2015 was an increase of $2.1 million in oil and condensate revenues and resulted in an increase in total price realized from $41.82 per Bbl to $47.50 per Bbl. The gain on oil and condensate commodity derivatives contracts settled during the period includes a loss of $10,000 for amortization of prepaid premiums and a loss of $291,000 of deferred put premiums. For additional information regarding our oil and condensate hedging positions as of March 31, 2015, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended March 31, 2014, the impact of hedging on oil and condensate sales was a decrease of $619,000 in oil and condensate revenues, which resulted in a decrease in total price realized from $82.61 per Bbl to $79.57 per Bbl. For both periods, we designated 50% of our current crude hedges as price protection for our NGLs production.

During the three months ended March 31, 2015, we had commodity derivative contracts covering approximately 56% of our natural gas production, which resulted in a gain on natural gas commodity derivatives contracts settled during the quarter of $1.8 million and resulted in an increase in total price realized from $2.03 per Mcf to $2.58 per Mcf. The gain on natural gas commodity derivative contracts settled during the period includes a loss of $9,000 for amortization of prepaid premiums. Excluding the non-cash amortization, the impact of hedging on natural gas sales was an increase in revenues of $1.8 million of NYMEX hedge gains and $9,000 of basis hedge gains. For additional information regarding our natural gas hedging positions as of March 31, 2015, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended March 31, 2014, the impact of hedging on natural gas sales was a decrease of $2.1 million in natural gas revenues resulting in a decrease in total price realized from $5.02 per Mcf to $4.34 per Mcf.

During the three months ended March 31, 2015, we had commodity derivative contracts covering approximately 39% of our NGLs production. The impact of hedging on NGLs sales during the three months ended March 31, 2015 was an increase of $2.1 million in NGLs revenues and resulted in an increase in total price realized from $9.58 per Bbl to $19.10 per Bbl. The gain on NGLs commodity derivatives contracts settled during the period includes a loss of $10,000 for amortization of prepaid premiums and a loss of $291,000 of deferred put premiums. For additional information regarding our NGLs hedging positions as of March 31, 2015, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended March 31, 2014, the impact of hedging on NGLs sales was a decrease of $646,000 in NGLs revenues which resulted in a decrease in total price realized from $42.79 per Bbl to $38.63 per Bbl.

The change in mark to market value for outstanding commodity derivatives contracts for the three months ended March 31, 2015 was a gain of $4.3 million compared to losses of $3.2 million for the three months ended March 31, 2014. The change in the mark to market value is primarily the result of lower commodity prices and the changes in hedge contracts during the period compared to the prior year.

Production taxes. We reported production taxes of $840,000 for the three months ended March 31, 2015 compared to $1.9 million for the three months ended March 31, 2014. The decrease in production taxes primarily resulted from lower commodity prices and new wells in Oklahoma that qualify for horizontal tax exemptions. Production taxes for the three months ended March 31, 2015 and 2014 were approximately 3.5% and 4.9%, respectively, of oil, condensate, natural gas and NGLs revenues. The decrease in the production tax as a percentage of revenues is primarily the result of an increase in Mid-Continent revenues that benefit from an initial four-year production tax abatement related to new horizontal well drilling.

Lease operating expenses. We reported lease operating expenses (“LOE”) of $6.0 million for the three months ended March 31, 2015 compared to $4.0 million for the three months ended March 31, 2014. Our total LOE was $5.30 per Boe for the three months ended March 31, 2015 compared to $4.65 per Boe for the same period in 2014. The increase in our LOE was primarily due to a $1.4 million increase in one-time workover expense for production enhancing workovers completed on certain WEHLU wells as well as a $477,000 increase in controllable LOE resulting from new wells drilled combined with higher overall costs associated with producing oil versus natural gas. Excluding workover expense, LOE per Boe for the three months ended March 31, 2015 was $4.09 compared to $4.65 for the three months ended March 31, 2014.

Transportation, treating and gathering. We reported transportation expenses of $497,000 for the three months ended March 31, 2015 compared to $625,000 for the three months ended March 31, 2014. The decrease in transportation expenses between quarters is primarily due to a $156,000 decrease for Marcellus transportation expense resulting from an 11% decrease

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in volumes for the quarter ended March 31, 2015 coupled with lower non-operated well fees compared to the quarter ended March 31, 2014 offset by a $35,000 increase in transportation expense for Utica production.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $14.5 million for the three months ended March 31, 2015up from $12.4 million for the three months ended March 31, 2014. The increase in DD&A expense was the result of a 30%increase in production partially offset by a 10%decrease in the DD&A rate per Boe. The DD&A rate for the three months ended March 31, 2015 was $12.75 per Boe compared to $14.23 per Boe for the same period in 2014. The decrease in the rate is primarily due to higher proved reserves at March 31, 2015 compared to March 31, 2014. While we did not recognize an impairment charge to oil and natural gas properties for the three monts ended March 31, 2015 and 2014, absent significant price increases, the sustained lower oil and natural gas prices experienced in the second half of 2014 and the current year will continue to impact our proved reserves and PV-10 adversely as the prices used for such estimates under SEC rules are based on the trailing 12-month unweighted average prices. Lower prices used in estimating proved reserves may result in a reduction in volumes due to economic limits or render undeveloped reserves non-economic, which in turn, without significant additions to proved reserves, may make it more likely that we will incur future impairment charges against our oil and natural gas properties under full cost accounting.

General and administrative expense. We reported general and administrative expenses of $4.2 million for the three months ended March 31, 2015 compared to $4.8 million for the three months ended March 31, 2014. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $1.5 million for the three months ended March 31, 2015 and 2014. Excluding stock-based compensation expense, general and administrative expense decreased $508,000 to $2.7 million for the three months ended March 31, 2015 compared to the three months ended March 31, 2014. This decrease is primarily due to lower legal expense.

Interest expense. We reported interest expense of $7.6 million for the three months ended March 31, 2015 compared to $6.9 million for the three months ended March 31, 2014. The increase in interest expense is directly related to the $467,000 of costs to amend certain covenants under our Revolving Credit Facility coupled with increased borrowings outstanding under the Revolving Credit Facility.

Dividends on preferred stock. We reported dividends on preferred stock of $3.6 million for the three months ended March 31, 2015 and 2014. The Series A Preferred Stock had a stated value of approximately $78.8 million and $77.6 million at March 31, 2015 and 2014, respectively, and carries a cumulative dividend rate of 8.625% per annum. Dividends on the Series A Preferred Stock were $2.2 million and $2.1 million for the three months ended March 31, 2015 and 2014, respectively. The Series B Preferred Stock had a stated value of approximately $50.0 million at March 31, 2015 and 2014 and carries a cumulative dividend rate of 10.75% per annum. Dividends on the Series B Preferred Stock were $1.4 million for the three months ended March 31, 2015 and 2014. Based on the number of shares of Series A Preferred Stock and Series B Preferred Stock outstanding at March 31, 2015, our future stated preferred dividend expense is approximately $3.6 million per quarter, which is subject to being declared and paid monthly.

Liquidity and Capital Resources

Overview. Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities, availability under the Revolving Credit Facility, access to capital markets, to the extent available, and potential asset sales. We believe that the funds from operating cash flows, available borrowings under our Revolving Credit Facility and proceeds from capital markets transactions and asset sales should be sufficient to meet our cash requirements for at least the next 12 months. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in oil, condensate, natural gas and NGLs prices, drilling results and cash flow.

For the three months ended March 31, 2015, we reported cash flows provided by operating activities of $33.1 million. For the three months ended March 31, 2015, we reported net cash used in investing activities of $46.7 million primarily for the development of oil and natural gas properties. For the three months ended March 31, 2015, we reported net cash provided by financing activities of $14.7 million, consisting primarily of $20.0 million of net borrowings under our Revolving Credit Facility partially offset by $3.6 million of preferred stock dividends paid and $1.4 million of tax withholding related to restricted stock and PBU vestings during the period. As a result of these activities, our cash and cash equivalents balance increased by $1.1 million, resulting in a cash and cash equivalents balance of $12.1 million at March 31, 2015.

At March 31, 2015, we had a net working capital surplus of approximately $155,000. At March 31, 2015, availability under our Revolving Credit Facility was $135.0 million.

Future capital and other expenditure requirements. Capital expenditures for the remainder of 2015, excluding acquisitions, are currently projected to be approximately $60.9 million. In the Appalachian Basin and Mid-Continent, we expect to spend $15.3 million and $40.3 million, respectively, for drilling, completion, infrastructure, lease acquisition and seismic costs. In addition, we have allocated $5.3 million for capitalized interest and other costs. We plan to fund our

33

remaining 2015 capital budget through existing cash balances, internally generated cash flow from operating activities, borrowings under the Revolving Credit Facility and possible capital markets transactions and divestitures of assets, or some combination thereof.

We are closely monitoring the recent volatility in the commodity markets, in particular the recent drop in oil prices and widening of basis differentials in Appalachia, and we are developing capital plans responsive to changes that are occurring in the commodity and capital markets. Our capital expenditures and the scope of our drilling activities may change as a result of several factors, including, but not limited to, changes in oil, condensate, natural gas and NGLs prices, costs of drilling and completion and leasehold acquisitions, drilling results, and changes in the borrowing base under the Revolving Credit Facility. We operate approximately 100% of our remaining budgeted 2015 capital expenditures, and thus, we could reduce a significant portion of 2015 capital expenditures if necessary to better match available capital resources.

Operating cash flow and commodity hedging activities. Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil, condensate, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions including national and worldwide economic activity, weather, infrastructure capacity to reach markets, supply levels and other variable factors. These factors are beyond our control and are difficult to predict.

To mitigate some of the potential negative impact on cash flows caused by changes in oil, condensate, natural gas and NGLs prices, we have entered into financial commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk. The crude oil fixed price swaps provide price protection for our future oil sales and butane, isobutene and pentanes components of our NGLs production as these heavy components of NGLs have pricing that correlates closely with oil pricing. We have designated 50% of our current crude hedges as price protection for a portion of our NGLs production. For additional information regarding our hedging activities, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report.

At March 31, 2015, the estimated fair value of all of our commodity derivative instruments was a net asset of $31.8 million, comprised of current and non-current assets and liabilities. By removing the price volatility from a portion of our oil, condensate, natural gas and NGLs sales for 2015 through 2018, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flows for those periods. While mitigating negative effects of falling commodity prices, certain derivative contracts also limit the benefits we could receive from increases in commodity prices. In conjunction with certain commodity derivative hedging activity, we deferred the payment of certain put premiums for the production month period April 2015 through August 2018. At March 31, 2015, we had a current commodity premium payable of $2.5 million and a long-term commodity premium payable of $4.8 million. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month.

As of March 31, 2015, all of our commodity derivative hedge positions were with a multinational energy company or large financial institutions, each of which is not known to us to be in default on their derivative positions. We are exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, we do not anticipate non-performance by such counterparties.

Revolving Credit Facility. Our Revolving Credit Facility provides for a maximum amount of $500.0 million, subject to a borrowing base, which, at December 31, 2014, was $145.0 million. Effective March 9, 2015, the borrowing base under the Revolving Credit Facility was increased by the lenders to $200.0 million. At March 31, 2015, we had $65.0 million of borrowings outstanding under our Revolving Credit Facility.

At March 31, 2015, we were in compliance with all financial covenants under the Revolving Credit Facility. For a more detailed description of the terms of our Revolving Credit Facility, see Part I, Item 1. “Financial Statements, Note 4 – Long-Term Debt” of this report.

Senior Secured Notes. We have $325.0 million of senior secured notes outstanding, which are due May 15, 2018. For a more detailed description of the terms of our Notes, see Part I, Item 1. “Financial Statements, Note 4 - Long-Term Debt - Senior Secured Notes” of this report. At March 31, 2015, we were in compliance with all covenants under the indenture governing the Notes.

Series A Preferred Stock. We pay cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three months endedMarch 31, 2015, we recognized dividend expense of $2.2 million for the Series A Preferred Stock.

Series B Preferred Stock. We pay cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the three months endedMarch 31, 2015, we recognized dividend expense of $1.4 million for the Series B Preferred Stock.

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Off-Balance Sheet Arrangements

As of March 31, 2015, we had no off-balance sheet arrangements. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Commitments and Contingencies

As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

We are party to various litigation matters and administrative claims arising out of the normal course of business. Although the ultimate outcome of each of these matters cannot be absolutely determined and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters, management does not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows. A discussion of current legal proceedings is set forth in Part I, Item 1. “Financial Statements, Note 11 – Commitments and Contingencies” of this report.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying condensed consolidated financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

• It requires assumptions to be made that were uncertain at the time the estimate was made; and

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

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Part I, Item I. “Financial Statements, Note 2 – Summary of Significant Accounting Policies” of this report and in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” included in our 2014 Form 10-K.

Recent Accounting Developments

For a discussion of recent accounting developments, see Part I, Item 1. “Financial Statements, Note 2 – Summary of Significant Policies” of this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major commodity price risk exposure is to the prices received for our oil, condensate, natural gas and NGLs production. Our results of operations and operating cash flows are affected by changes in market prices. Realized commodity prices received for our production are the spot prices applicable to oil, condensate, natural gas and NGLs in the region produced. Prices received for oil, condensate, natural gas and NGLs are volatile and unpredictable and are beyond our control. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. For the three months ended March 31, 2015, a 10% change in the prices received for oil, condensate, natural gas and NGLs production would have had an approximate $2.4 million impact on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report for additional information regarding our hedging activities.

Interest Rate Risk

We are exposed to changes in interest rates as a result of our Revolving Credit Facility. At March 31, 2015, we had $65.0 million of borrowings outstanding under our Revolving Credit Facility. We have not entered into interest rate hedging arrangements in the past, and have no current plans to do so. Due to the potential for fluctuating balances in the amount outstanding under our Revolving Credit Facility, we do not believe such arrangements to be cost effective. The amount outstanding under the Notes is at fixed interest of 8.625% per annum. We currently do not use interest rate derivatives to mitigate our exposure to the volatility in interest rates, including under the Revolving Credit Facility, as this risk is minimal.

Item 4. Controls and Procedures

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Management’s Evaluation on the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of March 31, 2015. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2015, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

36

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

A discussion of current legal proceedings is set forth in Part I, Item 1. “Financial Statements, Note 11 – Commitments and Contingencies” of this report.

Item 1A. Risk Factors

Information about material risks related to our business, financial condition and results of operations for the three months endedMarch 31, 2015 does not materially differ from that set out under Part I, Item 1A. “Risk Factors” in our 2014 Form 10-K. You should carefully consider the risk factors and other information discussed in our 2014 Form 10-K, as well as the information provided in this report. These risks are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, operating results and cash flows.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table sets forth our share repurchase activity for each period presented.

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, 2015 - January 31, 2015	545,176	$	2.40	—	n/a
March 1, 2015 - March 31, 2015	49,920	$	2.25	—	n/a

Shares purchased represent shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock units held by our employees and Board of Directors.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosure

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The exhibits required to be filed or furnished pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Form 10-Q and are incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		GASTAR EXPLORATION INC.
Date:	May 7, 2015	By:	/S/ J. RUSSELL PORTER
			J. Russell Porter
			President and Chief Executive Officer
			(Duly authorized officer and principal executive officer)

Date:	May 7, 2015	By:	/S/ MICHAEL A. GERLICH
			Michael A. Gerlich
			Senior Vice President and Chief Financial Officer
			(Duly authorized officer and principal financial and accounting officer)

38

EXHIBIT INDEX

Exhibit Number	Description
2.1	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).
2.2	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).
2.3†**	Purchase and Sale Agreement, dated May 1, 2015, by and between Gastar Exploration Inc. and Oklahoma Energy Acquisitions, LP.
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 of Gastar Exploration, Inc. into Gastar Exploration USA, Inc. (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 8-A 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).
10.1	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 (incorporated by reference to Exhibit 10.8 of the Annual Report on Form 10-K filed with the SEC on March 12, 2015. File No. 001-35211).
10.2*	Third Amendment to Employment Agreement entered into by and between Gastar Exploration Inc. and Michael A. Gerlich as of March 10, 2015 (incorporated by reference to Exhibit 10.21 of the Annual Report on Form 10-K filed with the SEC on March 12, 2015. File No. 001-35211).
10.3*	Third Amendment to Amended and Restated Gastar Exploration Inc. Employee Change of Control Severance Plan, dated March 10, 2015 (incorporated by reference to Exhibit 10.32 of the Annual Report on Form 10-K filed with the SEC on March 12, 2015. File No. 001-35211).
31.1†	Certification of Principal Executive Officer of Gastar Exploration Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†	Certification of Principal Financial Officer of Gastar Exploration Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1††	Certification of Principal Executive Officer and Principal Financial Officer of Gastar Exploration Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

39

101.INS†	XBRL Instance Document
101.SCH†	XBRL Taxonomy Extension Schema Document
101.CAL†	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF†	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB†	XBRL Taxonomy Extension Label Linkbase Document
101.PRE†	XBRL Taxonomy Extension Presentation Linkbase Document

___________________________________

† Filed herewith.

†† By SEC rules and regulations, deemed not filed for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, nor shall it be deemed incorporated by reference into any filing under the Securities Act, or the Exchange Act.

* Management plan or compensatory plan or arrangement.

** Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments to Exhibit 2.3 have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

40

EX-2.3

Exhibit 2.3

PURCHASE AND SALE AGREEMENT

BY AND BETWEEN

GASTAR EXPLORATION INC.

AS SELLER,

AND

OKLAHOMA ENERGY ACQUISITIONS, LP

AS BUYER

DATED MAY 1, 2015

TABLE OF CONTENTS
		Page
	Article I
	DEFINITIONS
Section 1.01	Defined Terms	1
Section 1.02	Interpretation	11
	Article II
	ASSETS
Section 2.01	Agreement to Sell and Purchase	11
Section 2.02	Assets	11
Section 2.03	Excluded and Reserved Assets	12
Section 2.04	Revenues and Expenses	14
	Article III
	CONSIDERATION
Section 3.01	Purchase Price	14
Section 3.02	Deposit	14
Section 3.03	Allocated Values	15
Section 3.04	Purchase Price Allocation	15
	Article IV
	TITLE MATTERS
Section 4.01	General Disclaimer of Title Warranties and Representations	15
Section 4.02	Special Warranty	15
Section 4.03	Recovery on Special Warranty	16
Section 4.04	Title Examination Period	16
Section 4.05	Title Defects	16
Section 4.06	Notice of Title Defects	18
Section 4.07	Remedies for Title Defects	20
Section 4.08	Title Benefits	20
Section 4.09	Limitations	21
Section 4.10	Title Defect Amount	21
Section 4.11	Resolution of Title and Environmental Matters	22
Section 4.12	Consents to Assign	23
	Article V
	ENVIRONMENTAL
Section 5.01	Environmental Examination Period	24
Section 5.02	Environmental Defect	24
Section 5.03	Notice of Environmental Defects	24
Section 5.04	Remedies for Environmental Defects	26
Section 5.05	Limitations	26
	Article VI
	REPRESENTATIONS AND WARRANTIES
Section 6.01	Representations and Warranties of Seller	26
Section 6.02	Representations and Warranties of Buyer	30

	Article VII
	CERTAIN COVENANTS
Section 7.01	Access	31
Section 7.02	Confidentiality	32
Section 7.03	Dispositions of Assets	32
Section 7.04	Operations	32
Section 7.05	Governmental Bonds	33
Section 7.06	Non-Solicitation of Employees	33
Section 7.07	Additional Interests	33
Section 7.08	Seller’s Rights Under Chesapeake Agreement	33
Section 7.09	Amendment to Schedules	33
Section 7.10	Knowledge of Breach	34
Section 7.11	Casualty	34
	Article VIII
	CONDITIONS TO CLOSING
Section 8.01	Conditions to Seller’s Obligations	35
Section 8.02	Conditions to Buyer’s Obligations	35
	Article IX
	CLOSING
Section 9.01	Time and Place of Closing	36
Section 9.02	Closing Statement; Adjustments to Purchase Price at Closing	36
Section 9.03	Actions of Seller at Closing	39
Section 9.04	Actions of Buyer at Closing	40
	Article X
	CERTAIN POST-CLOSING OBLIGATIONS
Section 10.01	Operation of the Assets After Closing	40
Section 10.02	Files	40
Section 10.03	Further Cooperation	40
Section 10.04	Document Retention	40
Section 10.05	Suspense Accounts	41
	Article XI
	TERMINATION
Section 11.01	Right of Termination	41
Section 11.02	Effect of Termination	42
	Article XII
	ASSUMPTION AND INDEMNIFICATION
Section 12.01	Assumption and Indemnity	42
Section 12.02	Indemnification by Buyer	43
Section 12.03	Buyer's Environmental Indemnification	43
Section 12.04	Indemnification by Seller	44
Section 12.05	Limitations	44
Section 12.06	Negligence and Fault	44

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TABLE OF CONTENTS
		Page
	Article I
	DEFINITIONS
Section 1.01	Defined Terms	1
Section 1.02	Interpretation	11
	Article II
	ASSETS
Section 2.01	Agreement to Sell and Purchase	11
Section 2.02	Assets	11
Section 2.03	Excluded and Reserved Assets	12
Section 2.04	Revenues and Expenses	14
	Article III
	CONSIDERATION
Section 3.01	Purchase Price	14
Section 3.02	Deposit	14
Section 3.03	Allocated Values	15
Section 3.04	Purchase Price Allocation	15
	Article IV
	TITLE MATTERS
Section 4.01	General Disclaimer of Title Warranties and Representations	15
Section 4.02	Special Warranty	15
Section 4.03	Recovery on Special Warranty	16
Section 4.04	Title Examination Period	16
Section 4.05	Title Defects	16
Section 4.06	Notice of Title Defects	18
Section 4.07	Remedies for Title Defects	20
Section 4.08	Title Benefits	20
Section 4.09	Limitations	21
Section 4.10	Title Defect Amount	21
Section 4.11	Resolution of Title and Environmental Matters	22
Section 4.12	Consents to Assign	23
	Article V
	ENVIRONMENTAL
Section 5.01	Environmental Examination Period	24
Section 5.02	Environmental Defect	24
Section 5.03	Notice of Environmental Defects	24
Section 5.04	Remedies for Environmental Defects	26
Section 5.05	Limitations	26
	Article VI
	REPRESENTATIONS AND WARRANTIES
Section 6.01	Representations and Warranties of Seller	26
Section 6.02	Representations and Warranties of Buyer	30

	Article VII
	CERTAIN COVENANTS
Section 7.01	Access	31
Section 7.02	Confidentiality	32
Section 7.03	Dispositions of Assets	32
Section 7.04	Operations	32
Section 7.05	Governmental Bonds	33
Section 7.06	Non-Solicitation of Employees	33
Section 7.07	Additional Interests	33
Section 7.08	Seller’s Rights Under Chesapeake Agreement	33
Section 7.09	Amendment to Schedules	33
Section 7.10	Knowledge of Breach	34
Section 7.11	Casualty	34
	Article VIII
	CONDITIONS TO CLOSING
Section 8.01	Conditions to Seller’s Obligations	35
Section 8.02	Conditions to Buyer’s Obligations	35
	Article IX
	CLOSING
Section 9.01	Time and Place of Closing	36
Section 9.02	Closing Statement; Adjustments to Purchase Price at Closing	36
Section 9.03	Actions of Seller at Closing	39
Section 9.04	Actions of Buyer at Closing	40
	Article X
	CERTAIN POST-CLOSING OBLIGATIONS
Section 10.01	Operation of the Assets After Closing	40
Section 10.02	Files	40
Section 10.03	Further Cooperation	40
Section 10.04	Document Retention	40
Section 10.05	Suspense Accounts	41
	Article XI
	TERMINATION
Section 11.01	Right of Termination	41
Section 11.02	Effect of Termination	42
	Article XII
	ASSUMPTION AND INDEMNIFICATION
Section 12.01	Assumption and Indemnity	42
Section 12.02	Indemnification by Buyer	43
Section 12.03	Buyer's Environmental Indemnification	43
Section 12.04	Indemnification by Seller	44
Section 12.05	Limitations	44
Section 12.06	Negligence and Fault	44

Section 12.07	Exclusive Remedy	44
Section 12.08	Expenses	45
Section 12.09	Survival; Knowledge	45
Section 12.10	Non-Compensatory Damages	46
Section 12.11	Indemnification Actions	46
Section 12.12	Characterization of Indemnity Payments	47
	Article XIII
	LIMITATIONS ON REPRESENTATIONS AND WARRANTIES
Section 13.01	Disclaimers of Representations and Warranties	47
Article XIV		49
	TAX MATTERS
Section 14.01	Allocation of Asset Taxes	49
Section 14.02	Transfer Taxes	50
Section 14.03	Cooperation	50
Section 14.04	Refunds	50
Section 14.05	Post-Closing Taxes	51
	Article XV
	MISCELLANEOUS
Section 15.01	Filings, Notices and Certain Governmental Approvals	51
Section 15.02	Entire Agreement	51
Section 15.03	Waiver	51
Section 15.04	Publicity	51
Section 15.05	No Third Party Beneficiaries	51
Section 15.06	Assignment	51
Section 15.07	Governing Law	52
Section 15.08	Notices	52
Section 15.09	Exclusivity	53
Section 15.10	Severability	53
Section 15.11	Counterparts	53
Section 15.12	Amendment	53
Section 15.13	Schedules and Exhibits	53

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Exhibits
Exhibit A	Part 1	Leases/Allocated Values
Exhibit A	Part 1-A	Term Leases/Allocated Values
Exhibit A	Part 1-B	Overriding Royalty Interests/Allocated Values
Exhibit A	Part 2	Wells/Allocated Values
Exhibit A	Part 3	Easements, Rights-of-Way, Surface Fees and Surface Leases
Exhibit A	Part 4	Material Contracts
Exhibit B	–	Excluded Assets
Exhibit C	–	Form of Assignment
Exhibit D	–	Form of Mineral Deed
Schedules
Schedule 1.01	–	Knowledge
Schedule 1.01(a)	–	Mechanics’ Liens
Schedule 1.01(b)	–	Tax Liens
Schedule 6.01(c)	–	Consents
Schedule 6.01(e)	–	Noncontravention
Schedule 6.01(f)	–	Litigation
Schedule 6.01(g)	–	Brokers’ Fees
Schedule 6.01(h)	–	Taxes
Schedule 6.01(i)	–	Royalty Payments
Schedule 6.01(j)	–	Hydrocarbon Sales
Schedule 6.01(k)	–	Environmental Notices
Schedule 6.01(l)	–	Compliance with Laws
Schedule 6.01(n)	–	AFEs
Schedule 6.01(p)	–	Imbalances
Schedule 6.01(q)	–	Payout Balances
Schedule 6.01(r)	–	Plugging and Abandonment
Schedule 6.01(u)	–	Suspended Funds
Schedule 6.02(c)	–	Consents
Schedule 7.04	–	Interim Period Operations

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PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”) is made and entered into this 1^st day of May, 2015, by and between Gastar Exploration Inc., a Delaware corporation (“Seller”) and Oklahoma Energy Acquisitions, LP, a Texas limited partnership (“Buyer”). Buyer and Seller are sometimes referred to herein, collectively, as the “Parties” and, individually, as a “Party.”

W I T N E S S E T H:

Seller desires to sell and assign, and Buyer desires to purchase and pay for all of Seller’s right, title and interest in and to the Assets (as defined hereinafter) effective as of the Effective Time (as defined hereinafter).

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged by each Party, the Parties agree as follows:

Article IDEFINITIONS

Section 1.01Defined Terms. As used in this Agreement, the following terms shall have the meanings set forth below:

“Accounting Arbitrator” shall have the meaning given that term in Section 9.02(d).

“Acreage Trade and Purchase Agreement” shall mean that certain Acreage Trade and Purchase Agreement dated as of October 1, 2014 between Chesapeake Exploration, L.L.C. and Gastar Exploration U.S.A., Inc.

“Adjusted Purchase Price” shall have the meaning given that term in Section 3.01.

“AFEs” shall have the meaning given that term in Section 6.01(n).

“Affiliate” shall mean any Person that, directly or indirectly, through one or more entities, controls, is controlled by or is under common control with the Person specified. For the purpose of the immediately preceding sentence, the term “control” and its syntactical variants mean the power, direct or indirect, to direct or cause the direction of the management of such Person, whether through the ownership of voting securities, by contract, agency or otherwise.

“Agreement” shall mean this Agreement, together with the Exhibits and Schedules attached hereto, as the same may be amended from time to time in accordance with the terms hereof.

“Allocated Value” shall have the meaning given that term in Section 3.03.

“Allocation” shall have the meaning given that term in Section 3.04.

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“Asserted Environmental Defect” shall have the meaning given that term in Section 5.03.

“Asserted Title Defect” shall have the meaning given that term in Section 4.06.

“Assets” shall have the meaning given that term in Section 2.02.

“Asset Taxes” means ad valorem, property, severance, production, excise, sales, use and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons or the receipt of proceeds therefrom, but excluding, for the avoidance of doubt, (a) Income Taxes and (b) Transfer Taxes.

“Assignments” shall have the meaning given that term in Section 9.03(a).

“Assumed Obligations” shall have the meaning given that term in Section 12.01.

“Benefit Deductible” shall have the meaning given that term in Section 4.08(b).

“Business Day” shall mean any day other than a Saturday, a Sunday or a day on which banks in Houston, Texas are authorized or obligated by Law to close.

“Buyer” shall have the meaning given that term in the preamble.

“Buyer Indemnitees” shall mean Buyer and its members, partners, shareholders and Affiliates, and the officers, board of directors and/or managers, employees, agents and representatives of all of the foregoing Persons.

“Chesapeake Cooperation Agreement” shall mean that certain Cooperation Agreement dated effective as of June 7, 2013 between Chesapeake Exploration, L.L.C. and Gastar Exploration U.S.A., Inc.

“Claim” shall have the meaning given that term in Section 12.11(b).

“Claim Notice” shall have the meaning given that term in Section 12.11(b).

“Closing” shall have the meaning given that term in Section 9.01.

“Closing Date” shall have the meaning given that term in Section 9.01.

"Closing Statement" shall have the meaning given that term in Section 9.02.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” shall mean that certain Confidentiality Agreement, dated as of February 25, 2015, by and between Buyer and Seller.

“Consent” shall have the meaning given that term in Section 6.01(c).

"Consultant" shall have the meaning given that term in Section 4.11(a).

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“Contracts” shall have the meaning given that term in Section 2.02(f).

“Cure Period” shall have the meaning given that term in Section 4.06.

“Customary Post-Closing Consents” shall mean consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer that are customarily obtained after the assignment of properties similar to the Assets.

“Defect Deductible” shall have the meaning given that term in Section 4.09.

“Defensible Title” shall have the meaning given that term in Section 4.05.

“Deposit” shall have the meaning given that term in Section 3.02(a).

“Dispute Notice” shall have the meaning given that term in Section 9.02(c).

“Effective Time” shall mean 7:00 a.m. Houston time on April 1, 2015.

“Environmental Defect” shall have the meaning given that term in Section 5.02.

“Environmental Defect Amount” shall have the meaning given that term in Section 5.04(a).

“Environmental Defect Notice” shall have the meaning given that term in Section 5.03.

“Environmental Defect Property” shall have the meaning given that term in Section 5.03.

“Environmental Examination Period” shall have the meaning given that term in Section 5.01.

“Environmental Laws” shall mean all applicable federal, state and local Laws (in each case, as the same have been amended prior to the date of this Agreement) pertaining to the environment (including natural resources), the prevention of pollution, the remediation of contamination, or the restoration of the environment, including the Clean Air Act, the Clean Water Act, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980, the Superfund Amendments and Reauthorization Act of 1986, the Occupational Safety and Health Act of 1970, the Resource Conservation and Recovery Act of 1976, the Hazardous and Solid Waste Amendments Act of 1984, the Safe Drinking Water Act, the Toxic Substances Control Act and the Oil Pollution Act of 1990.

“Escrow Agent” shall mean Wells Fargo Bank, National Association.

“Escrow Agreement” shall mean that certain Escrow Agreement among Buyer, Seller, and Escrow Agent to be entered into pursuant to the terms hereof.

“Escrow Amount” shall mean $4,620,221.72.

“Excluded Assets” shall have the meaning given that term in Section 2.03.

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“Facilities” shall have the meaning given that term in Section 2.02(c).

“Files” shall have the meaning given that term in Section 2.02(h).

“Final Accounting Statement” shall have the meaning given that term in Section 9.02(c).

“GAAP” means United States generally accepted accounting principles, consistently applied, as published by the Financial Accounting Standards Board.

“Governmental Authority” shall mean any federal, state, local or foreign government or any court of competent jurisdiction, regulatory or administrative agency, commission or other governmental authority that exercises jurisdiction over any of the Assets.

“Hydrocarbons” shall mean oil and gas and other hydrocarbons produced or processed in association therewith.

“Imbalance” shall mean any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Seller therein and the share of production from the relevant Well to which Seller is entitled.

“Income Taxes” shall mean any income, franchise and similar Taxes.

“Indemnitee” shall have the meaning given that term in Section 12.11(a).

“Indemnitor” shall have the meaning given that term in Section 12.11(a).

“Indemnity Deductible” shall have the meaning given that term in Section 12.05(a).

“Interim Period” shall mean that period commencing on the date of the execution of this Agreement and terminating upon the earlier of the Closing or the termination of this Agreement.

“Knowledge” shall mean, with respect to Seller and Buyer, the actual knowledge, without investigation, of the Persons listed on Schedule 1.01 hereto.

“Law” shall mean any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

“Leases” shall have the meaning given that term in Section 2.02(a).

“Liabilities” shall mean, except as provided in Section 12.10, any and all claims, causes of action, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines or costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury or death or property damage.

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“Liens” shall mean any mortgage, lien, security interest or other charge or encumbrance, any financing lease having substantially the same economic effect as any of the foregoing, any assignment of the right to receive income, or any other type of preferential arrangement.

“Lowest Cost Response” shall mean the response allowed under Environmental Laws that addresses the condition present at the lowest cost (considered as a whole taking into consideration any material negative impact such response may have on the operations of the relevant Assets, obligations under the Leases, and the ongoing liability of the Buyer as a result of response) as compared to any other response that is allowed under Environmental Laws.

“Material Adverse Effect” shall mean an event or circumstance that results in a material adverse effect on the ownership or operation of the Assets taken as a whole and as currently operated as of the date of this Agreement, or an occurrence or event that materially hinders or impedes the consummation by Seller of the transactions contemplated by this Agreement; provided, however, that no change, effect, event, occurrence, state of facts or development that arises or results from the following shall constitute a Material Adverse Effect: (a) changes in general economic, capital market, regulatory or political conditions or changes in applicable Law or the interpretation therefor; (b) changes that affect generally the oil and gas industry; (c) the declaration by the United States of a national emergency or acts of war or terrorism or act of God that, in any case, do not disproportionately affect the Assets in any material respect; (d) the entry into or announcement of the transactions contemplated by this Agreement, or the consummation of the transactions contemplated hereby; (e) any changes in commodity prices; (f) any action or omission of Seller taken in accordance with the terms of this Agreement without the violation thereof or with the prior written consent of Buyer; or (g) any normal decline in Well performance.

“Material Contract” shall mean the following (excluding any Leases) to the extent relating to the Assets:

(a)    any Contract that (i) can reasonably be expected to result in aggregate payments by Seller of more than $100,000 during the current or any subsequent fiscal year (based solely on the terms thereof and without regard to any expected increase in volumes or revenues) or (ii) cannot be terminated without penalty on 90 days or less notice;

(b)    any Contract that can reasonably be expected to result in aggregate revenues to Seller of more than $100,000 during the current or any subsequent fiscal year (based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(c)    any purchase and sale, transportation, processing, refining or similar Contract (in each case) to which Seller is a party or to which the Assets are subject to that is not terminable without penalty on 90 days or less notice;

(d)    any indenture, mortgage, loan, note, credit, sale-leaseback or similar Contract (in each case) to which any of the Assets are subject and all related security agreements or similar agreements associated therewith, unless such Assets are to be released from such Contracts on or before the Closing; and

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(e)    any Contract between an Affiliate of Seller and Seller that will not be terminated on or prior to Closing.

“Net Acre” means, as computed separately with respect to each Lease, (a) the number of gross acres in the lands covered by such Lease, multiplied by (b) the undivided percentage interest in oil, gas and other minerals covered by such Lease in such lands and attributable to the Target Formations, multiplied by (c) Seller’s percentage Working Interest or undivided interest in such Lease, provided that if items (b) and/or (c) vary as to different areas of such lands (including depths) covered by such Lease, the Parties shall agree on a separate calculation for each such area to calculate total Net Acre’s attributable to such Lease.

“Net Acre Allocation” means an amount per Net Acre as set forth on Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable.

“Net Revenue Interest”, with respect to any Well or Term Lease, means the percentage interest in and to all Hydrocarbons attributable to the Target Formations produced, saved, and sold from or allocated to such Well or Term Lease, after giving effect to all Royalties.

“Operating Expenses” means all operating expenses (including costs of insurance) and capital expenditures incurred in the ownership or operation of the Assets in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and Overhead Costs charged to the Assets under the relevant operating agreement or unit agreement, if any, but excluding (a) Liabilities for personal injury or death, property damage or violation of any Law, (b) obligations to plug Wells, dismantle Facilities, close pits or restore the surface around such Wells, Facilities and pits, (c) environmental Liabilities, including obligations to remediate any contamination of groundwater, surface water, soil, sediments, Facilities or personal property under applicable Environmental Laws, (d) obligations with respect to Imbalances, (e) obligations to pay working interests, royalties, overriding royalties or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to the Properties, including those held in suspense and (f) any Asset Taxes or Income Taxes.

“Overhead Costs” shall mean, with respect to each Well operated by Seller or any of its Affiliates, (a) the overhead amount under the joint operating agreement applicable to such Well that would be attributable to Seller’s interest therein for the period of time from and after the Effective Time up to (and including) the Closing Date, or (b) if no such joint operating agreement is in existence with respect to any Well, then the amount obtained by multiplying (i) $45 per dayfor such Well operated by Seller or any of its Affiliates by (ii) the number of days elapsing from and after the Effective Time up to (and including) the Closing Date.

“Parties” shall have the meaning given that term in the preamble.

“Permitted Encumbrances” shall mean any of the following:

(a)    the terms, conditions, restrictions, exceptions, reservations, limitations and other matters contained in the agreements, instruments and documents that create or reserve to Seller its interests in any of the Assets, including the Leases and assignments thereof, to

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the extent that such agreements, instruments and documents do not operate to reduce any Net Revenue Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable), increase any Working Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) without a proportionate increase in the corresponding Net Revenue Interest of Seller, or reduce the number of Net Acres of Seller (as set forth in Exhibit A—Part 1);

(b)    any (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses that were incurred incidental to maintenance, development, production or operation of the Assets or for the purpose of developing, producing or processing Hydrocarbons therefrom or therein that individually or in the aggregate do not operate to reduce any Net Revenue Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable), increase any Working Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) without a proportionate increase in the corresponding Net Revenue Interest of Seller, or reduce the number of Net Acres of Seller (as set forth in Exhibit A—Part 1) and are customary in the industry and are not such as to interfere materially with the operation, value or use of any of the Assets, and (ii) materialman’s, mechanic’s, repairman’s, vendor’s, construction, employee’s, contractor’s, operator’s or other similar liens or charges for the payment of expenses arising in the ordinary course of business (in each case) that are not yet delinquent or, if delinquent, that are being contested in good faith in the ordinary course of business as identified on Schedule 1.01(a) as of the Effective Time and for which Seller retains liability for the period prior to the Effective Time;

(c)    any liens for Taxes not yet delinquent or, if delinquent, that are being contested in good faith in the ordinary course of business as identified on Schedule 1.01(b) as of the Effective Time and for which Seller retains liability for the period prior to the Effective Time;

(d)    any liens or security interests created by law;

(e)    any obligations or duties affecting the Assets to any municipality or Governmental Authority with respect to any franchise, grant, license or permit and all applicable Laws;

(f)    any easements, rights-of-way, servitudes, licenses, permits and other similar rights for the purposes of pipelines, transmission lines, Facilities or other similar fixtures or personalty that do not operate to reduce any Net Revenue Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) or increase any Working Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) without a proportionate increase in the corresponding Net Revenue Interest of Seller, and any other matters set forth on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable, and which would be considered acceptable by a reasonably prudent operator engaged in the business of owning and operating oil and gas properties;

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(g)    all overriding royalties, net profits interests, carried interests, production payments, reversionary interests and other burdens on, or deductions from the proceeds of production, that do not operate to reduce any Net Revenue Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) or increase any Working Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) without a proportionate increase in the corresponding Net Revenue Interest of Seller, and any other matters set forth on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable;

(h)    preferential rights to purchase or similar agreements;

(i)    Third Party consents to assignments or similar agreements to the extent set forth on Schedule 6.01(c);

(j)    such Title Defects as Buyer has waived or has been deemed to have waived, or which are remedied at Closing pursuant to Section 4.07;

(k)    all rights to consent by, required notices to, filings with or other actions by any Governmental Authority in connection with the sale or conveyance of oil and gas leases or interests therein;

(l)    all Contracts, including all production sales contracts; division orders; contracts for sale, purchase, exchange, refining or processing of Hydrocarbons; unitization and pooling designations, declarations, orders and agreements; operating agreements; agreements of development; area of mutual interest agreements; gas balancing or deferred production agreements; processing agreements; plant agreements; pipeline, gathering and transportation agreements; injection, repressuring and recycling agreements; carbon dioxide purchase or sale agreements; salt water or other disposal agreements; seismic or geophysical permits or agreements; and any and all other agreements, (in each case) that do not operate to reduce any Net Revenue Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable), increase any Working Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) without a proportionate increase in the corresponding Net Revenue Interest of Seller, or reduce the number of Net Acres of Seller (as set forth in Exhibit A—Part 1);

(m)    all defects and irregularities (i) based on a gap in Seller’s chain of title in the state’s records as to state Leases, or in the county records as to other Leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain which documents shall be included in a Title Defect Notice, or (ii) to the extent affecting any depths other than the Target Formations;    

(n)    all defects and irregularities affecting the Assets that do not operate to reduce any Net Revenue Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable), increase any Working Interest of Seller (as set forth in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable) without a proportionate increase in the corresponding Net Revenue Interest of Seller, reduce the number of Net Acres of Seller (as set forth in Exhibit A—Part 1) or otherwise interfere materially with the operation or use of the Assets

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as currently operated and which would be considered acceptable by a reasonably prudent operator engaged in the business of owning and operating oil and gas properties; and

(o)    any indenture, mortgage, loan, note, credit, sale-leaseback or similar Contract for borrowed money, (in each case) to which the Assets are subject and all related security agreements or similar agreements associated therewith, so long as such Assets are released as security under such Contracts on or before the Closing.

“Person” shall mean an individual, corporation, partnership, association, trust, limited liability company or any other entity or organization, including government or political subdivisions or an agency, unit or instrumentality thereof.

“Properties” shall have the meaning given that term in Section 2.02(b).

“Purchase Price” shall have the meaning given that term in Section 3.01.

“Retained Liabilities”means all Liabilities and obligations, known or unknown, arising from, based upon, related to or associated with (i) Seller’s failure to properly, timely and legally pay, in accordance with the terms of any Lease and applicable Laws, all Royalties with respect to the Assets due by Seller and attributable to Seller’s ownership of the Assets prior to the Effective Time (other than for amounts held in suspense pursuant to Section 10.05); (ii) any Liabilities to third parties for personal injury or death attributable to Seller’s operation of the Assets prior to the Closing Date; (iii) transportation or disposal of waste to premises not included in the Assets occurring prior to the Closing Date and (iv) any Assets excluded pursuant to Section 4.07, Section 5.04 or Section 4.12(a).

“Royalties” shall have the meaning given that term in Section 6.01(i).

“Seller” shall have the meaning given that term in the preamble.

“Seller Indemnitees” shall mean Seller and its respective members, partners, shareholders, Affiliates, successors and assigns, and the officers, board of directors and/or managers, employees, agents, and representatives of all of the foregoing Persons.

“Seller Taxes” shall mean (a) Income Taxes imposed by any applicable laws on Seller, and (b) Asset Taxes allocable to Seller pursuant to Section 14.01 (taking into account, and without duplication of, (i) such Asset Taxes effectively borne by Seller as a result of the adjustments to the Purchase Price made pursuant to Section 9.02, and (ii) any payments made from one Party to the other in respect of Asset Taxes pursuant to Section 14.01(c)).

“Special Warranty”shall have the meaning given that term in Section 4.02.

“Special Warranty Notices”shall have the meaning given that term in Section 4.03.

“Straddle Period”means any Tax period beginning before and ending after the Effective Time.

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“Target Acreage”shall mean oil and gas leases covering the Target Formation located within N/2 of T15N R5W, T16N R5W, T17N R5W, T17N R6W, or T18N, R5W of Kingfisher County, Oklahoma.

“Target Acreage Payment Amount” means an amount equal to Seller’s actual and documented direct costs of acquisition, excluding Seller’s overhead, internal or administrative costs for Target Acreage acquired by Seller or its Affiliates during the period between the date of the execution of this Agreement and the Closing Date.

“Target Formations” means the depths and formations underlying and located within Kingfisher County, Oklahoma conveying all rights below the base of the Chester which generally include the stratigraphic equivalent depths found in the Marlin Oil Company, Morrow-1 well (API # 35-073-243300000), located in Section 15, Township 16N and Range 7W, Kingfisher County, Oklahoma, with that stratigraphic equivalent (being the base of the Chester and top of the Mississippi) found on the electric log at the measured vertical depth of 7,642 feet. The Parties recognize that the actual depths of the Target Formations will vary across the Leases.

“Tax Returns” shall mean any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto and any amendment thereof.

“Taxes” means any taxes, assessments and other governmental charges imposed by any Governmental Authority, including income, profits, gross receipts, employment, stamp, occupation, premium, alternative or add-on minimum, ad valorem, real property, personal property, transfer, real property transfer, value added, sales, use, customs, duties, capital stock, franchise, excise, withholding, social security (or similar), unemployment, disability, payroll, windfall profit, severance, production, estimated or other tax, including any interest, penalty or addition thereto.

“Term Leases” shall have the meaning given that term in Section 2.02(a).

“Third Party” shall mean any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

“Title Benefit” shall mean any right, circumstance or condition that operates (a) to increase the Net Revenue Interest of Seller in any Well or Term Lease above that shown on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable, to the extent not causing a greater than proportionate increase in Seller’s Working Interest in such Well or Term Lease above that shown in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable, (b) to decrease the Working Interest of Seller in any Well or Term Lease below that shown for such Term Lease in Exhibit A—Part 1-A or Well in Exhibit A—Part 2, to the extent the same causes a decrease in Seller’s Working Interest that is proportionately greater than the decrease in Seller’s Net Revenue Interest therein below that shown in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable or (c) to increase the Net Acres of Seller in any Lease or Term Lease above that shown in Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable.

“Title Benefit Amount” shall have the meaning given that term in Section 4.08(b).

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“Title Benefit Property” shall have the meaning given that term in Section 4.08(a).

“Title Defect” shall have the meaning given that term in Section 4.05.

“Title Defect Amount” shall have the meaning given such term in Section 4.07(a).

“Title Defect Notice” shall have the meaning given such term in Section 4.06.

“Title Defect Property” shall have the meaning given such term in Section 4.06.

“Title Examination Period” shall have the meaning given that term in Section 4.04.

“Transfer Taxes” shall have the meaning given that term in Section 14.02.

“Unit Interests” shall have the meaning given that term in Section 2.02(a).

“Wells” shall have the meaning given that term in Section 2.02(b).

“Working Interest”, with respect to any Term Lease or Well, means the percentage interest in and to such Term Lease or Well that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Term Lease or Well, but without regard to the effect of any Royalties.

Section 1.02Interpretation. As used in this Agreement, unless the context otherwise requires, the term “includes” and its syntactical variants means “includes but is not limited to.” The headings and captions contained in this Agreement have been inserted for convenience only and shall not be deemed in any manner to modify, explain, enlarge or restrict any of the provisions hereof. Preparation of this Agreement has been a joint effort of the Parties and the resulting document shall not be construed more severely against one of the Parties than against the other. All references herein to “Sections” and “Articles” in this Agreement shall refer to the corresponding Section and Article of this Agreement unless specific reference is made to such sections of another document or instrument. The words “hereof,” “herein” and “hereunder” and words of similar import when used in any agreement or instrument shall refer to such agreement or instrument as a whole and not to any particular provision of such agreement or instrument.

ARTICLE IIASSETS

Section 2.01Agreement to Sell and Purchase. Subject to the terms and conditions of this Agreement, Buyer agrees to purchase from Seller and Seller agrees to sell to Buyer all of Seller’s right, title and interest in and to the Assets.

Section 2.02Assets. Subject to Section 2.03, the term “Assets” shall mean, less and except the Excluded Assets, all of Seller’s right, title and interest in and to:

(a)(i) the oil and gas leases and forced pooling orders more particularly described in Exhibit A – Part 1 (Seller’s interests in such leases, including all overriding royalty

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interests, collectively, the “Leases”), (ii) the oil and gas leases more particularly described in Exhibit A – Part 1-A (Seller’s interests in such leases, including all overriding royalty interests, collectively the “Term Leases”), (iii) the overriding royalty interests more particularly described in Exhibit A – Part 1-B, and (iv) the interests in any units or pooled or communitized lands arising on account of the Leases and Term Leases having been unitized or pooled into such units or with such lands (Seller’s interests in such units, the “Unit Interests”);

(b)all oil and gas wells attributable to the Leases, Term Leases, or Unit Interests (Seller’s interests in such wells, collectively and including the wells set forth on Exhibit A—Part 2, the “Wells”, and the Leases, the Term Leases, the Unit Interests and the Wells being collectively referred to hereinafter as the “Properties”);

(c)all production facilities, structures, tubular goods, well equipment, lease equipment, production equipment, pipelines, inventory and all other personal property, fixtures and facilities to the extent appurtenant to or used in connection with the Properties (collectively, the “Facilities”);

(d)all permits, licenses, servitudes, easements, rights-of-way, surface fee interests and other surface use agreements to the extent used in connection with the ownership or operation of the Properties or the Facilities, including those described in Exhibit A-Part 3;

(e)the Hydrocarbons produced and saved from or attributable to the Properties from and after the Effective Time and all Hydrocarbons produced therefrom prior to the Effective Time that are in storage prior to sale and that are upstream of the sales metering point as of the Closing Date;

(f)all contracts and agreements insofar as such contracts and agreements relate to the Properties, including those listed in Exhibit A  – Part 4 that can be transferred without additional consideration to such Third Parties (or including such licensed data in the event Buyer agrees to pay such additional consideration) (collectively, the “Contracts”);

(g)all Imbalances relating to the Properties as of the Effective Time; and

(h)all records, files, contracts, orders, agreements, maps, data, schedules, reports and logs primarily relating to the Assets in Seller’s possession (collectively referred to as the “Files”).

Section 2.03Excluded and Reserved Assets. The Assets shall not include, and there is excepted, reserved and excluded from the purchase and sale contemplated hereby, the Excluded Assets. The “Excluded Assets” shall mean:

(a)any Leases, or portions thereof, or other Assets that are excluded due to Title Defects or Environmental Defects;

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(b)except to the extent Buyer has an indemnification obligation in favor of Seller under this Agreement, any trade credits, accounts receivable, proceeds or revenues of Seller or its Affiliates attributable to the Assets and accruing prior to the Effective Time;

(c)all rights to proceeds from Hydrocarbons produced from or attributable to the Properties with respect to any periods of time prior to the Effective Time that are not in storage prior to sale and that are upstream of the sales metering point as of the Closing Date, and all proceeds attributable thereto;

(d)all claims of Seller for refunds of, credits attributable to, loss carry forwards with respect to, or similar Tax assets relating to (i) Asset Taxes allocable to Seller pursuant to Section 14.01, (ii) Income Taxes, (iii) Taxes attributable to the Excluded Assets, and (iv) any other Taxes relating to the ownership or operation of the Assets that are attributable to any period (or portion thereof) prior to the Effective Time;

(e)except to the extent Buyer has an indemnification obligation in favor of Seller under this Agreement, all proceeds from the settlements of contract disputes with purchasers of Hydrocarbons from or attributable to the Properties, insofar as said proceeds are attributable to any periods of time prior to the Effective Time;

(f)all bonds, letters of credit and guarantees, if any, posted by Seller or its Affiliates with Governmental Authorities and relating to the Assets;

(g)except to the extent Buyer has an indemnification obligation in favor of Seller under this Agreement, all rights, titles, claims and interests of Seller or its Affiliates under any policy or agreement of insurance or indemnity;

(h)except to the extent Buyer has an indemnification obligation in favor of Seller under this Agreement, all rights and claims of Seller or its Affiliates relating to the Assets and attributable to periods of time prior to the Effective Time;

(i)all patents, patent applications, logos, service marks, copyrights, trade names or trademarks of or associated with Seller, its Affiliates or their businesses;

(j)all privileged attorney-client (i) communications and (ii) other documents (other than title opinions);

(k)all materials and information that cannot be disclosed to Buyer as a result of confidentiality obligations to Third Parties;

(l)except to the extent Buyer has an indemnification obligation in favor of Seller under this Agreement, all audit rights of Seller or its Affiliates arising under any of the Contracts with respect to any periods of time prior to Closing or to any of the Excluded Assets, except for any Imbalances;

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(m)all materials, information and analyses developed or prepared in connection with marketing the Assets, including presentations, valuations and bidder lists and all communications with marketing advisors;

(n)all amounts paid by any Person to Seller or its Affiliates as overhead for periods of time accruing prior to Closing under any joint operating agreements burdening the Assets;

(o)the rights, titles or interests described in Exhibit B and those portions of the oil, gas, and mineral leases shown on the map in Exhibit B (and the operating rights, working interests, net revenue interests, and other rights to Hydrocarbons therein) to the extent located within the boundary of such depicted units; and

(p)all master services agreements.

Section 2.04Revenues and Expenses. Except as expressly provided otherwise in this Agreement, Seller shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall remain responsible for all Operating Expenses (in each case) attributable to the Assets for the period of time prior to the Effective Time. Subject to the provisions hereof, from and after Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall be responsible for all Operating Expenses (in each case) attributable to the Assets for the period of time from and after the Effective Time. All Operating Expenses attributable to the Assets (in each case) that are: (a) incurred with respect to operations conducted or Hydrocarbons produced prior to the Effective Time shall be paid by or allocated to Seller and (b) incurred with respect to operations conducted or Hydrocarbons produced from and after the Effective Time shall be paid by or allocated to Buyer. Seller shall, upon receipt of any amounts owed to Buyer under this Section 2.04 that are not accounted for in the Final Accounting Statement, promptly deliver any such amounts to Buyer. Buyer shall, upon its receipt of any amounts owed to Seller under this Section 2.04 that are not accounted for in the Final Accounting Statement, promptly deliver any such amounts to Seller.

ARTICLE IIICONSIDERATION

Section 3.01Purchase Price. The consideration for the purchase, sale and assignment of the Assets by Seller to Buyer is Buyer’s payment to Seller of the sum of $46,202,217.15 (the “Purchase Price”), as adjusted pursuant to this Agreement (the “Adjusted Purchase Price”).

Section 3.02Deposit.

(q)Within 3 Business Days of the execution of this Agreement, Buyer shall deposit by wire transfer in same day funds with the Escrow Agent the Escrow Amount (such amount, including any interest earned thereon, the “Deposit”) pursuant to the terms of the Escrow Agreement. The fees and expenses of the Escrow Agent shall be borne one-half by Buyer and one-half by Seller.

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(r)If (i) Seller is ready, willing and able to assign the Assets and all conditions precedent to the obligations of Buyer set forth in Section 8.02 have been met and (ii) the transactions contemplated by this Agreement are not consummated on or before the Closing Date because of: (A) the failure of Buyer to perform in any material respects any of its obligations hereunder or (B) the failure of any of Buyer’s representations or warranties hereunder to be true and correct in any material respect, then Seller shall have the right to terminate this Agreement and Seller and Buyer shall promptly direct the Escrow Agent to deliver the Deposit to Seller, free of any claims by Buyer thereto, as liquidated damages as its sole remedy. The provision for payment of liquidated damages in this Section 3.02(b) has been included because, in the event of a termination of this Agreement described in this Section 3.02(b), the actual damages to be incurred by Seller can reasonably be expected to approximate the amount of liquidated damages called for herein and because the actual amount of such damages would be difficult if not impossible to measure accurately.

(s)If this Agreement is terminated by the mutual written agreement of Buyer and Seller or if the Closing does not occur on or before the Closing Date for any reason other than as set forth in Section 3.02(b), then Buyer shall be entitled to the immediate return of the Deposit, free of any claims by Seller with respect thereto and Buyer and Seller shall promptly so instruct the Escrow Agent. Buyer and Seller shall thereupon have the rights and obligations set forth in Section 11.02.

Section 3.03Allocated Values. Buyer and Seller agree that the unadjusted Purchase Price is allocated among the Assets in the amounts set forth in Exhibit A—Part 1, Exhibit A—Part 1-A, Exhibit A—Part 1-B, and Exhibit A—Part 2. The “Allocated Value” for any Asset equals the portion of the unadjusted Purchase Price allocated to such Asset on Exhibit A—Part 1, Exhibit A—Part 1-A, Exhibit A—Part 1-B, or Exhibit A—Part 2 and such Allocated Value shall be used in calculating adjustments to the Purchase Price as provided herein.

Section 3.04Purchase Price Allocation. Buyer and Seller shall use commercially reasonable efforts to agree to an allocation of the Purchase Price and any other items properly treated as consideration for U.S. federal Income Tax purposes among the Assets in accordance with Section 1060 of the Code and, to the extent allowed by applicable Laws, in a manner consistent with the Allocated Values within 30 days after the Closing Date (the “Allocation”). If Seller and Buyer reach an agreement with respect to the Allocation, (i) the Parties shall use commercially reasonable efforts to update the Allocation in a manner consistent with Section 1060 of the Code following any adjustment to the Purchase Price pursuant to this Agreement, and (ii) Seller and Buyer shall, and shall cause their Affiliates to, report consistently with the Allocation in all Tax Returns (including Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which Form will be timely filed separately by Seller and Buyer with the Internal Revenue Service pursuant to the requirements of Section 1060(b) of the Code), and neither Seller nor Buyer shall take any position in any Tax Return that is inconsistent with the Allocation unless otherwise required by applicable Law; provided, however, that neither Party shall be unreasonably impeded in its ability and discretion to negotiate, compromise and/or settle any Tax audit, claim or similar proceedings in connection with such allocation.

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ARTICLE IVTITLE MATTERS

Section 4.01General Disclaimer of Title Warranties and Representations. Except as set forth in the Assignments and without limiting Buyer's remedies for Title Defects set forth in this Article IV, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Buyer hereby acknowledges and agrees that Buyer's sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets (a) before Closing, shall be as set forth in Section 4.07 and (b) after Closing, shall be pursuant to the Special Warranty of title set forth in the Assignments.

Section 4.02Special Warranty. If the Closing occurs, then the Assignments shall contain a special warranty of title effective as of the Closing Date whereby Seller shall warrant Defensible Title to the Properties to Buyer as of the Closing Date, against every Person whomsoever lawfully claiming the same or any part thereof by, through or under Seller, or any Affiliates of Seller, but not otherwise, subject, however, to the Permitted Encumbrances (the “Special Warranty”). Seller warrants to Buyer that it holds title to all of its Assets (excluding the Properties) as of the Closing Date, free and clear of any claim, mortgage, lien, right or encumbrance by, through or under Seller, or any Affiliates of Seller, but not otherwise, except for Permitted Encumbrances.

Section 4.03Recovery on Special Warranty. From and after the expiration of the Title Examination Period, Buyer shall be entitled to furnish Seller written claim notices meeting the requirements of Section 4.06 setting forth any and all matters which Buyer intends to assert as a breach of Seller’s Special Warranty (collectively the “Special Warranty Notices” and individually a “Special Warranty Notice”). Seller shall have a reasonable opportunity, but not the obligation, to cure any breach of the Special Warranty asserted by Buyer pursuant to this Section 4.03. Buyer agrees to reasonably cooperate with any attempt by Seller to cure any such breach. For purposes of the Special Warranty, the value of the Term Leases, Wells and/or Leases set forth on Exhibit A—Part 1, Exhibit A—Part 1-A, or Exhibit A—Part 2, as applicable, shall be deemed to be the Allocated Value thereof, as may be adjusted herein. Buyer’s recovery on the Special Warranty shall be limited to the Allocated Value of such Term Lease, Well or Lease, without duplication of any recovery by Buyer pursuant to Section 4.07. Seller shall be entitled to offset amounts attributable to any breach of the Special Warranty with respect to any Asset by the amount of Title Benefits with respect to such Asset; provided that Seller has given Buyer notice of such Title Benefit prior to the date that is 30 days following the date Seller receives the applicable Special Warranty Notice.

Section 4.04Title Examination Period. Commencing on the date of the execution of this Agreement and ending 45 days following signingat 5:00 p.m. Houston time (the “Title Examination Period”), Seller shall, subject to Section 7.01, (a) permit Buyer and/or its representatives to examine, in a reasonable manner, during regular business hours and in Seller’s and its Affiliates’ offices, all abstracts of title, title opinions, title files, ownership maps, Property files, assignments, division orders, operating records and agreements (including the Contracts) pertaining to the Assets insofar as same may now be in existence and in the possession of Seller or its Affiliates and (b) subject to Third Party operator approval and the provisions of Section 7.01 hereof, permit Buyer and/or its representatives, during regular business hours and at Buyer’s sole risk, cost and expense, to conduct

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reasonable inspections of the Assets (other than environmental inspections which are covered by Section 5.01 hereof); provided, however Seller will use commercially reasonable efforts to obtain a waiver of any such restrictions in favor of Buyer.

Section 4.05Title Defects. An Asset shall be deemed to have a “Title Defect” if Seller is found to have less than Defensible Title thereto, without duplication, and it is reasonably estimated to individually (a) require an expenditure in excess of $25,000 to remedy or (b) reduce the value of such Asset by an amount in excess of $25,000. For purposes of this Agreement, the term “Defensible Title” shall mean such title of Seller that, as of the Effective Time, and subject to and except for the Permitted Encumbrances:

(i)with respect to any Well (but limited to any currently producing interval or specified formation or reservoir set forth in Exhibit A—Part 2 to the extent within the Target Formations):

(A)    entitles Seller to receive not less than the amount set forth in Exhibit A—Part 2 as the Net Revenue Interest for such Well of all Hydrocarbons produced, saved and marketed from such Well, without reduction of such interest throughout the duration of the life of such Well, except (1) as set forth in Exhibit A—Part 2, (2) decreases in connection with those operations to the extent permitted under this Agreement in which Seller may from and after the date of this Agreement be a non-consenting co-owner, (3) decreases resulting from the establishment or amendment of pools or units from and after the date of this Agreement, and (4) decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries to the extent accounted for under Section 9.02(b);

(B)    obligates Seller to bear the percentage of the costs and expenses relating to the maintenance, development and operation of such Well not greater than the Working Interest for such Well (shown in Exhibit A—Part 2), without increase throughout the duration of the life of such Well, except (1) as set forth in Exhibit A—Part 2, (2) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements, and (3) increases to the extent that they are accompanied by a proportionate increase in Seller’s corresponding Net Revenue Interest (set forth in Exhibit A—Part 2);

(ii)with respect to any Lease or Term Lease (but limited to any specified formation or reservoir set forth in Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable, to the extent within the Target Formations):

(A) entitles Seller to not less than the Net Acres set forth in Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable, except for (1) as set forth in Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable, (2) decreases in connection with those operations in which Seller may from and after the date

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of this Agreement be a non-consenting co-owner, and (3) decreases resulting from the establishment or amendment of pools or units from and after the date of this Agreement;

(B)such Lease and Term Lease is valid and in full force and effect;

(iii)with respect to any Term Lease (but limited to any specified formation or depth restrictions set forth in Exhibit A—Part 1-A to the extent within the Target Formations):

(A)entitles Seller to receive not less than the amount set forth in Exhibit A—Part 1-A as the Net Revenue Interest for such Term Lease of all Hydrocarbons produced, saved and marketed from such Term Lease, without reduction of such interest throughout the duration of the life of such Term Lease, except (1) as set forth in Exhibit A—Part 1-A, (2) decreases in connection with those operations to the extent permitted under this Agreement in which Seller may from and after the date of this Agreement be a non-consenting co-owner, and (3) decreases resulting from the establishment or amendment of pools or units from and after the date of this Agreement;

(B)obligates Seller to bear the percentage of the costs and expenses relating to the maintenance, development and operation of such Term Lease not greater than the Working Interest for such Term Lease (shown in Exhibit A—Part 1-A), without increase throughout the duration of the life of such Term Lease, except (1) as set forth in Exhibit A—Part 1-A, (2) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements, and (3) increases to the extent that they are accompanied by a proportionate increase in Seller’s corresponding Net Revenue Interest (set forth in Exhibit A—Part 1-A); and

(iv)is free and clear of all material Liens and encumbrances.

Notwithstanding the foregoing, none of the following shall constitute a Title Defect: (1) the loss of or reduction of interest in any Lease, Term Lease, Well or other Property following the date hereof due to: (x) any election or decision made by Seller in accordance with applicable joint operating agreements as permitted under this Agreement or (y) the expiration of the primary or secondary term of any Lease or Term Lease that does not materially differ from the date of expiration set forth on Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable; (2) defects based solely on (A) lack of information in Seller’s or its Affiliates’ files, or (B) references to a document(s) if such document(s) is not in Seller’s or its Affiliates’ files; (3) defects in the chain of title prior to April 1, 1995 which have not resulted in any adverse claims since such date; (4) defects arising out of lack of corporate or other entity authorization unless Buyer provides affirmative evidence that the action was not authorized and results in another party’s actual and superior claim of title to the relevant Property; (5)

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defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Buyer provides affirmative evidence that such failure or omission results in another party’s actual and superior claim of title to the relevant Property; (6) defects arising out of lack of survey, unless a survey is expressly required by applicable Laws; (7) defects or irregularities resulting from or related to probate proceedings or the lack thereof, which defects or irregularities have been outstanding for seven and a half years or more;(8) defects based on failure to record Leases issued by any Governmental Authority, or any assignments of record title or operating rights in such Leases, in the real property, conveyance or other records of the county in which such Property is located; or (9) defects arising from a mortgage encumbering the oil, gas or mineral estate of any lessor unless (a) such defects relate to a Well currently operated by Seller and (b) a complaint of foreclosure has been filed or any similar action taken by the mortgagee thereunder and in such case such mortgage is not subordinated to the Lease applicable to such Property.

Section 4.06Notice of Title Defects. If Buyer discovers any Title Defect, Buyer shall promptly notify Seller thereof prior to the expiration of the Title Examination Period. To be effective, such notice (a “Title Defect Notice”) shall be in writing and shall include (a) a description of each alleged Title Defect, (b) the Asset or portion thereof affected thereby (each “Title Defect Property”), (c) the value of such Title Defect Property (which shall be the Allocated Value thereof), (d) documentation sufficient to reasonably support such asserted Title Defect, and (e) the amount which Buyer reasonably believes to be the Title Defect Amount resulting from such alleged Title Defect and the computations and information upon which Buyer’s belief is based. To give Seller an opportunity to commence reviewing and curing any Title Defects, Buyer agrees to use reasonable efforts to give Seller, each Monday following the execution of this Agreement but prior to the expiration of the Title Examination Period, written notice of all Title Defects (as well as any claims that would be claims under the Special Warranty set forth in the Assignments) discovered by Buyer during the previous week, which notice may be preliminary in nature and supplemented from time to time prior to expiration of the Title Examination Period; provided, however, that Buyer’s failure to notify Seller as set forth above shall not constitute a waiver of any such alleged Title Defect to the extent that notice is received prior to the expiration of the Title Examination Period. Subject to Buyer’s rights with respect to any breach by Seller of Section 7.03, any matters that may otherwise constitute Title Defects but that are not specifically disclosed to Seller pursuant to a Title Defect Notice delivered to Seller prior to the expiration of the Title Examination Period shall be deemed to have been waived by Buyer, on behalf of itself and its successors and assigns, for all purposes. Seller shall have the right, but not the obligation, to attempt to cure any asserted Title Defects of which it has been advised by Buyer at any time prior to sixty days after the Closing Date (the “Cure Period”). During the period of time from Closing to the expiration of the Cure Period, Buyer agrees to afford Seller and its officers, employees and other authorized representatives reasonable access, during normal business hours, to the Assets and all Files in Buyer’s or any of its Affiliates’ possession in order to facilitate Seller’s attempt to cure any such Title Defects. No reduction shall be made to the Purchase Price with respect to any Title Defect properly asserted in good faith prior to the expiration of the Title Examination Period (“Asserted Title Defects”) for which Seller has provided notice to Buyer prior to or on the Closing Date that Seller intends to attempt to cure the Title Defect during the Cure Period or for which Seller has provided notice to Buyer prior to or on the Closing

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Date that Seller disputes the existence, in whole or in part, which notice shall include a description of the matters in dispute. An election by Seller to attempt to cure a Title Defect shall be without prejudice to its rights under Section 4.11 and shall not constitute an admission against interest or a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Title Defect. Subject to Section 4.09, the Title Defect Amounts resulting from the Title Defects asserted by Buyer and not cured by Seller prior to Closing shall be retained by the Escrow Agent at Closing from the Deposit, unless the Parties agree otherwise; provided, however, to the extent such Title Defect Amounts (together with any other amounts held by the Escrow Agent pursuant to Section 5.03) exceed the Deposit, at the Closing, Buyer shall deposit with the Escrow Agent a portion of the Purchase Price equal to such excess (without duplication); provided further, however (i) if, Seller elects to cure an Asserted Title Defect, the Title Defect Amount resulting from such Asserted Title Defect shall be released to Seller upon cure if such Asserted Title Defect is cured by the expiration of the Cure Period, and if not cured by then, such Title Defect Amount shall be released to Buyer at such time, or if the Parties have not agreed on (x) the proper and adequate cure for any such Title Defect, (y) the Title Defect Amount and/or (z) whether the Asserted Title Defect constitutes a Title Defect (each a “Disputed Title Matter”), then such Title Defect Amount shall be treated as provided in the following sub-part (ii), and (ii) if an Asserted Title Defect is a Disputed Title Matter, such Asserted Title Defect shall be finally and exclusively resolved in accordance with the provisions of Section 4.11 and release of the Title Defect Amount by the Escrow Agent for such Asserted Title Defect shall be resolved in accordance therewith. If, prior to the expiration of the Cure Period, a Disputed Title Matter exists, then such dispute(s) shall be finally and exclusively resolved in accordance with the provisions of Section 4.11.

Section 4.07Remedies for Title Defects. Subject to Seller’s continuing right to dispute the existence of a Title Defect and/or the Title Defect Amount therefor pursuant to Section 4.11, in the event that any Title Defect timely asserted by Buyer in accordance with Section 4.06 is not waived in writing by Buyer or cured during the Cure Period, Seller may, at its sole election for each Title Defect:

(a)subject to Section 4.09, reduce the Purchase Price by an amount (the “Title Defect Amount”) agreed to by Seller and Buyer, or if Seller and Buyer are unable to agree on the amount of such Title Defect, an amount determined by the Consultant under Section 4.11, to the extent so agreed or determined prior to Closing, in which event the Parties shall (subject to the other terms of this Agreement) proceed to Closing, each Title Defect Property shall be assigned to Buyer subject to such Title Defect and Buyer shall pay to Seller the Purchase Price as so adjusted, provided if at the Closing Date, Seller has not cured the Title Defect, but elects to cure such Title Defect during the Cure Period, the Parties shall instruct Escrow Agent to disburse the Escrow Amount to Seller in accordance with the provisions of Section 4.06; or

(b)retain the Title Defect Property and reduce the Purchase Price by an amount equal to the Allocated Value (or portion thereof allocable thereto) of the Title Defect Property, in which event such Title Defect Property shall become an Excluded Asset, the Parties shall (subject to the other terms of this Agreement) proceed to Closing, and Buyer shall pay to Seller the Purchase Price as so adjusted.

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Section 4.08Title Benefits.

(a)Should either Party or such Party’s representatives discover any Title Benefit on or before the end of the Title Examination Period, Seller shall have the right and Buyer shall have the obligation to notify the other Party thereof on or before the end of the Title Examination Period, which notice shall include (i) a description of the Title Benefit(s), (ii) the Asset affected (each, a “Title Benefit Property”), (iii) the alleged Allocated Value of such Title Benefit Property, (iv) documentation sufficient to reasonably support the asserted Title Benefit, and (v) the amount by which the asserting Party reasonably believes the Allocated Value of such Title Benefit Property is increased by the alleged Title Benefit, which must be greater than $25,000 to be asserted by such Party, and the computations and information upon which such Party’s belief is based.

(b)With respect to each Title Benefit Property reported under Section 4.08(a), (i) if the Net Acres of such Title Benefit Property is greater than the Net Acres set forth in Exhibit A—Part 1, then the Purchase Price shall be increased by an amount equal to the product of the positive difference between such Net Acre amounts for the applicable Title Benefit Property multiplied by the Net Acre Allocation; (ii) if the Net Revenue Interest of such Title Benefit Property is greater than the Net Revenue Interest stated therefor on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable, then the Purchase Price shall be increased by an amount equal to the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the actual Net Revenue Interest increase and the denominator of which is the Net Revenue Interest stated on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable and (iii) if the Working Interest of such Title Benefit Property is less than the Working Interest stated therefor on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable (without a proportionate reduction in the corresponding Net Revenue Interest stated on Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable), then the Purchase Price shall be increased by an amount mutually agreed by Seller and Buyer. Provided that the Purchase Price shall not be increased by any Title Benefit Amount, unless and until the aggregate amount of all qualifying Title Benefit Amounts exceed 1% of the Purchase Price (the “Benefit Deductible”). The amount by which the Purchase Price is increased pursuant to the preceding sentences of this Section 4.08(b) shall be referred to herein as the “Title Benefit Amount.”

Section 4.09Limitations. Notwithstanding anything to the contrary, (a) in no event shall there be any adjustments to the Purchase Price or other remedies under this Agreement for any Title Defect if the sum of all Title Defect Amounts and Environmental Defect Amounts does not exceed 2%of the Purchase Price (the “Defect Deductible”), (b) in the event that the sum of all Title Defect Amounts and Environmental Defect Amounts exceeds the Defect Deductible, then any adjustments to the Purchase Price or other remedies provided by Seller pursuant to Section 4.07 shall be applicable only to the portion thereof that exceeds the Defect Deductible (such Defect Deductible being a true deductible), and (c) except for Buyer’s rights under the Special Warranty in the Assignments, Section 4.07 (as limited by this Section 4.09), and Section 4.11 shall, subject to Buyer’s rights with respect to any breach by Seller of Section 7.03, to the fullest extent permitted by applicable Law, be the

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exclusive right and remedy of Buyer with respect to any Title Defect or any other title matter related to the Assets and Buyer waives any and all other rights, at Law or in equity, with respect thereto.

Section 4.10Title Defect Amount. The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of each Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined by the Parties in accordance with the following terms and conditions:

(a)if Buyer and Seller agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(b)if the Title Defect is an encumbrance that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(c)if the Title Defect represents a discrepancy between (i) the actual Net Acres for any Lease and (ii) the Net Acres stated therefor in Exhibit A—Part 1, then the Title Defect Amount shall be the product of the positive difference between such Net Acre amounts for such Lease multiplied by the Net Acre Allocation;

(d)if the Title Defect represents a discrepancy between (i) the Net Revenue Interest for any Term Lease or Well and (ii) the Net Revenue Interest stated therefor in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable, then the Title Defect Amount shall be the product of the Allocated Value of such affected Term Lease or Well multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest stated in Exhibit A—Part 1-A or Exhibit A—Part 2, as applicable;

(e)if the Title Defect represents an obligation upon, encumbrance upon or other defect in title to the Title Defect Property of a type not described above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation; provided, however, that if such Title Defect is reasonably capable of being cured, the Title Defect Amount shall not be greater than the cost and expense of curing such Title Defect;

(f)the Title Defect Amount with respect to each Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(g)notwithstanding anything to the contrary in this Section 4.10, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon a Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

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Section 4.11Resolution of Title and Environmental Matters.

(a)If, after good faith efforts, Seller and Buyer are not in agreement as to (i) whether a Title Defect or an Environmental Defect asserted in a Title Defect Notice or Environmental Defect Notice exists, (ii) the Title Defect Amount of a particular Title Defect, or the Environmental Defect Amount of a particular Environmental Defect, (iii) whether a Title Benefit exists or the Title Benefit Amount, or (iv) whether a Title Defect or Environmental Defect has been cured prior to the expiration of the Cure Period, Seller and Buyer will submit the dispute to arbitration as provided in this Section following written notice from one Party to the other Party that such Party is initiating dispute resolution in accordance with this Section, such notice to describe in reasonable detail the nature and specifics of the dispute. The matter to be arbitrated shall be submitted to an oil and gas title attorney with at least 10 years’ experience in the county where the affected Property is located (or the nearest county where a reasonably acceptable title attorney may be found), selected by Seller and Buyer, in the case of a Title Defect or Title Benefit, or to an environmental expert in the county where the affected Property is located (or the nearest county where a reasonably acceptable environmental expert may be found), selected by Seller and Buyer, in the case of an Environmental Defect (each such title attorney or environmental expert hereinafter, a “Consultant”). In the event Seller and Buyer are unable to agree on any Consultant, Seller on the one hand and Buyer on the other hand will each appoint one Consultant and the two Consultants so appointed will appoint a third Consultant and the three Consultants so appointed will resolve such matter by majority decision. The cost of each Consultant shall be borne one-half by Buyer and one-half by Seller. Seller and Buyer shall each present to the Consultant(s), with a simultaneous copy to the other Party, a single written statement of its position on the defect or benefit in question, together with a copy of this Agreement and any supporting material that such Party desires to furnish, not later than the 5th Business Day after appointment of the Consultant(s). In making their determination, the Consultant(s) shall be bound by the terms of this Agreement and, without any additional or supplemental submittals by either Party, may consider available legal and industry matters as in their opinion are necessary or appropriate to make a proper determination. By the 20th day following the submission of the matter to the Consultant(s), applying the principles set forth in this Section 4.11, the Consultant(s) shall make a determination of the matter submitted. The decision of the Consultant(s) shall be in writing and conclusive and binding on Seller and Buyer and shall be enforceable against the Parties in any court of competent jurisdiction. The Consultant(s)' decision shall also state, when applicable, the positive or negative adjustments which the Parties should make to the Purchase Price based upon the decision rendered. The Consultant(s) shall act as experts for the limited purpose of determining the specific title or environmental dispute presented to them, shall not act as arbitrators, may not hear or decide any matters except the specific title or environmental disputes presented to them and may not award damages, interest, costs or penalties to either Party.

(b)If the Consultant(s) have made no determination with respect to the matters subject to arbitration prior to Closing, then all adjustments to the Purchase Price required

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as a result of the Consultant's determination shall be accounted for in the Final Accounting Statement.

Section 4.12Consents to Assign. With respect to each Consent set forth in Schedule 6.01(c), promptly, but in no event later than five (5) days after the date of this Agreement, Seller shall send to the holder of each such Consent a notice (in form reasonably satisfactory to Buyer) in material compliance with the contractual provisions applicable to such Consent seeking such holder’s consent as required.

(a)If (i) Seller fails to obtain a Consent set forth in Schedule 6.01(c) prior to Closing and the failure to obtain such Consent would cause (A) the assignment of the Assets affected thereby to Buyer to be void or (B) the termination of a Lease or Contract under the express terms thereof or (ii) a Consent requested by Seller is denied in writing, then, in each case, the Asset (or portion thereof) affected by such un-obtained Consent shall be excluded from the Assets to be assigned to Buyer at Closing, and the Purchase Price shall be reduced by the Allocated Value of such Asset (or portion thereof) so excluded. In the event that a Consent (with respect to an Asset excluded pursuant to this Section 4.12(a)) that was not obtained prior to Closing is obtained within ninety (90) days following Closing, then, within ten (10) days after such Consent is obtained (x) Buyer shall purchase the Asset (or portion thereof) that was so excluded as a result of such previously un-obtained Consent and pay to Seller the amount by which the Purchase Price was reduced at Closing with respect to the Asset (or portion thereof) so excluded and (y) Seller shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

(b)If Seller fails to obtain a Consent set forth in Schedule 6.01(c) prior to Closing (i) and the failure to obtain such Consent would not cause (A) the assignment of the Asset (or portion thereof) affected thereby to Buyer to be void or (B) the termination of a Lease or Contract under the express terms thereof and (ii) such Consent requested by Seller is not denied in writing by the holder thereof, then the Asset (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by Seller to Buyer at Closing as part of the Assets and Buyer shall have no claim against, and Seller shall have no Liability for, the failure to obtain such Consent.

(c)Prior to Closing and during the ninety (90) day period following Closing, Seller and Buyer shall use their commercially reasonable efforts to obtain all Consents listed on Schedule 6.01(c); provided, however, that neither Party shall be required to incur any Liability or pay any money in order to obtain any such Consent. Subject to the foregoing, Buyer agrees to provide Seller with any information or documentation that may be reasonably requested by Seller and/or the Third Party holder(s) of such Consents in order to facilitate the process of obtaining such Consents.

ARTICLE VENVIRONMENTAL

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Section 5.01Environmental Examination Period. Commencing on the date of the execution of this Agreement and ending 45 days following signingat 5:00 p.m. Houston time (the “Environmental Examination Period”), Seller shall, subject to Third Party operator and surface owner approval (which, upon Buyer’s request, Seller shall use commercially reasonable efforts to obtain, provided that Seller shall not be required to provide consideration or undertake obligations to or for the benefit of the holders of such approval rights) and the provisions of Section 7.01 hereof, permit Buyer and/or its representatives, in a reasonable manner, during regular business hours and at Buyer’s sole risk, cost and expense, to conduct reasonable environmental inspections of the Assets, provided that such inspections shall not include the sampling or testing of any environmental media (air, soil, surface or ground water, or sediments) or the operation of any equipment on the Assets or the real property on which the Assets are located.

Section 5.02Environmental Defect. An Asset shall be deemed to have an “Environmental Defect” if Buyer discovers that such Asset is subject to an individual condition (i) constituting a violation of Environmental Laws or (ii) consisting of soil and/or groundwater contamination that is required to be remediated at the present time pursuant to applicable Environmental Laws, in the case of either (i) or (ii) with respect to which the net present value (using a 10% discount rate) of the Lowest Cost Response therefor is reasonably estimated to require expenditures in excess of $50,000.

Section 5.03Notice of Environmental Defects. If Buyer discovers any Environmental Defect, Buyer shall promptly notify Seller thereof prior to the expiration of the Environmental Examination Period. To be effective, such notice (an “Environmental Defect Notice”) shall be in writing and shall include (a) a description of each alleged Environmental Defect, (b) the Asset or portion thereof affected thereby (each “Environmental Defect Property”), (c) the value of such Environmental Defect Property (which shall be the Allocated Value thereof), (d) documentation sufficient to reasonably support such asserted Environmental Defect, and (e) the amount which Buyer reasonably believes to be the net present value (using a 10% discount rate) of the Lowest Cost Response to cure such alleged Environmental Defect and the computations and information upon which Buyer’s belief is based. Subject to the Retained Liabilities and Buyer’s remedies under Article XII, any matters that may otherwise constitute Environmental Defects but that are not specifically disclosed to Seller pursuant to an Environmental Defect Notice prior to the expiration of the Environmental Examination Period shall be deemed to have been waived by Buyer, on behalf of itself and its successors and assigns, for all purposes (including, without limitation, Article XII of this Agreement). Seller shall have the right, but not the obligation, to attempt to cure any asserted Environmental Defect on or before the expiration of the Cure Period. To give Seller an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to use reasonable efforts to give Seller, on or before the end of each calendar week prior to the expiration of the Environmental Examination Period, written notice of all alleged Environmental Defects discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the expiration of the Environmental Examination Period; provided, however, that Buyer’s failure to notify Seller as set forth above shall not constitute a waiver of any such alleged Environmental Defect to the extent that notice is received prior to the expiration of the Environmental Examination Period. No reduction shall be made to the Purchase Price with respect to any Environmental Defect properly asserted in good faith prior to the expiration of the Environmental Examination period

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(“Asserted Environmental Defect”) for which Seller has provided notice to Buyer prior to or on the Closing Date that Seller intends to attempt to cure the asserted Environmental Defect during the Cure Period or for which Seller has provided notice to Buyer prior to or on the Closing Date that Seller disputes the existence, in whole or in part, which notice shall include a description of the matters in dispute. Each Environmental Defect Property affected by an Asserted Environmental Defect shall not be conveyed to Buyer at Closing pending the resolution of such Environmental Defect pursuant to the terms of this Section 5.03 and Section 5.04.Subject to Section 5.05, the Allocated Value of the Assets for which Buyer has asserted an Asserted Environmental Defect shall be retained by the Escrow Agent at Closing from the Deposit, unless the Parties agree otherwise with respect to any Asserted Environmental Defect prior to Closing; provided however, to the extent such Allocated Value (together with any other amounts held by the Escrow Agent pursuant to Section 4.06) exceeds the Deposit, at the Closing, Buyer shall deposit with the Escrow Agent a portion of the Purchase Price equal to such excess (without duplication); provided further, however, (i) if Seller elects to cure an Asserted Environmental Defect, (a) if such Asserted Environmental Defect is cured by the end of the Cure Period, subject to Buyer’s right to dispute the completion of the cure in (ii) below, the Allocated Value of the applicable Environmental Defect Property shall be released by the Escrow Agent to Seller and the Environmental Defect Property shall be conveyed to Buyer, but (b) if cure has not been achieved by the end of the Cure Period, the Allocated Value for the applicable Environmental Defect Property shall be released by the Escrow Agent to Buyer and the applicable Environmental Defect Property shall be retained by Seller, or (ii) if an Asserted Environmental Defect is one for which Seller properly disputes the existence or if Buyer disputes that the Seller has cured an Asserted Environmental Defect, in whole or in part, such Asserted Environmental Defect (or the completion of the cure) shall be finally and exclusively resolved in accordance with the provisions of Section 4.11 and release of the Allocated Value by the Escrow Agent for such Asserted Environmental Defects shall be resolved in accordance therewith.

Section 5.04Remedies for Environmental Defects. Subject to Seller’s right to dispute the existence of an Environmental Defect and/or the Lowest Cost Response therefor and Buyer’s right to dispute the completion of a cure of an Asserted Environmental Defect pursuant to Section 4.11, in the event that any Environmental Defect timely asserted by Buyer in accordance with Section 5.03 is not waived in writing by Buyer or cured prior to the Closing Date, the remedy in clause (a) below shall apply unless either Party elects the remedy in clause (b) below if the Environmental Defect Amount with respect to any Environmental Defect is in excess of the Allocated Value of the Environmental Defect Property:

(b)subject to Section 5.05, reduce the Purchase Price by an amount determined in good faith by the Parties to be the Lowest Cost Response to cure such Environmental Defect (the “Environmental Defect Amount”), in which event each Environmental Defect Property shall be assigned to Buyer subject to such Environmental Defect; or

(c)Seller shall retain the Environmental Defect Property and reduce the Purchase Price by an amount equal to the Allocated Value (or portion thereof allocable thereto) of each Environmental Defect Property, in which event such Environmental Defect Property shall become an Excluded Asset.

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For the avoidance of doubt, if Seller has provided notice to Buyer prior to or on the Closing Date that Seller intends to attempt to cure an asserted Environmental Defect during the Cure Period in accordance with Section 5.03, the applicable procedures set forth in Section 5.03 shall apply.

Section 5.05Limitations. Notwithstanding anything to the contrary, (a) in no event shall there be any adjustments to the Purchase Price or other remedies under this Agreement for any Environmental Defect if the sum of all Environmental Defect Amounts and Title Defect Amounts does not exceed the Defect Deductible, (b) in the event that the sum of all Title Defect Amounts and Environmental Defect Amounts exceeds the Defect Deductible, then any adjustments to the Purchase Price or other remedies provided by Seller pursuant to Section 5.04 shall be applicable only to the portion thereof that exceeds the Defect Deductible (such Defect Deductible being a true deductible), and (c) other than for the Retained Liabilities and the remedies provided to Buyer in Article XII, Section 5.04 (as limited by this Section 5.05) and Section 4.11 shall, to the fullest extent permitted by applicable Law, be the exclusive right and remedy of Buyer with respect to any Environmental Defect or any matter that could have constituted an Environmental Defect, any obligations imposed under Environmental Laws, or any other environmental matters with respect to the Assets or environmental matters generally, and Buyer waives any and all other rights, at Law or in equity, with respect thereto.

ARTICLE VIREPRESENTATIONS AND WARRANTIES

Section 6.01Representations and Warranties of Seller. Subject to the matters specifically listed or disclosed in the Schedules (as added, supplemented or amended pursuant to Section 7.09), Seller represents and warrants to Buyer as follows:

(a)Organization. Seller is duly formed, validly existing and (to the extent applicable) in good standing under the Laws of the jurisdiction of its formation.

(b)Qualification. Seller is duly qualified to do business and is in good standing in Oklahoma and each other jurisdiction in which the nature of its business as now conducted makes such qualification necessary, except where the failure to be so qualified or in good standing would not have a Material Adverse Effect.

(c)Authorization / Consents. The execution and delivery by Seller of this Agreement and the performance of its obligations hereunder have been duly and validly authorized by all requisite action by Seller’s governing body and under its organizational documents. Other than (i) as set forth on Schedule 6.01(c), and (ii) those consents of Governmental Authorities customarily obtained post-Closing, Seller is not required to (A) give any notice to, make any filing with or obtain any authorization, consent or approval from any Governmental Authority or (B) obtain any consent from any other Third Party (in each case) in order for Seller to consummate the transactions contemplated by this Agreement (each, a “Consent”).

(d)Enforceability. This Agreement has been duly executed and delivered by Seller, and constitutes the valid and legally binding obligation of Seller, enforceable in

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accordance with its terms and conditions except insofar as the enforceability thereof may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar Laws affecting the enforcement of creditors’ rights generally and by general principles of equity, regardless of whether such principles are considered in a proceeding at Law or in equity.

(e)Noncontravention. Except as described on Schedule 6.01(e), and except for Customary Post-Closing Consents, neither the execution and the delivery of this Agreement, nor the consummation of the transactions contemplated hereby by Seller will violate or breach the terms of, cause a default under, result in thecreation or imposition of any Lien or encumbrance on any of the Properties, result in acceleration of, create in any party the right to accelerate, terminate, modify or cancel this Agreement or require any notice under: (A) any applicable Law, (B) the organizational documents of Seller, or (C) to Seller’s Knowledge, any Material Contract.

(f)Litigation. Except for the litigation described on Schedule 6.01(f), as of the date of this Agreement, there are no suits, actions or litigation before or by any Governmental Authority that are pending or, to Seller’s Knowledge, threatened against (i) Seller that are attributable to Seller’s ownership of the Assets or (ii) the Assets.

(g)Brokers’ Fees. Except as described on Schedule 6.01(g), Seller has no Liability or obligation to pay any fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement for which Buyer will be liable or obligated.

(h)Taxes. Except as described on Schedule 6.01(h),

(i)all Asset Taxes that have become due and payable prior to the Effective Time have been duly paid, and all Tax Returns with respect to Asset Taxes required to be filed prior to the Effective Time have been timely filed;

(ii)no audit, litigation or other proceeding with respect to Asset Taxes has been commenced or is presently pending;

(iii)there are no Liens (other than Permitted Encumbrances) on any of the Assets attributable to Taxes; and

(iv)none of the Assets is subject to any tax partnership agreement or is otherwise treated, or required to be treated, as held in an arrangement requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code.

Notwithstanding any other provision in this Agreement, the representations and warranties in this Section 6.01(h) are the only representations and warranties in this Agreement with respect to Tax matters.

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(i)Royalty Payments. Except as described on Schedule 6.01(i), all shut-in royalties, overriding royalties and other royalties or similar burdens on production with respect to the Leases that have become due and payable as of the Effective Time (“Royalties”) have been duly paid (other than royalties held in escrow or suspense accounts) in all material respects.

(j)Hydrocarbon Sales. Except as described on Schedule 6.01(j), Seller is not obligated by virtue of a production payment or any other arrangement, other than gas balancing arrangements, to deliver Hydrocarbons produced from the Assets at some future time without then or thereafter receiving payment for the production commensurate with Seller’s ownership in and to the Assets.

(k)Environmental Matters.

(i)Except as described on Schedule 6.01(k),as of the date of this Agreement, (i) Seller has not received any written notice of violation of any Environmental Laws relating to the Assets where such violation has not been previously cured or otherwise remedied to the satisfaction of the relevant Governmental Authority; (ii) no suits, actions or litigation is pending or to Seller’s Knowledge, threatened under Environmental Law with respect to the Assets or Seller’s ownership or operation of the Assets except as would not have a Material Adverse Effect; (iii) to Seller’s Knowledge, there has been no release or disposal of any contamination on the Assets that is reasonably likely to give rise to liability under Environmental Law except as would not have a Material Adverse Effect; (iv) no lien arising under Environmental Law are on any of the Assets except as would not have a Material Adverse Effect; or (v) the Assets and the operation thereof are not subject to any order, consent agreement or similar agreement with any Governmental Authority with respect to Environmental Law except as would not have a Material Adverse Effect.

(ii)Seller has provided Buyer with a copy of that certain Internal Phase I Assessment of the Wells conducted by Alicia Cook, Gastar’s Environmental Health and Safety Coordinator during the period of April 6-9^th, 2015; provided that for the avoidance of doubt, Seller makes no representations regarding the accuracy or completeness of such assessment.

(iii)This Section 6.01(k) is the sole and exclusive representation by Seller or its Affiliates with respect to any Environmental Law or environmental matter.

(l)Compliance with Laws. Except as described on Schedule 6.01(l), Seller's operation of the Assets has been, in all material respects, in accordance with all Laws, orders, rules and regulations of all Governmental Authorities having or asserting jurisdiction relating to the ownership and operation thereof, including the production of all Hydrocarbons attributable thereto. Since the Effective Time, Seller has not received any written notice of any such violation. Notwithstanding the foregoing, Seller makes no representation or

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warranty in this Section 6.01(l) with respect to any matters relating to the environment or Environmental Law, which representations and warranties are set forth in Section 6.01(k).

(m)Contracts. Exhibit A – Part 4 lists all Material Contracts. As of the date of this Agreement, Seller has not received any written notice alleging any breach by Seller of such Material Contracts that has not been previously cured or otherwise remedied and to Seller’s Knowledge (i) there is no breach by any counterparties to such Material Contracts, and (ii) each of the Material Contracts is in full force and effect.

(n)AFEs. Schedule 6.01(n) contains a true and correct list as of the Effective Time of all material authorities for expenditures (collectively, “AFEs”) relating to the Assets operated by Seller, and to Seller’s Knowledge, the Assets not operated by Seller, to drill or rework Wells or for capital expenditures with respect to the Assets that have been proposed by any Person having authority to do so other than internal AFEs of Seller not delivered to Third Parties. For the purposes of this Section 6.01(n), an AFE shall be material if, net to Seller’s interest, such AFE exceeds $100,000 and such AFE is (or was as of the Effective Time) valid and outstanding.

(o)Preferential Purchase Rights. There are no preferential rights to purchase or similar rights that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby.

(p)Imbalances. Except as set forth in Schedule 6.01(p), as of the dates set forth on Schedule 6.01(p), there are no Imbalances attributable to the Assets operated by Seller, and to Seller’s Knowledge, the Assets not operated by Seller, as of the Effective Time which require payment from Buyer to a Third Party or for which Buyer would otherwise be responsible.

(q)Payout Balances. Schedule Section 6.01(q) contains a complete list of the estimated status of any “payout” balance, as of the dates shown in such Schedule, for each Property operated by Seller, and to Seller’s Knowledge, for each Property not operated by Seller, that is subject to a reversion or other adjustment at some level of cost recovery or payout.

(r)Plugging and Abandonment. Except as set forth in Schedule 6.01(r), there are no Wells operated by Seller located on the Leases that:

(i)Seller has received an order from any Governmental Authority requiring that such Well be plugged and abandoned;

(ii)were producing as of the Effective Time, but that as of the date of this Agreement are shut in and have been for more than twenty (20) days, or temporarily abandoned; or

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(iii)to Seller’s Knowledge, have been plugged and abandoned but have not been plugged in accordance with all applicable requirements of each Governmental Authority having jurisdiction over the Assets.

(s)Calls. Seller has not granted to any Person any call upon, option to purchase, or similar rights with respect to any portion of the production from the Assets operated by Seller.

(t)Non-Consent Operations. Seller has not elected with respect to any operation or activity proposed to Seller with respect to the Properties which could result in any of Seller’s interest in such Properties becoming subject to a penalty or forfeiture as a result of such election by Seller not to participate in such operation or activity.

(u)Suspended Funds. There are no proceeds from production attributable to the Properties (as of January 31, 2015 for gas and as of February 28, 2015 for oil)that are currently held in suspense by Seller, other than as shown on Section 6.01(u).

Section 6.02Representations and Warranties of Buyer. Buyer represents and warrants to Seller as follows:

(a)Organization. Buyer is a limited partnership duly organized, validly existing and in good standing under the Laws of Texas.

(b)Qualification. Buyer is duly qualified to do business and is in good standing in each jurisdiction in which the nature of its business as now conducted makes such qualification necessary.

(c)Authorization / Consents. The execution and delivery by Buyer of this Agreement and the performance of its obligations hereunder have been duly and validly authorized by all requisite action by Buyer’s governing body and under its organizational documents. Buyer is not required to give any notice to, make any filing with or obtain any authorization, consent, or approval from any Governmental Authority or, except as set out in Schedule 6.02(c) hereto, any Third Party in order for Buyer to consummate the transactions contemplated by this Agreement.

(d)Enforceability. This Agreement has been duly executed and delivered by Buyer and constitutes the valid and legally binding obligation of Buyer, enforceable in accordance with its terms and conditions, except insofar as the enforceability thereof may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar Laws affecting the enforcement of creditors’ rights generally and by general principles of equity, regardless of whether such principles are considered in a proceeding at Law or in equity.

(e)Noncontravention. Except where same would not hinder or impede the consummation by Buyer of the transactions contemplated by this Agreement, neither the execution and the delivery of this Agreement, nor the consummation of the transactions

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contemplated hereby by Buyer will violate or breach the terms of, cause a default under, result in acceleration of, create in any party the right to accelerate, terminate, modify or cancel this Agreement or require any notice under: (%4) any applicable Law, (%4) the organizational documents of Buyer, or (%4) any material contract of Buyer.

(f)Litigation. There are no suits, actions or litigation before or by any Governmental Authority that are pending or, to Buyer's Knowledge, threatened against Buyer or any Affiliate of Buyer that would hinder or impede the consummation by Buyer of the transactions contemplated by this Agreement.

(g)Brokers’ Fees. Buyer has no Liability or obligation to pay any fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement for which Seller will be liable or obligated.

(h)Financing. Buyer has sufficient cash, available lines of credit or other sources of immediately available funds (in United States dollars) to enable Buyer to pay the Purchase Price to Seller at the Closing.

(i)Investment. Buyer is an experienced and knowledgeable investor in the oil and gas business. Prior to entering into this Agreement, Buyer was advised by and has relied solely on its own legal, tax and other professional counsel concerning this Agreement, the Assets and the value thereof. In making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Buyer has relied solely on the basis of its own independent valuation and due diligence investigation of the Assets.

(j)Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended. Buyer is acquiring the Assets for its own account and not for distribution or resale in any manner that would violate any state or federal securities Law.

ARTICLE VIICERTAIN COVENANTS

Section 7.01Access. Buyer hereby agrees to defend, indemnify, release and hold harmless the Seller Indemnitees and all co-owners of the Assets from and against any and all Liabilities arising out of or relating to the access to Seller’s or its Affiliates’ offices or the Assets by Buyer and/or its Affiliates and their respective officers, employees, agents, advisors and representatives in connection with this Agreement or any due diligence activity conducted by Buyer or its Affiliates or any of their respective officers, employees, agents, advisors or representatives in connection with the transactions contemplated by this Agreement. THE DEFENSE, RELEASE, INDEMNIFICATION AND HOLD HARMLESS OBLIGATIONS SET FORTH IN THIS SECTION 7.01 SHALL ENTITLE THE INDEMNITEE TO SUCH DEFENSE, RELEASE, INDEMNIFICATION AND HOLD HARMLESS HEREUNDER IN ACCORDANCE WITH THE TERMS HEREOF, REGARDLESS OF WHETHER THE CLAIM GIVING RISE TO SUCH OBLIGATION IS THE RESULT OF: (A) STRICT LIABILITY, (B) THE VIOLATION OF ANY

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LAW BY SUCH INDEMNITEE OR BY A PRE-EXISTING CONDITION, OR (C) THE SOLE, CONCURRENT OR COMPARATIVE NEGLIGENCE OF SUCH INDEMNITEE.

Section 7.02Confidentiality. Buyer acknowledges that, by virtue of its right of access to the Files and the Assets hereunder, Buyer will become privy to confidential and other information of Seller and its Affiliates and that such confidential information shall be held confidential by Buyer and Buyer’s and its Affiliates and their respective officers, employees, agents, advisors or representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets).

Section 7.03Dispositions of Assets. During the Interim Period, Seller shall not, without the prior consent of Buyer (which consent shall not be unreasonably withheld or delayed), transfer, farmout, sell, encumber or otherwise dispose of any Assets, except for (a) sales and dispositions of Hydrocarbon production in the ordinary course of business, (b) sales of equipment that is no longer necessary in the operation of the Assets or for which replacement equipment is obtained, or (c) transfers, farmouts, sales or other similar dispositions of Assets, in one or more transactions, not exceeding in the aggregate $100,000 of consideration (in any form).

Section 7.04Operations. Except as provided in this Agreement, during the Interim Period, Seller shall (a) use commercially reasonable efforts to operate and maintain, or cause any applicable Third Party operator to operate and maintain, the Assets, consistent with past practices, (b) provide prompt notice to Buyer of any written notice received by Seller of a material claim asserting any breach of contract, tort, or violation of Law or suit that, in each case, directly impacts any of the Assets, (c) to the extent known to Seller, provide Buyer with written notice of (i) any claims, demands, suits or actions made against Seller which materially affect the Assets; or (ii) any proposal from a Third Party to engage in any material transaction with respect to the operation of the Assets, and (d) fulfill all material contractual or other covenants, obligations and conditions imposed upon Seller with respect to the Assets, including, but not limited to, payment of royalties, delay rentals, shut-in gas royalties and any and all other required payments. In addition, during the Interim Period, except as set forth on Schedule 7.04, Seller shall not, without Buyer’s prior consent, which consent shall not be unreasonably withheld or delayed, (a) propose, under any joint operating agreement, any operation with respect to the Assets reasonably expected to cost Seller in excess of $100,000; (b) consent to any operation with respect to the Assets reasonably expected to cost Seller in excess of $100,000 that is proposed by any Third Party, or elect not to participate in any operation with respect to the Assets that is proposed by any Third Party; (c) enter into any contract that would constitute a Material Contract hereunder; except in each case of subsections (a) through (c) above, where such operation is (i) in connection with an AFE listed in Schedule Section 6.01(n), (ii) in response to an emergency, or (iii) is necessary to maintain or prevent forfeiture of a Lease or other Property; (d) reduce or terminate (or cause to be reduced or terminated) any insurance coverage now held in connection with the Assets; or (e) except for the Permitted Encumbrances, mortgage or pledge or create or suffer to exist any encumbrance on any of the Assets. Buyer acknowledges that Seller owns undivided interests in certain of the properties comprising the Assets that it is not the operator thereof, and Buyer agrees that the acts or omissions of the other working interest owners (including the operators) who are not Seller or Affiliates of Seller shall not constitute a breach of

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the provisions of this Section 7.04, nor shall any action required by a vote of working interest owners constitute such a breach so long as Seller has voted its interest in a manner that complies with the provisions of this Section 7.04.

Section 7.05Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Seller or its Affiliates with Governmental Authorities and relating to the Assets, are transferable or are to be transferred to Buyer. On or before the Closing Date, Buyer shall obtain, or cause to be obtained in the name of Buyer or its designee, replacements for such bonds, letters of credit and guarantees to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guarantees posted by Seller and/or its Affiliates relating to the Assets. In addition, at or prior to Closing, Buyer shall deliver to Seller evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such authorities for Buyer to own and, where appropriate, operate, the Assets.

Section 7.06Non-Solicitation of Employees. From and after the date of this Agreement until the date that is 12 months after the Closing Date or the date this Agreement is terminated pursuant to Section 11.01, Buyer and its Affiliates may not solicit or hire any officer or employee of Seller or its Affiliates without first obtaining the prior written consent of Seller; provided that this prohibition shall not apply to offers of employment made by Buyer or its Affiliates pursuant to a general solicitation of employment to the public or the industry.

Section 7.07Additional Interests. During the period prior to the Closing Date, Seller or its Affiliates may acquire Target Acreage. At Closing, (a) the Purchase Price shall be increased by the Target Acreage Payment Amount and (b) Exhibit A—Part 1 or Exhibit A—Part 1-A, as applicable, shall be revised to include all of the Target Acreage acquired by Seller or its Affiliates prior to Closing as part of the Leases for all purposes under this Agreement.

Section 7.08Seller’s Rights Under Chesapeake Agreement. Prior to the Closing, subject to the terms and conditions of the Chesapeake Cooperation Agreement, Seller shall use commercially reasonable efforts to comply with provisions of the Chesapeake Cooperation Agreement pertaining to assignment and assumption of rights under that agreement.

Section 7.09Amendment to Schedules. Buyer agrees that, with respect to the representations and warranties of Seller contained in this Agreement, Seller shall have the continuing right until Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising or discovered which, if existing or known on the date of the execution of this Agreement or thereafter, would have been required to be set forth or described in such Schedules. For all purposes of this Agreement, including for purposes of determining whether the conditions set forth in Section 8.02 have been fulfilled, the Schedules to Seller’s representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the date of the execution of this Agreement and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto; provided, however, that if Closing shall occur, then all matters disclosed pursuant to any such addition, supplement or amendment at or prior to Closing shall be waived and Buyer shall not be entitled to make a claim with respect thereto pursuant to the terms of this Agreement or otherwise.

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Section 7.10Knowledge of Breach. Buyer will notify Seller promptly and in reasonable detail of any Knowledge Buyer or any Affiliate of Buyer, or any of their respective officers or representatives has on or prior to the execution of this Agreement that any representation, warranty, covenant, or other agreement of Seller contained in this Agreement is, becomes, or will be untrue, or has been or may be breached, as applicable, in any material respect on or before the Closing Date. No breach of any representation, warranty, covenant, agreement or condition of this Agreement shall be deemed to be a breach of this Agreement for any purpose under this Agreement, and none of Buyer or any Affiliate of Buyer shall have any claim or recourse against Seller or any Affiliate of Seller, or their respective directors, officers, employees, Buyers, controlling persons, agents, advisors or representatives with respect to such breach, if Buyer or any Affiliate of Buyer, or any of their respective officers or representatives, had Knowledge prior to the execution of this Agreement of such breach or of the threat of such breach or the circumstances giving rise to such breach.

Section 7.11Casualty. If any Asset shall be damaged or destroyed by fire or other casualty before the Closing, Seller, at its sole option, and upon written notice prior to Closing to Buyer, may elect (1) to exclude such Asset from this Agreement or (2) cause such Assets to be repaired and restored, at Seller’s sole cost, as promptly as reasonably practicable (which work may extend after the Closing Date). In the event that the Asset to be excluded pursuant to this Section 7.11 is the entirety of the Lease or Term Lease, as applicable, the Purchase Price shall be reduced by the Allocated Value of the Lease or Term Lease, as applicable, and associated Wells, if any, to be excluded. In the event that the Asset sought to be excluded is less than the entirety of a Lease or Term Lease, as applicable, the Purchase Price shall be reduced by a mutually agreed upon amount. If Seller elects not to delete or repair such Asset from this Agreement as aforesaid, and the Closing thereafter occurs, Seller, at Closing, shall pay to Buyer any insurance proceeds actually received by it by reason of such casualty, and assign to Buyer all of its right, title and interest in any claim under any applicable insurance policies and against all third parties in respect of such casualty; provided however, that Seller shall reserve and retain (and Buyer shall assign to Seller) all right, title, and interest in any claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to Closing in repairing such casualty loss and/or pursuing or asserting any such insurance claims or other rights against Third Parties.

ARTICLE VIIICONDITIONS TO CLOSING

Section 8.01Conditions to Seller’s Obligations. The obligations of Seller to consummate the transactions provided for herein are subject, at the option of Seller, to the fulfillment on or prior to the Closing Date of each of the following conditions:

(d)Representations. The representations and warranties of Buyer set forth in this Agreement shall be true and correct in all material respects on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date.

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(e)Performance. Buyer shall have materially performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date.

(f)Pending Matters. No suit, action or other proceeding (instituted by a Person other than Seller or its Affiliates) shall be pending or threatened that seeks to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement.

(g)Execution and Delivery of Closing Documents. Buyer shall have executed and acknowledged, as appropriate, and shall be ready, willing and able to deliver to Seller all of the documents described in Section 9.04 and Buyer shall be ready, willing and able to deliver to Seller the Adjusted Purchase Price.

(h)Performance Bonds. Buyer shall have obtained, or caused to be obtained, in the name of Buyer, replacements for Seller’s and/or Seller’s Affiliates’ bonds, letters of credit and guarantees, and such other bonds, letters of credit and guarantees to the extent required by Section 7.05.

(i)Consents. Buyer shall have obtained all material consents, authorizations, orders, permits and approvals for (or registrations, declarations or filings with) any Governmental Authority (other than the Customary Post-Closing Consents) or any other consents required in connection with the execution, delivery and performance of this Agreement and the transactions contemplated hereby shall have been obtained or made.

(j)Termination Threshold. The aggregate amount of all Title Defect Amounts, Environmental Defect Amounts (whether such amounts are agreed or in dispute at the time of Closing), and Allocated Value of Assets excluded pursuant to Section 4.12(a) and exercised or outstanding preferential purchase rights shall not exceed 20% of the Purchase Price.

Section 8.02Conditions to Buyer’s Obligations. The obligations of Buyer to consummate the transactions provided for herein are subject, at the option of Buyer, to the fulfillment on or prior to the Closing Date of each of the following conditions:

(a)Representations. The representations and warranties of Seller set forth in this Agreement shall be true and correct in all material respects on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date.

(b)Performance. Seller shall have materially performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or at the Closing Date.

(c)Pending Matters. No suit, action or other proceeding (initiated by a Person other than Buyer or its Affiliates) shall be pending or threatened that seeks to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement.

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(d)Execution and Delivery of Closing Documents. Seller shall have executed and acknowledged, as appropriate, and shall be ready, willing and able to deliver to Buyer all of the documents described in Section 9.03.

(e)Consents. Seller shall have obtained consents required under the Chesapeake Cooperation Agreement and the Acreage Trade and Purchase Agreement and, subject to Section 4.12, Seller shall have obtained all material consents, authorizations, orders, permits and approvals for (or registrations, declarations or filings with) any Governmental Authority, and any other consents, including the consents to assignments of Contracts, required in connection with the execution, delivery and performance of this Agreement and the transactions contemplated hereby shall have been obtained or made.

(f)Termination Threshold. The aggregate amount of all Title Defect Amounts, Environmental Defect Amounts (whether such amounts are agreed or in dispute at the time of Closing), and Allocated Value of Assets excluded pursuant to Section 4.12(a) and exercised or outstanding preferential purchase rights shall not exceed 20% of the Purchase Price.

ARTICLE IXCLOSING

Section 9.01Time and Place of Closing. If the conditions referred to in Article VIII have been satisfied or waived in writing, the sale by Seller and the purchase by Buyer of the Assets pursuant to this Agreement (the “Closing”) shall take place at the offices of Vinson & Elkins LLP located at 1001 Fannin Street, Houston, Texas 77002, at 10:00 a.m., Houston time, on June 22, 2015or such earlier or later date as is mutually agreed by the Parties (the “Closing Date”).

Section 9.02Closing Statement; Adjustments to Purchase Price at Closing. Seller shall prepare and deliver to Buyer not later than 3 Business Days prior to Closing, a statement prepared in accordance with GAAP which sets forth Seller's good faith estimate of the adjustments of the Purchase Price made in accordance with the following provisions (the "Closing Statement"), reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Closing Statement and the calculation of the adjustments used to determine such amount:

(c)At the Closing, the Purchase Price shall be increased in the following amounts:

(i)all costs and expenses (including royalties, capital expenditures, lease operating expenses, overhead, rentals, lease renewals, and other lease maintenance payments but excluding, for the avoidance of doubt, any Asset Taxes and Income Taxes) paid by Seller that are (A) attributable to the Assets and (B) attributable to any period of time from and after the Effective Time;

(ii)the Overhead Costs;

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(iii)the value of all merchantable Hydrocarbons produced from or attributable to the Properties prior to the Effective Time that are in storage prior to sale and that are upstream of the sales metering point as of the Closing Date;

(iv)the sum of all Title Benefit Amounts of any Title Benefits for which the Title Benefit Amounts have been determined prior to Closing pursuant to Section 4.08;

(v)the Target Acreage Payment Amount;

(vi)the amount of all Asset Taxes allocated to Buyer in accordance with Section 14.01 but paid or otherwise economically borne by Seller;

(vii)the amount of any applicable adjustments for Imbalances as of the Effective Date; and

(viii)any other amount provided for in this Agreement or agreed upon by Seller and Buyer.

(d)At the Closing, the Purchase Price shall be decreased, as set forth in the Closing Statement, in the following amounts:

(v)except for any Excluded Asset, the amount of all proceeds received by Seller with respect to the Assets that are attributable to the period of time from and after the Effective Time (but in no event including Hydrocarbons produced prior to the Effective Time);

(vi)if Seller makes the election under Section 4.07(a) with respect to a Title Defect, the Title Defect Amount with respect to such Title Defect if the Title Defect Amount has been determined prior to Closing or, the Title Defect Amount associated with an Asserted Title Defect that has not been cured by Seller prior to Closing and is being held by the Escrow Agent pursuant to Section 4.06;

(vii)unless Seller or Buyer makes the election under Section 5.04(b) with respect to an Environmental Defect, the Environmental Defect Amount with respect to such Environmental Defect if the Environmental Defect Amount has been determined prior to Closing or, the Allocated Value associated with an Asserted Environmental Defect that has not been cured by Seller prior to Closing and is being held by the Escrow Agent pursuant to Section 5.03;

(viii)the Allocated Value of any Assets removed from the transaction pursuant to Section 4.07(b), Section 4.12(a), or Section 5.04(b);

(ix)the amount of all Asset Taxes allocated to Seller in accordance with Section 14.01 but paid or otherwise economically borne by Buyer;

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(x)the amount of any applicable adjustments for Imbalances as of the Effective Date; and

(xi)any other amount provided for in this Agreement or agreed upon by Seller and Buyer.

(e)Seller shall prepare within 90 days after the Closing Date and furnish to Buyer a final accounting statement setting forth the adjustments and pro-rating of any amounts provided for in Article IX or elsewhere in this Agreement, including, without limitation, any adjustments required pursuant to the dispute resolution procedures set forth in Section 4.11 (the “Final Accounting Statement”). Buyer shall within 30 days after receipt of the Final Accounting Statement deliver to Seller a written report (together with reasonable supporting documentation) containing any changes that Buyer proposes be made to such Final Accounting Statement (the “Dispute Notice”). Any changes not so specified in the Dispute Notice shall be deemed waived and Seller’s determinations with respect to all such elements of the Final Accounting Statement that are not addressed specifically in the Dispute Notice shall prevail. If Buyer fails to timely deliver a Dispute Notice to Seller containing changes Buyer proposes to be made to the Final Accounting Statement, the Final Accounting Statement as delivered by Seller will be deemed to be correct and mutually agreed upon by the Parties, and will be final and binding on the Parties and not subject to further audit or arbitration. The Parties shall undertake to agree on the final adjustment amounts and such final adjustment amounts shall be paid by Buyer or Seller, as appropriate, not later than 5 days after such agreement. During the foregoing periods of time, either Party may at its own expense audit the other Party’s books, accounts and records relating to production proceeds, operating expenses and Asset Taxes paid that may have been adjusted on account of this transaction. Such audit shall be conducted so as to cause a minimum of inconvenience to the audited Party. The occurrence of the Closing shall not relieve either Party of its obligation to account to the other Party after the Closing with respect to amounts that are received or become due after the Closing and that are properly payable or chargeable to either Party pursuant to any provision of this Agreement.

(f)If Seller and Buyer are unable to resolve the matters addressed in the Dispute Notice, each of Buyer and Seller shall, within 15 Business Days after the delivery of such Dispute Notice, summarize its position with regard to such dispute in a written document of twenty pages or less and submit such summaries to Opportune LLP, or such other party as the Parties may mutually select (the “Accounting Arbitrator”), together with the Dispute Notice, the Final Accounting Statement and any other documentation such Party may desire to submit. Within 30 Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either Seller’s position or Buyer’s position with respect to each matter addressed in any Dispute Notice, based on the materials described above. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against any of the Parties in any court of competent jurisdiction. The costs of such Accounting Arbitrator shall be borne one-half by Buyer and one-half by Seller.

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Section 9.03Actions of Seller at Closing. At the Closing, Seller shall:

(c)execute and deliver to Buyer assignments, substantially in the form of Exhibit C (the “Assignments”), and such other instruments, in form and substance mutually agreed upon by Buyer and Seller, as may be necessary or desirable to convey ownership, title and possession of the Assets to Buyer;

(d)execute and deliver to Buyer a Mineral Deed, substantially in the form of Exhibit D;

(e)deliver an executed certificate of non-foreign status that meets the requirements set forth in Treasury Regulation § 1.1445-2(b)(2);

(f)deliver to Buyer releases of any mortgages and terminations of any security interests (in each case) with respect to the Assets that secure Seller’s and/or its Affiliates’ credit facilities;

(g)execute and deliver to Buyer change of operator forms executed by Seller, suitable for with the applicable Government Authority;

(h)execute and deliver to Buyer, all Letters-in-Lieu or division orders;

(i)execute and deliver any other agreements that are provided for herein or are necessary or desirable to effectuate the transactions contemplated hereby;

(j)execute and deliver all other forms required by any Governmental Authority relating to the assignment of the Assets and relating to the assumption of operations by Buyer;

(k)deliver possession of the Assets to Buyer subject to Section 10.02; and

(l)to the extent permitted by the Chesapeake Cooperation Agreement and the Acreage Trade and Purchase Agreement, Seller shall deliver an assignment to Buyer of all rights and obligations under the Chesapeake Cooperation Agreement and the Acreage Trade and Purchase Agreement, in each case, insofar and only insofar as such rights and obligations relate to the Assets.

Section 9.04Actions of Buyer at Closing. At the Closing, Buyer shall:

(a)deliver to Seller the Adjusted Purchase Price, less the Deposit, by wire transfer as set forth in Section 3.01;

(b)deliver to Seller counterparts of the Assignments executed by Buyer; and

(c)execute, acknowledge and deliver any other agreements provided for herein or necessary or desirable to effectuate the transactions contemplated hereby and the appointment of Buyer as operator of the Assets operated by Seller as of the Effective Date.

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Section 9.05Actions of Buyer and Seller at Closing. At the Closing, Buyer and Seller shall instruct the Escrow Agent to pay the Deposit to Seller (less any amounts held back pursuant to Section 4.06 or Section 5.03 pending resolution of such matters related to Title Defects and Environmental Defects).

ARTICLE XCERTAIN POST-CLOSING OBLIGATIONS

Section 10.01Operation of the Assets After Closing. It is expressly understood and agreed that neither Seller nor any of its Affiliates shall be obligated to continue operating any of the Assets upon and after the Closing and Buyer hereby assumes full responsibility for operating (or causing the operation of) all Assets upon and after the Closing.

Section 10.02Files. Seller shall make the Files available for pickup by Buyer within 15 days after the Closing and Buyer shall pick up such Files on such date or within 5 days thereafter.

Section 10.03Further Cooperation. After the Closing, and subject to the terms and conditions of this Agreement, each Party, at the request of the other and without additional consideration, shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer and shall take such other action as the other Party may reasonably request to convey and deliver the Assets to Buyer in the manner contemplated by this Agreement. After the Closing, the Parties will cooperate to have all proceeds received attributable to the Assets paid to the proper Party hereunder and to have all expenditures to be made with respect to the Assets made by the proper Party hereunder; provided that Seller shall have no further responsibility for any Operating Expenses following the adjustments made pursuant to the Final Accounting Statement.

Section 10.04Document Retention.

(h)Inspection. Subject to the provisions of Section 10.04(b) and Section 14.03, at Seller’s expense, Buyer agrees, and will cause its respective assigns to agree, that the Files related to all periods prior to the Final Accounting Statement shall be open for inspection by representatives of Seller at reasonable times and upon reasonable notice during regular business hours for a period of four (4) years following the Closing Date (or for such longer period as may be required by Law or Governmental Authorities) and that Seller may, during such period and at its expense, make such copies thereof as it may reasonably request; provided, however, that such access by Seller (i) shall be conducted during the normal business hours of Buyer and (ii) shall not unreasonably interfere with the operations and activities of Buyer.

(i)Destruction. Without limiting the generality of the foregoing, for a period of four (4) years after the Closing Date (or for such longer period as may be required by Law or by Governmental Authorities), Buyer shall not, and shall cause its respective assigns to agree that they shall not, destroy or give up possession of any original or final copy of the Files without first offering Seller the opportunity, at Seller’s expense (without any payment to Buyer), to obtain such original or final copy or a copy thereof. At the written

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request of Seller, upon the conclusion of such period, Buyer shall offer to deliver to Seller, at Seller’s expense, the Files prior to destroying the same.

Section 10.05Suspense Accounts. At Closing, Seller shall transfer or cause to be transferred to Buyer all funds held by Seller in suspense related to proceeds of production and attributable to Third Parties’ interests in the Properties or Hydrocarbon production from the Properties, including funds suspended awaiting minimum disbursement requirements, funds suspended under division orders and funds suspended for title and other defects. Buyer agrees to administer all such accounts and assume all payment obligations relating to such funds to the extent transferred by Seller to Buyer in accordance with all applicable Laws, rules and regulations and shall be liable for the payment thereof to the proper parties and such obligations shall become part of the Assumed Obligations.

ARTICLE XITERMINATION

Section 11.01Right of Termination. This Agreement and the transactions contemplated hereby may be completely terminated at any time at or prior to the Closing:

(m)by mutual written consent of the Parties;

(n)by either Party, by written notice to the other, if the Closing shall not have occurred on or before 5:00 p.m. Houston time on June 30, 2015; provided, however, that no Party can so terminate this Agreement if such Party is at such time in material breach of this Agreement;

(o)by Seller, by written notice to Buyer, at Seller’s option, in the event the conditions set forth in Section 8.01 are not satisfied to the satisfaction of Seller at or prior to the Closing Date;

(p)by Buyer, by written notice to Seller, at Buyer’s option, if the conditions set forth in Section 8.02 are not satisfied to the satisfaction of Buyer at or prior to the Closing Date;

(q)by eitherParty, if consummation of the transactions contemplated by this Agreement would violate any non-appealable final order, decree or judgment of any state or federal court or agency enjoining, restraining, prohibiting or awarding substantial damages in connection with (i) Seller’s proposed sale of Assets to Buyer, or (ii) consummation of the transactions contemplated by this Agreement;

(r)by Buyer, by written notice to Seller, if the sum of all Title Defect Amounts and Environmental Defect Amounts, plus the Allocated Value of Assets excluded pursuant to Section 4.12(a) and exercised or outstanding preferential purchase rights exceeds 20% of the Purchase Price;

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(s)by Seller, by written notice to Buyer, if the sum of all Title Defect Amounts and Environmental Defect Amounts exceeds 20% of the Purchase Price; or

(t)by Seller, by written notice to Buyer, at Seller’s option, if Buyer has not deposited the Escrow Amount with the Escrow Agent within 3 Business Days of the execution of this Agreement.

Section 11.02Effect of Termination. In the event that the Closing does not occur as a result of either Party exercising its right not to close pursuant to Section 11.01, then, except as provided in Section 3.02 and except for the provisions of Section 1.01, Section 1.02, Section 7.01, Section 7.02, this Section 11.02, Section 12.06, Section 12.08, Section 12.10, Section 13.01 and Article XV, this Agreement shall thereafter be null and void and neither Party shall have any rights or obligations under this Agreement, except that nothing herein shall relieve any Party from Liability for any willful breach of its covenants or agreements hereunder; provided that if Seller retains the Deposit as liquidated damages pursuant to Section 3.02(b), then such retention shall constitute full and complete satisfaction of any and all damages Seller may have against Buyer. Notwithstanding anything to the contrary in this Agreement, in no event shall either Party be entitled to receive any indirect, consequential, punitive or exemplary damages, or damages for lost profits of any kind or loss of business opportunity.

ARTICLE XIIASSUMPTION AND INDEMNIFICATION

Section 12.01Assumption and Indemnity. As of the Closing, but without limiting Buyer’s rights to indemnity under Section 12.04 of this Agreement, Buyer assumes and agrees to pay, perform and discharge, or cause to be paid, performed, and discharged, all obligations and Liabilities with respect to the Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including:

(d)all obligations (whether arising by Law or by contract) to properly plug and abandon all wells and dismantle, decommission or remove all personal property, fixtures and related equipment now located on the land covered by or attributable to the Properties or other Assets or hereafter placed thereon, and all such obligations to cleanup and restore such lands;

(e)all Asset Taxes;

(f)all Liabilities attributable to the Assets arising from, attributable to or alleged to be arising from or attributable to, a violation of or the failure to perform any obligation imposed by any Environmental Law or otherwise relating to the environmental condition, effect or operation of the Assets;

(g)all obligations to settle any Imbalances;

(h)all obligations applicable to the lessee under any of the Leases; and

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(i)all other Liabilities with respect to the Assets arising prior to, on or after the Effective Time.

All such assumed obligations and Liabilities described above in this Section 12.01 are collectively referred to herein as the “Assumed Obligations”; provided that Buyer does not assume the Retained Liabilities, to the extent Seller has an indemnity obligation pursuant to Section 12.04, or the Excluded Assets, and “Assumed Obligations” does not include such matters.

Section 12.02Indemnification by Buyer. Effective as of Closing, Buyer hereby defends, releases, indemnifies and holds harmless the Seller Indemnitees from and against any and all Liabilities caused by, arising from, attributable to or alleged to be caused by, arising from or attributable to (a) any Assumed Obligation or (b) the breach by Buyer of any of its representations, warranties, covenants or agreements contained in this Agreement. The amount of Liabilities for which Seller is entitled to indemnity under this Section 12.02 shall be reduced by the amount of insurance proceeds realized by Seller or any of its Affiliates.

Section 12.03Buyer's Environmental Indemnification. Notwithstanding anything herein to the contrary, in addition to the indemnities set forth in Section 12.02, effective as of the Closing and except to the extent for which Seller’s indemnity and defense obligations in Section 12.04(b) apply and have not otherwise terminated, Buyer and its successors and assigns shall assume (as part of the Assumed Obligations), be responsible for, shall pay on a current basis and defend, indemnify, hold harmless and forever release the Seller Indemnitees from and against any and all Liabilities arising from, based upon, related to or associated with any environmental condition or other environmental matter related or attributable to the Assets regardless of whether such Liabilities arose prior to, on or after the Effective Time, including the presence, disposal or removal of any pollutant, contaminant, or hazardous or toxic substance, waste or material of any kind regulated under any Environmental Law in, on or under the Assets or other property (whether neighboring or otherwise) and including any Liability of any Seller Indemnitees with respect to the Assets under any Environmental Laws, including the Comprehensive Environmental Response, Compensation and Liability Act (42 U.S.C. §§ 9601 et. seq.), the Resource Conservation and Recovery Act (42 U.S.C. § 6901 et. seq.), the Clean Water Act (33 U.S.C. §§ 466 et. seq.), the Safe Drinking Water Act (14 U.S.C. §§ 1401-1450), the Hazardous Materials Transportation Act (49 U.S.C. §§ 1801 et. seq.), the Toxic Substance Control Act (15 U.S.C. §§ 2601-2629), the Clean Air Act (42 U.S.C. § 7401 et. seq.), the Oil Pollution Act (33 U.S.C. § 2701 et. seq.), any and all amendments to the foregoing, and all state and local Environmental Laws, provided however that Buyer does not assume and does not agree to defend, indemnify, hold harmless or release Seller Indemnitees from and against any Liabilities arising from, based upon, related to or associated with the Excluded Assets or the Retained Liabilities nor any actions by Seller after the Closing Date associated with Seller’s efforts to cure any environmental Defects during the Cure Period.

Section 12.04Indemnification by Seller. From and after Closing, Seller hereby defends, indemnifies and holds harmless the Buyer Indemnitees from and against any and all Liabilities caused by, arising from or attributable to (a) the breach by Seller of any of its representations, warranties, covenants or agreements contained in this Agreement, (b) the Retained Liabilities or (c) any Seller Taxes. The amount of Liabilities for which Buyer is entitled to indemnity under this

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Section 12.04 shall be reduced by the amount of insurance proceeds realized by Buyer or any of its Affiliates.

Section 12.05Limitations.

(a)Buyer Indemnitees shall not be entitled to assert any right to indemnification pursuant to Section 12.04 (i) for any individual Liability unless the amount with respect to such Liability exceeds $50,000 and (ii) until the aggregate amount of all such Liabilities exceeding $50,000 and actually suffered by Buyer Indemnitees in connection therewith exceeds 2% of the Purchase Price (the “Indemnity Deductible”), and then only to the extent such Liabilities exceeding $50,000 exceed, in the aggregate, the Indemnity Deductible (it being agreed that such Indemnity Deductible shall be a true deductible).

(b)In no event shall Seller ever be required to indemnify the Buyer Indemnitees for Liabilities under Section 12.04 exceeding, in the aggregate, 25% of the Purchase Price; and Buyer (on its own behalf and on behalf of the other Buyer Indemnitees) waives, releases and forever discharges Seller from any and all Liabilities under Section 12.04 in excess of this aggregate amount; provided, however the limitations set forth in clauses (a) and (b) of this Section 12.05 shall not apply to Retained Liabilities that the Buyer does not assume under Section 12.01.

Section 12.06Negligence and Fault. THE DEFENSE, RELEASE, INDEMNIFICATION AND HOLD HARMLESS OBLIGATIONS SET FORTH IN THIS AGREEMENT (INCLUDING SECTION 7.01, SECTION 12.02, SECTION 12.03, AND SECTION 12.04) SHALL ENTITLE THE INDEMNITEE TO SUCH DEFENSE, RELEASE, INDEMNIFICATION AND HOLD HARMLESS HEREUNDER IN ACCORDANCE WITH THE TERMS HEREOF, REGARDLESS OF WHETHER THE CLAIM GIVING RISE TO SUCH OBLIGATION IS THE RESULT OF: (A) STRICT LIABILITY, (B) THE VIOLATION OF ANY LAW BY SUCH INDEMNITEE OR BY A PRE-EXISTING CONDITION, OR (C) THE SOLE, CONCURRENT OR COMPARATIVE NEGLIGENCE OF SUCH INDEMNITEE.

Section 12.07Exclusive Remedy. From and after Closing, each of the Parties acknowledges and agrees that its sole and exclusive remedy with respect to any and all Liabilities pursuant to or in connection with this Agreement, the purchase of the Assets by Buyer and the sale of the Assets by Seller or otherwise in connection with the transactions contemplated hereby shall be limited to the indemnification provisions set forth in this Agreement. Except for the remedies contained in (a) this Article XII, (b) the Special Warranty of title in the Assignments and (c) as otherwise expressly provided in this Agreement, effective as of Closing, each Party, on its own behalf and on behalf of its Affiliates, hereby releases, remises and forever discharges the other Party and its Affiliates and all such parties' shareholders, partners, members, board of directors and/or supervisors, officers, employees, agents and representatives from any and all suits, legal or administrative proceedings, claims, demands, damages, losses, costs, Liabilities, interest or causes of action whatsoever, at Law or in equity, known or unknown, which Buyer or Seller, as applicable, or its respective Affiliates might now or subsequently may have, based on, relating to or arising out of this Agreement, the transactions contemplated hereby, the ownership, use or operation of the Assets or the condition, quality, status or nature of the Assets, including rights to contribution under the Comprehensive

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Environmental Response, Compensation, and Liability Act (42 U.S.C. § 9601 et. seq.), breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common law rights of contribution and rights under insurance maintained by Seller or any of its Affiliates, excluding, however, any contractual rights (apart from this Agreement) existing as of the date hereof between (a) Buyer or any of Buyer's Affiliates, on the one hand, and (b) Seller or any of Seller's Affiliates, on the other hand, under contracts between them relating to the Assets (if any).

Section 12.08Expenses. Notwithstanding anything herein to the contrary, the foregoing defense, release, indemnity and hold harmless obligations shall not apply to, and each Party shall be solely responsible for, all expenses, including due diligence expenses, incurred by it to enter into, and consummate the transactions contemplated by, this Agreement.

Section 12.09Survival; Knowledge.

(a)The representations and warranties of Seller and Buyer in Article VI (other than (i) the representations in Section 6.01(g) and Section 6.02(g), and (ii) the representations in Section 6.01(h), which shall survive until the expiration of the applicable statute of limitations with respect to the underlying Tax claim) and the covenants and agreements of Seller shall survive the Closing for a period of 18 months. Subject to the foregoing and as set forth in Section 12.09(b), the remainder of this Agreement shall survive the Closing without time limit. Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration; provided, however, that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(b)The indemnities in Section 12.04(b) shall terminate 24 months after the Closing and the other indemnities in Article XII shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification, except in each case as to matters for which a specific written claim for indemnity has been delivered on or before such termination date (other than Retained Liabilities related to any Assets excluded pursuant to Section 4.07, Section 5.04 or Section 4.12(a) , which shall survive the Closing without time limit).

Section 12.10Non-Compensatory Damages. None of the Buyer Indemnitees nor the Seller Indemnitees shall be entitled to recover from Seller or Buyer, or their respective Affiliates, any indirect, consequential, punitive or exemplary damages or damages for lost profits of any kind or loss of business opportunity arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such party suffers such damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending of such damages) to a Third Party, which damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder. Subject to the preceding sentence, Buyer, on behalf of each of the Buyer Indemnitees, and Seller, on behalf of each of the Seller Indemnitees, waive any right to recover punitive, special, exemplary and consequential damages, including damages for lost profits or loss of business opportunity, arising in connection with or with respect to this Agreement or the transactions contemplated hereby.

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Section 12.11Indemnification Actions. All claims for indemnification under this Article XII shall be asserted and resolved as follows:

(a)For purposes of this Agreement, the term “Indemnitor” when used in connection with particular damages shall mean the Person having an obligation to indemnify another Person or Persons with respect to such damages pursuant to this Agreement, and the term “Indemnitee” when used in connection with particular damages shall mean a Person having the right to be indemnified with respect to such damages pursuant to this Agreement.

(b)To make claim for indemnification under this Article XII, an Indemnitee shall notify the Indemnitor of its claim, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnitee (a “Claim”), the Indemnitee shall provide its Claim Notice promptly after the Indemnitee has actual knowledge of the Claim and shall enclose a copy of all papers (if any) served with respect to the Claim; provided that the failure of any Indemnitee to give notice of a Claim as provided in this Section 12.11 shall not relieve the Indemnitor of its obligations under this Article XII except to the extent (and only to the extent of such incremental damages incurred) such failure results in insufficient time being available to permit the Indemnitor to effectively defend against the Claim or otherwise prejudices the Indemnitor’s ability to defend against the Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c)In the case of a claim for indemnification based upon a Claim, the Indemnitor shall have 30 days from its receipt of the Claim Notice to notify the Indemnitee whether or not it agrees to indemnify and defend the Indemnitee against such Claim under this Article XII. The Indemnitee is authorized, prior to and during such 30 day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnitor and that is not prejudicial to the Indemnitor.

(d)If the Indemnitor agrees to indemnify the Indemnitee, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Claim. The Indemnitor shall have full control of such defense and proceedings, including any compromise or settlement thereof, subject to the terms hereof. If requested by the Indemnitor, the Indemnitee agrees to cooperate in contesting any Claim which the Indemnitor elects to contest (provided, however, that the Indemnitee shall not be required to bring any counterclaim or cross-complaint against any Person). The Indemnitee may participate in, but not control, at its sole cost and expense, any defense or settlement of any Claim controlled by the Indemnitor pursuant to this Section 12.11. An Indemnitor shall not, without the written consent of the Indemnitee, such consent not to be unreasonably withheld, conditioned or delayed, settle any Claim or consent to the entry of any judgment with respect thereto that (i) does not result in a final resolution of the Indemnitee’s Liability with respect to the Claim (including, in the case of a settlement, an unconditional written release of the Indemnitee from all

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Liability in respect of such Claim) or (ii) may materially and adversely affect the Indemnitee (other than as a result of money damages covered by the indemnity).

(e)If the Indemnitor does not agree to indemnify the Indemnitee within the 30 day period specified in Section 12.11(c) or fails to give notice to the Indemnitee within such 30 day period regarding its election or if the Indemnitor agrees to indemnify, but fails to diligently defend or settle the Claim, then the Indemnitee shall have the right to defend against the Claim (at the sole cost and expense of the Indemnitor, if the Indemnitee is entitled to indemnification hereunder), with counsel of the Indemnitee’s choosing; provided, however, that the Indemnitee shall make no settlement, compromise, admission or acknowledgment that would give rise to Liability on the part of any Indemnitor without the prior written consent of such Indemnitor, which consent shall not be unreasonably withheld, conditioned or delayed.

(f)In the case of a claim for indemnification not based upon a Claim, the Indemnitor shall have 30 days from its receipt of the Claim Notice to (i) cure the damages complained of, (ii) agree to indemnify the Indemnitee for such damages, or (iii) dispute the claim for such damages. If such Indemnitor does not respond to such Claim Notice within such 30 day period, such Indemnitor will be deemed to dispute the claim for damages.

Section 12.12Characterization of Indemnity Payments. The Parties agree that any indemnity payments made pursuant to this Article XII shall be treated for all Tax purposes as an adjustment to the Purchase Price unless otherwise required by Law.

ARTICLE XIIILIMITATIONS ON REPRESENTATIONS AND WARRANTIES

Section 13.01Disclaimers of Representations and Warranties.

(j)EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN SECTION 6.01 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE IN THE ASSIGNMENTS, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING, WITHOUT LIMITATION, ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY ANY OFFICER, DIRECTOR, SUPERVISOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF ITS AFFILIATES).

(k)EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN SECTION 6.01 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE IN THE ASSIGNMENTS, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR

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WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER, ITS AFFILIATES OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(l)EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN SECTION 6.01 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE IN THE ASSIGNMENTS, SELLER EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY WAIVES (I) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (II) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, (III) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, (IV) ANY RIGHTS OF PURCHASERS UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION, (V) ANY CLAIMS BY BUYER FOR DAMAGES BECAUSE OF REDHIBITORY VICES OR DEFECTS, WHETHER KNOWN OR UNKNOWN AS OF THE EFFECTIVE TIME OR THE CLOSING DATE, AND (VI) ANY AND ALL IMPLIED WARRANTIES EXISTING UNDER APPLICABLE LAW; IT BEING THE EXPRESS INTENTION OF BOTH BUYER AND SELLER THAT, EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN SECTION 6.01 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE IN THE ASSIGNMENTS, THE ASSETS SHALL BE CONVEYED TO BUYER IN THEIR PRESENT CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS,” WITH ALL FAULTS, AND THAT BUYER HAS MADE OR SHALL MAKE PRIOR TO CLOSING SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(m)OTHER THAN EXPRESSLY SET FORTH IN SECTION 6.01(K) OF THIS AGREEMENT, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT, THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL

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RESOURCES OR THE ENVIRONMENT OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY. SUBJECT TO BUYER’S RIGHTS UNDER ARTICLE V OF THIS AGREEMENT AND OTHER THAN EXPRESSLY SET FORTH IN SECTION 6.01 OF THIS AGREEMENT, BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS,” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION, AND BUYER ACKNOWLEDGES IT HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(n)SELLER AND BUYER AGREE THAT THE DISCLAIMERS OF CERTAIN WARRANTIES CONTAINED IN THIS SECTION 13.01 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSES OF ANY APPLICABLE LAW, RULE OR ORDER.

ARTICLE XIV

TAX MATTERS

Section 14.01Allocation of Asset Taxes.

(c)Seller shall be allocated and bear all Asset Taxes attributable to (i) any Tax period ending prior to the Effective Time and (ii) the portion of any Straddle Period ending immediately prior to the Effective Time. Buyer shall be allocated and bear all Asset Taxes attributable to (x) any Tax period beginning at or after the Effective Time and (y) the portion of any Straddle Period beginning at the Effective Time.

(d)For purposes of determining the allocations described in Section 14.01(a), (i) Asset Taxes that are attributable to the severance or production of Hydrocarbons (other than Asset Taxes that are ad valorem or property Taxes) shall be allocated to the period in which the severance or production giving rise to such Asset Taxes occurred, (ii) Asset Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than such Asset Taxes described in clause (i)), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (iii) Asset Taxes that are ad valorem, property or other Asset Taxes imposed on a periodic basis pertaining to a Straddle Period shall be allocated between the portion of such Straddle Period ending immediately prior to the Effective Time and the portion of such Straddle Period beginning at the Effective Time by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur before the date on which the Effective Time occurs, on the one hand, and the number of days in such Straddle Period that occur on or after the date on which the Effective Time occurs, on the other hand. For purposes of clause (iii) of the preceding sentence, the period for such Asset Taxes shall begin on the date on which ownership of the applicable Assets gives rise to liability for the particular Asset Tax and shall end on the day before the next such date.

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(e)To the extent the actual amount of an Asset Tax is not determinable at the time an adjustment to the Purchase Price is to be made with respect to such Asset Tax pursuant to Section 9.02, (i) the Parties shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of such adjustment, and (ii) upon the later determination of the actual amount of such Asset Tax, timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such Asset Tax that is allocable to such Party under this Section 14.01.

Section 14.02Transfer Taxes. Buyer shall bear and pay all (i) sales, use, transfer, stamp, documentary, registration or similar Taxes incurred or imposed with respect to the transactions described in this Agreement (“Transfer Taxes”) and (ii) required filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer.  Seller and Buyer shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

Section 14.03Cooperation. The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation, or other proceeding with respect to Taxes relating to the Assets. Such cooperation shall include the retention and (upon another Party’s request) the provision of records and information that are relevant to any such Tax Return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement.

Section 14.04Refunds. Seller shall be entitled to any and all refunds of Asset Taxes allocated to Seller pursuant to Section 14.01, and Buyer shall be entitled to any and all refunds of Asset Taxes allocated to Buyer pursuant to Section 14.01.  If a Party or its Affiliate receives a refund of Asset Taxes to which the other Party is entitled pursuant to this Section 14.04, such recipient Party shall forward to the entitled Party the amount of such refund within thirty (30) days after such refund is received, net of any reasonable costs or expenses incurred by such recipient Party in procuring such refund.

Section 14.05Post-Closing Taxes. Subject to Buyer’s indemnification rights under Article XII of this Agreement, Buyer shall be responsible for payment to the applicable Governmental Authorities of all Asset Taxes that become due and payable on or after the Closing Date, and Buyer shall indemnify and hold Seller harmless from any failure to make such payments.

ARTICLE XVMISCELLANEOUS

Section 15.01Filings, Notices and Certain Governmental Approvals. As soon as reasonably possible after the Closing, but in no event later than 90 days after such Closing, Buyer shall remove the names of Seller and its Affiliates, including “Gastar” and all variations thereof, from the Assets. Promptly after Closing, Buyer shall make all requisite filings with, and provide the requisite notices to, the appropriate Governmental Authorities to accomplish all transactions contemplated by this Agreement.

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Section 15.02Entire Agreement. This Agreement, the Confidentiality Agreement, the documents to be executed pursuant hereto and the exhibits and schedules attached hereto constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof. No supplement, amendment, alteration, modification, waiver or termination of this Agreement shall be binding unless executed in writing by the Parties and specifically referencing this Agreement as being supplemented, amended, altered, modified, waived or terminated.

Section 15.03Waiver. No waiver of any of the provisions of this Agreement or rights hereunder shall be deemed or shall constitute a waiver of any other provisions hereof or right hereunder (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 15.04Publicity. Each Party shall consult with the other Party prior to making any public release concerning this Agreement or the transactions contemplated hereby and, except as required by applicable Law or by any Governmental Authority or stock exchange, no Party shall issue any such release without the prior written consent of the other Party, which consent shall not be unreasonably withheld or delayed.

Section 15.05No Third Party Beneficiaries. Except with respect to the Persons included within the definition of Seller Indemnitees or Buyer Indemnitees (and in such cases, only to the extent expressly provided herein), nothing in this Agreement shall provide any benefit to any Third Party or entitle any Third Party to any claim, cause of action, remedy or right of any kind, it being the intent of the Parties that this Agreement shall not be construed as a Third Party beneficiary contract.

Section 15.06Assignment. Neither Party may assign or delegate any of its rights or duties hereunder without the prior written consent of the other Party and any assignment made without such consent shall be void. Any assignment made by either Party as permitted hereby shall not relieve such Party from any Liability or obligation hereunder. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective permitted successors, assigns and legal representatives.

Section 15.07Governing Law. THIS AGREEMENT AND THE LEGAL RELATIONS AMONG THE PARTIES SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION; PROVIDED THAT, AS TO MATTERS RELATING TO TITLE TO THE ASSETS, THE LAWS OF THE STATE OF OKLAHOMA SHALL APPLY AS TO THE PROPERTY LOCATED IN (OR OTHERWISE SUBJECT TO THE LAWS OF) THAT STATE. ALL OF THE PARTIES HERETO CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE COURTS OF THE STATE OF TEXAS FOR ANY ACTION ARISING OUT OF THIS AGREEMENT. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY

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SHALL BE EXCLUSIVELY LITIGATED IN COURTS HAVING SITUS IN HOUSTON, HARRIS COUNTY, TEXAS. EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT.

Section 15.08Notices. Any notice, communication, request, instruction or other document required or permitted hereunder shall be given in writing and delivered in person or sent by United States mail (postage prepaid, return receipt requested), telex, facsimile (provided any such facsimile is confirmed by written confirmation), telecopy, or electronic mail transmission (“email”) (provided that receipt of such email is requested and received) to the addresses of Seller and Buyer set forth below. Any such notice shall be effective upon receipt only if received during normal business hours or, if not received during normal business hours, on the next Business Day.

Seller:	Gastar Exploration Inc. Attention: Henry J. Hansen 1331 Lamar, Suite 650 Houston, Texas 77010 Phone: 713-739-0443 Fax: 713-739-0458 Email: hhansen@gastar.com
Buyer:	Oklahoma Energy Acquisitions, LP Attention: Scott K. Cowand 15021 Katy Freeway, Suite 400 Houston, Texas 77094 Phone: 832-916-4623 Fax: 281-530-5278 Email: scowand@altamesa.net

Either Party may, by written notice so delivered, change its address for notice purposes hereunder.

Section 15.09Exclusivity. Until the earlier of Closing or the termination of this Agreement in accordance with its terms, Seller will not (a) solicit, initiate, or encourage the submission of a proposal or offer from any Person relating to the acquisition of any of the Assets or any substantial portion of the Assets or (b) participate in any negotiations regarding, furnish any information with respect to, assist any effort or attempt by any Person to do or seek any of the foregoing. Seller will notify Buyer promptly if any Person makes any written proposal or offer with respect to any of the foregoing.

Section 15.10Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner

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to either Party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 15.11Counterparts. This Agreement may be executed in any number of counterparts, and each counterpart hereof shall be deemed to be an original instrument, but all such counterparts shall constitute but one instrument. Any signature hereto delivered by a Party by facsimile or electronic transmission shall be deemed an original signature hereto.

Section 15.12Amendment. This Agreement may be amended only by an instrument in writing executed by all Parties.

Section 15.13Schedules and Exhibits. The inclusion of any matter upon any Schedule or any Exhibit attached hereto does not constitute an admission or agreement that such matter is material with respect to the representations and warranties contained herein.

[The remainder of this page is left intentionally blank.]

IN WITNESS WHEREOF, Seller and Buyer have executed this Agreement as of the date first written above.

SELLER

By: GASTAR EXPLORATION INC.

By: /s/ Michael A. Gerlich                

Name:    Michael A. Gerlich

Title:    Sr. Vice President and CFO

BUYER

By: OKLAHOMA ENERGY ACQUISITIONS, LP

By:    ALTA MESA GP, LLC

Its:    General Partner

By: /s/ Harlan H. Chappelle                

Name:    Harlan H. Chappelle

Title:    President & CEO

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EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, J. Russell Porter, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q 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 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.

Date: May 7, 2015

/S/ J. RUSSELL PORTER

J. Russell Porter

Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Michael A. Gerlich, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q 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 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.

Date: May 7, 2015

/S/ MICHAEL A. GERLICH

Michael A. Gerlich

Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER AND PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, J. Russell Porter, Principal Executive Officer, and I, Michael A, Gerlich, Principal Financial Officer, of Gastar Exploration Inc. (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the three and nine months ended March 31, 2015 (the “Report”), filed by the Company with the Securities and Exchange Commission on the date hereof complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 7, 2015

/S/ J. RUSSELL PORTER

J. Russell Porter

Principal Executive Officer

/S/ MICHAEL A. GERLICH

Michael A. Gerlich

Principal Financial Officer

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Capital Stock (Narrative) (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Apr. 24, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	40,000,000			40,000,000
Preferred stock par value per share	$ 0.01
Liquidation Preference (per share)	$ 25.00
Dividends on preferred stock	$ (3,618,000)	$ (3,576,000)
Common shares reserved for the exercise of stock options (shares)	866,600
Parent's 2006 Long-Term Stock Incentive Plan
Class of Stock [Line Items]
Increase in the number of share reserved for issuance			3,000,000
Common shares reserved for the exercise of stock options (shares)	2,849,434
Series A Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	10,000,000			10,000,000
Preferred stock, dividend rate, percentage (percentage)	8.625%
Preferred stock par value per share	$ 0.01			0.01
Liquidation Preference (per share)	$ 25.00			25.00
Preferred stock, shares issued	4,045,000			4,045,000
Preferred stock, shares outstanding	4,045,000			4,045,000
Dividends on preferred stock	(2,200,000)
Series B Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	10,000,000			10,000,000
Preferred stock, dividend rate, percentage (percentage)	10.75%
Preferred stock par value per share	$ 0.01			0.01
Liquidation Preference (per share)	$ 25.00			25.00
Preferred stock, shares issued	2,140,000			2,140,000
Preferred stock, shares outstanding	2,140,000			2,140,000
Preferred stock redemption price per share	$ 25.00
Option to convert shares of Series B Preferred Stock	11.5207
Recognized dividend expense	$ 1,400,000

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Derivative Instruments and Hedging Activity (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of commodity derivative contracts	$ 4,252	$ (3,155)

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Statement Of Cash Flows - Supplemental Information (Tables)

3 Months Ended

Mar. 31, 2015

Supplemental Cash Flow Information [Abstract]

Statement Of Cash Flows Supplemental Information

The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash paid for interest, net of capitalized amounts	$	(282	)	$	(697	)
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	$	(10,366	)	$	(299	)
Capital expenditures included in accounts receivable	—			4,077
Asset retirement obligation included in oil and natural gas properties	77			28
Application of advances to operators	8,457			9,490
Other	23			78

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Earnings Per Share (Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to common stockholders	$ (3,004)	$ (1,965)
Weighted average common shares outstanding basic (shares)	77,114,826	58,204,532
Weighted average common shares outstanding diluted (shares)	77,114,826	58,204,532
Basic (dollars per share)	$ (0.04)	$ (0.03)
Diluted (dollars per share)	$ (0.04)	$ (0.03)
Common shares excluded from denominator as anti-dilutive (shares)	823,881	119,496
Unvested restricted shares
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Shares	0	0
Common shares excluded from denominator as anti-dilutive (shares)	450,556	119,496
Stock options
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Shares	0	0
Common shares excluded from denominator as anti-dilutive (shares)	0	0
Unvested PBUs
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Shares	0	0
Common shares excluded from denominator as anti-dilutive (shares)	373,325	0

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Derivative Instruments and Hedging Activity (Schedule of Future Amortization of Put Premium) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
April to December 2015	$ 1,714
January to December 2016	3,050
January to December 2017	1,684
January to August 2018	833
Total unamortized put premium liabilities	$ 7,281	$ 7,183

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Long-Term Debt

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Second Amended and Restated Revolving Credit Facility

On June 7, 2013, the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). At the Company's election, borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent, (ii) the federal funds rate plus50 basis points or (iii) LIBOR plus 1.0%. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base and subject to adjustments based on the Company's leverage ratio. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity of November 14, 2017.

The Revolving Credit Facility will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on all domestic oil and natural gas properties currently owned by or later acquired by the Company and its subsidiaries, excluding de minimis value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of the Company.

The Revolving Credit Facility contains various covenants, including, among others:

• Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments;

• Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted;

• Maintenance of a maximum ratio of net indebtedness to EBITDA of not greater than 4.0 to 1.0, subject to the modifications in Amendment No. 5 set forth below; and

• Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0, subject to the modifications in Amendment No. 5 set forth below.

All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including, among others:

• Failure to make payments;

• Non-performance of covenants and obligations continuing beyond any applicable grace period; and

• The occurrence of a change in control of the Company, as defined under the Revolving Credit Facility.

OnMarch 9, 2015, the Company, together with the parties thereto, entered into a Master Assignment, Agreement and Amendment No. 5(“Amendment No. 5”) to Second Amended and Restated Credit Agreement. Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million, (ii) adjust the leverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016, to 5.25 to 1.00; for the fiscal quarter ending on September 30, 2016, to 5.00 to 1.00; for the fiscal quarter ending on December 31, 2016, to 4.75 to 1.00; for the fiscal quarter ending on March 31, 2017, to 4.25 to 1.00; and for each fiscal quarter ending on or after June 30, 2017, to 4.00 to 1.00, (iii) adjust the interest coverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016, to 2.00 to 1.00 and for each fiscal quarter ending on or after March 31, 2016, to 2.50 to 1.00, and (iv) add the senior secured leverage ratio covenant, such ratio not to exceed, (a) for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016, 2.25 to 1.00 and (b) for each fiscal quarter ending on or after June 30, 2016, 2.00 to 1.00 provided that this senior secured leverage ratio shall cease to apply commencing with the first fiscal quarter end occurring after June 30, 2016 for which the total leverage ratio is equal to or less than 4.00 to 1.00.

Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. The Company and its lenders may request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At March 31, 2015, the Revolving Credit Facility had a borrowing base of $200.0 million, with $65.0 million borrowings outstanding and availability of $135.0 million. The next regularly scheduled redetermination is set for November 2015. Future increases in the borrowing base in excess of the original $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the Notes agreement (as discussed below in “Senior Secured Notes”).

At March 31, 2015, the Company was in compliance with all financial covenants under the Revolving Credit Facility.

Senior Secured Notes

The Company has $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. The Notes will mature on May 15, 2018.

In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.

The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to the Company's unsecured indebtedness and effectively subordinated to the Company's and Guarantors' under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation.

The Indenture contains covenants that, among other things, limit the Company's ability and the ability of its subsidiaries to:

• Transfer or sell assets or use asset sale proceeds;

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

• Make certain investments; incur or guarantee additional debt or issue preferred equity securities;

• Create or incur certain liens on the Company's assets;

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

• Merge, consolidate or transfer all or substantially all of the Company's assets;

• Enter into certain transactions with affiliates; and

• Enter into certain sale and leaseback transactions.

These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.

At March 31, 2015, the Notes reflected a balance of $315.9 million, net of unamortized discounts of $9.1 million, on the condensed consolidated balance sheets.

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Commitments And Contingencies (Narrative) (Details) (Gastar Exploration Ltd vs US Speciality Ins Co and Axis Ins Co, USD $) In Millions, unless otherwise specified	0 Months Ended
	Dec. 17, 2010
Gastar Exploration Ltd vs US Speciality Ins Co and Axis Ins Co
Loss Contingencies [Line Items]
Settlement aggregate amount	$ 21.2
Combined coverage limits under directors and officers insurance	$ 20.0

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Long-Term Debt (Narrative) (Details) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Jun. 07, 2013	May 15, 2013	Dec. 31, 2014	Mar. 09, 2015	Mar. 08, 2015	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 29, 2016	Mar. 31, 2016	Mar. 30, 2016	Jun. 30, 2016	Jun. 29, 2016	Nov. 15, 2013
Line of Credit Facility [Line Items]
Long-term debt	380,916,000			$ 360,303,000
Second Amended and Restated Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility borrowing base	200,000,000.00	50,000,000.0			200,000,000.00	145,000,000
Borrowings outstanding	65,000,000
Borrowing availability	135,000,000
Increase in adjusted consolidated net tangibles assets	17.50%
Second Amended and Restated Revolving Credit Facility | Scenario, Forecast
Line of Credit Facility [Line Items]
Leverage ratio							4.00	4.25	4.75	5.0	5.25
Interest coverage ratio												2.5	2.00
Senior Secured Notes Due 2018 | Senior Secured Notes
Line of Credit Facility [Line Items]
Long-term debt	315,900,000
Unamortized discounts	9,100,000
Senior Secured Notes Due 2018 | Senior Secured Notes | Scenario, Forecast
Line of Credit Facility [Line Items]
Leverage ratio														2.0	2.25
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility
Line of Credit Facility [Line Items]
Annual commitment fee (percentage)	0.50%
Percentage of stock foreign subsidiary pledged as collateral for credit facility (percentage)	65.00%
Line of credit facility covenant compliance EBITDA to Interest Expense Ratio on a four quarter rolling basis	2.5
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Minimum
Line of Credit Facility [Line Items]
Line of credit facility covenant compliance Current Ratio	1.0
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Maximum | Each quarter thereafter
Line of Credit Facility [Line Items]
Line of credit facility covenant compliance indebtedness to EBITDA Ratio	4.0
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Interest rate description		federal funds rate plus
Applicable interest margin (percentage)		0.50%
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | LIBOR
Line of Credit Facility [Line Items]
Applicable interest margin (percentage)		1.00%
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Prime Rate | Minimum
Line of Credit Facility [Line Items]
Applicable interest margin (percentage)		1.00%
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Prime Rate | Maximum
Line of Credit Facility [Line Items]
Applicable interest margin (percentage)		2.00%
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Eurodollar Rate | Minimum
Line of Credit Facility [Line Items]
Applicable interest margin (percentage)		2.00%
Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Eurodollar Rate | Maximum
Line of Credit Facility [Line Items]
Applicable interest margin (percentage)		3.00%
Gastar Exploration USA | Senior Secured Notes Due 2018 | Senior Secured Notes
Line of Credit Facility [Line Items]
Aggregate principal amount			$ 325,000,000
Interest rate			8.625%													8.625%
Percentage of aggregate principal amount			101.00%

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Property, Plant And Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Impairment recorded (pre-tax) (in thousands)	$ 0		$ 0
Henry Hub natural gas price (per MMBtu)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe	3.88	[1]	3.99	[1]
West Texas Intermediate oil price (per Bbl)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe	82.72	[1]	98.30	[1]

[1] For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

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Statement Of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized amounts	$ (282)	$ (697)
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	(10,366)	(299)
Capital expenditures included in accounts receivable	0	4,077
Asset retirement obligation included in oil and natural gas properties	77	28
Application of advances to operators	8,457	9,490
Other	$ 23	$ 78

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Fair Value Measurements (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount reclassified from unproved to proved properties	$ 35,000
Impairment of unproved properties		194,000
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of long-term debt	$ 371,700,000

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Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	$ 32,219	$ 27,502
Liabilities:
Liabilities, Commodity derivative contracts	(396)	0
Total	43,966	38,510
Level 1
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	0	0
Liabilities:
Liabilities, Commodity derivative contracts	0	0
Total	12,143	11,008
Level 2
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	0	0
Liabilities:
Liabilities, Commodity derivative contracts	0	0
Total	0	0
Level 3
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	32,219	27,502
Liabilities:
Liabilities, Commodity derivative contracts	(396)	0
Total	31,823	27,502
Cash and Cash Equivalents
Derivative Assets [Abstract]
Cash and cash equivalents	12,143	11,008
Cash and Cash Equivalents | Level 1
Derivative Assets [Abstract]
Cash and cash equivalents	12,143	11,008
Cash and Cash Equivalents | Level 2
Derivative Assets [Abstract]
Cash and cash equivalents	0	0
Cash and Cash Equivalents | Level 3
Derivative Assets [Abstract]
Cash and cash equivalents	$ 0	$ 0

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Property, Plant And Equipment

3 Months Ended

Mar. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant And Equipment

Property, Plant and Equipment

The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of West Virginia, Pennsylvania and Oklahoma.

The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:

	March 31, 2015		December 31, 2014
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	17,468	$	29,193
Acreage acquisition costs	94,079		91,362
Capitalized interest	8,794		7,719
Total unproved properties excluded from amortization	$	120,341	$	128,274

For the three months endedMarch 31, 2015, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $35,000 of unproved properties to proved properties for the three months endedMarch 31, 2015 related to acreage in Marcellus East.

The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company's capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:

	2015
	Total Impairment		March 31
Henry Hub natural gas price (per MMBtu)(1)			$	3.88
West Texas Intermediate oil price (per Bbl)(1)			$	82.72
Impairment recorded (pre-tax) (in thousands)	$	—	$	—

	2014
	Total Impairment		March 31
Henry Hub natural gas price (per MMBtu)(1)			$	3.99
West Texas Intermediate oil price (per Bbl)(1)			$	98.30
Impairment recorded (pre-tax) (in thousands)	$	—	$	—

 _________________________________

(1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Future declines in the 12-month average of oil, condensate, natural gas and NGLs prices could result in the recognition of future ceiling impairments.

Mid-Continent Divestiture

On May 1, 2015, the Company entered into a purchase and sale agreement with an undisclosed private third party to sell certain non-core assets comprised of 38 gross (16.7 net) wells producing approximately net 170 Boe/d (41% oil) for the three months ended March 31, 2015 and approximately 29,300 gross (19,000 net) acres in Kingfisher County, Oklahoma for approximately $46.2 million, subject to customary closing adjustments. The transaction is expected to close on or before June 22, 2015, with an effective date of April 1, 2015. The sale will be reflected as a reduction to the full cost pool and the Company does not anticipate recording a gain or loss related to the divestiture as it is not significant to the full cost pool.

Atinum Joint Venture

In September 2010, the Company entered into a joint venture (the “Atinum Joint Venture”) pursuant to which the Company ultimately assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum”), for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, the Company acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay the Company on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million.

The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, Atinum and the Company agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells. At March 31, 2015, 70 gross operated horizontal Marcellus Shale wells and one gross operated horizontal Utica Shale/Point Pleasant well were capable of production under the Atinum Joint Venture. The Atinum Joint Venture Agreement expires on November 1, 2015.

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Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) (Level 3, Commodity, Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 27,502		$ 3,764
Total gains (losses) included in earnings	10,223		(6,514)
Purchases	866		71
Issuances	(186)		0
Settlements	(6,582)	[1]	3,299	[1]
Balance at end of period	31,823		620
Gain (loss) on commodity derivatives contracts
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$ 4,252		$ (3,155)

[1] Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

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Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of restricted common stock granted	1,421,224
Shares of restricted common stock vested	1,274,872
Shares of restricted common stock surrendered upon vesting/exercise	382,238	[1]
Shares of restricted common stock forfeited	23,657

[1] Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 12,143	$ 11,008
Accounts receivable, net of allowance for doubtful accounts of $0, respectively	18,187	30,841
Commodity derivative contracts	18,815	19,687
Prepaid expenses	1,808	2,083
Total current assets	50,953	63,619
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	120,341	128,274
Proved properties	1,174,581	1,124,367
Total oil and natural gas properties	1,294,922	1,252,641
Furniture and equipment	3,013	3,010
Total property, plant and equipment	1,297,935	1,255,651
Accumulated depreciation, depletion and amortization	(577,822)	(563,351)
Total property, plant and equipment, net	720,113	692,300
OTHER ASSETS:
Commodity derivative contracts	13,404	7,815
Deferred charges, net	2,682	2,586
Advances to operators and other assets	2,770	9,474
Total other assets	18,856	19,875
TOTAL ASSETS	789,922	775,794
CURRENT LIABILITIES:
Accounts payable	19,780	28,843
Revenue payable	8,258	9,122
Accrued interest	10,550	3,528
Accrued drilling and operating costs	6,598	5,977
Advances from non-operators	1,025	1,820
Commodity derivative contracts	56	0
Commodity derivative premium payable	2,472	2,481
Asset retirement obligation	84	82
Other accrued liabilities	1,975	3,175
Total current liabilities	50,798	55,028
LONG-TERM LIABILITIES:
Long-term debt	380,916	360,303
Commodity derivative contracts	340	0
Commodity derivative premium payable	4,809	4,702
Asset retirement obligation	5,676	5,475
Total long-term liabilities	391,741	370,480
Commitments and contingencies (Note 11)
STOCKHOLDERS’ EQUITY:
Common stock	78	78
Additional paid-in capital	568,541	568,440
Accumulated deficit	(221,298)	(218,294)
Total stockholders’ equity	347,383	350,286
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	789,922	775,794
Series A Preferred Stock
STOCKHOLDERS’ EQUITY:
Preferred stock	41	41
Series B Preferred Stock
STOCKHOLDERS’ EQUITY:
Preferred stock	$ 21	$ 21

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Description Of Business

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of business

Description of Business

Gastar Exploration Inc. (the “Company” or “Gastar,” and before January 31, 2014, “Gastar USA”) is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Gastar’s principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expects to test other prospective formations on the same acreage, including the Woodford Shale and the Meramec Shale (middle Mississippi Lime), which Gastar refers to as the Stack Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled and completed its first successful dry gas Utica Shale/Point Pleasant well on its acreage.

On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” At December 31, 2013, Gastar Exploration, Inc. was a holding company and substantially all of its operations were conducted through, and substantially all of its assets were held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Subsequently, on January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc. as part of a reorganization to eliminate the holding company corporate structure. Pursuant to the merger agreement, shares of Gastar Exploration, Inc.'s common stock were converted into an equal number of shares of common stock of Gastar Exploration USA, Inc. and Gastar Exploration USA, Inc. changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc. owns and continues to conduct business in substantially the same manner as was being conducted by Gastar Exploration, Inc. and its subsidiaries prior to the merger. All references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration Inc. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) and its wholly-owned subsidiaries and all references to “Parent” refer solely to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.).

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Derivative Instruments and Hedging Activity Schedule of Unamortized Put Premium Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current commodity derivative premium put payable	$ 2,472	$ 2,481
Long-term commodity derivative premium payable	4,809	4,702
Total unamortized put premium liabilities	$ 7,281	$ 7,183

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Capital Stock (Tables)

3 Months Ended

Mar. 31, 2015

Stockholders' Equity Note [Abstract]

Schedule of Issuances And Forfeitures Of Common Shares

The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the period indicated:

	For the Three Months Ended March 31, 2015
Other share issuances:
Shares of restricted common stock granted	1,421,224
Shares of restricted common stock vested	1,274,872
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
Shares of restricted common stock surrendered upon vesting/exercise(1)	382,238
Shares of restricted common stock forfeited	23,657

 __________________

(1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

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Derivative Instruments and Hedging Activity (Schedule of Deferred Put Premium Liability) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Put Premium Liabilities [Roll Forward]
Put premium liabilities, beginning balance	$ 7,183
Amortization of put premium liabilities	(582)
Additional put premium liabilities	680
Put premium liabilities, ending balance	$ 7,281

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

	For the Three Months Ended March 31,
	2015			2014
	(in thousands, except per share and share data)
Net loss attributable to common stockholders	$	(3,004	)	$	(1,965	)
Weighted average common shares outstanding - basic	77,114,826			58,204,532
Incremental shares from unvested restricted shares	—			—
Incremental shares from outstanding stock options	—			—
Incremental shares from outstanding PBUs	—			—
Weighted average common shares outstanding - diluted	77,114,826			58,204,532
Net loss per share of common stock attributable to common stockholders:
Basic	$	(0.04	)	$	(0.03	)
Diluted	$	(0.04	)	$	(0.03	)
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares	450,556			119,496
Stock options	—			—
Unvested PBUs	373,325			—
Total	823,881			119,496

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Summary Of Significant Accounting Policies

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2014 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material item included in those notes has changed except as a result of normal transactions in the interim or as disclosed within this report.

The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows.

The unaudited interim condensed consolidated financial statements of the Company include the consolidated accounts of all of its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.

Certain reclassifications of prior year balances have been made to conform to the current year presentation; these reclassifications have no impact on net income (loss).

The results of operations for the three months endedMarch 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate.

Recent Accounting Developments

The following recently issued accounting pronouncement may impact the Company in future periods:

Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB's due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accounts receivable, net of allowance for doubtful accounts	$ 0	$ 0
Preferred stock, shares authorized	40,000,000	40,000,000
Preferred stock, par value	$ 0.01
Liquidation Preference	$ 25.00
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	80,145,775	78,632,810
Common stock, shares outstanding	80,145,775	78,632,810
Series A Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares issued	4,045,000	4,045,000
Preferred stock, shares outstanding	4,045,000	4,045,000
Liquidation Preference	$ 25.00	$ 25.00
Series B Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares issued	2,140,000	2,140,000
Preferred stock, shares outstanding	2,140,000	2,140,000
Liquidation Preference	$ 25.00	$ 25.00

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Statement Of Cash Flows - Supplemental Information

3 Months Ended

Mar. 31, 2015

Supplemental Cash Flow Information [Abstract]

Statement Of Cash Flows - Supplemental Information

Statement of Cash Flows – Supplemental Information

The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash paid for interest, net of capitalized amounts	$	(282	)	$	(697	)
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	$	(10,366	)	$	(299	)
Capital expenditures included in accounts receivable	—			4,077
Asset retirement obligation included in oil and natural gas properties	77			28
Application of advances to operators	8,457			9,490
Other	23			78

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Document And Entity Information	3 Months Ended
	Mar. 31, 2015	May 04, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Entity Registrant Name	Gastar Exploration Inc.
Entity Central Index Key	0001431372
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		81,145,775

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Summary Of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Basis of Accounting

The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.

Recent Accounting Developments

Recent Accounting Developments

The following recently issued accounting pronouncement may impact the Company in future periods:

Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB's due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

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Condensed Consolidated Statements Of Operations (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
REVENUES:
Oil and condensate	$ 15,353	$ 16,778
Natural gas	6,700	15,419
NGLs	2,096	6,644
Total oil, condensate, natural gas and NGLs revenues	24,149	38,841
Gain (loss) on commodity derivatives contracts	10,223	(6,514)
Total revenues	34,372	32,327
EXPENSES:
Production taxes	840	1,894
Lease operating expenses	6,019	4,044
Transportation, treating and gathering	497	625
Depreciation, depletion and amortization	14,471	12,382
Accretion of asset retirement obligation	125	122
General and administrative expense	4,248	4,763
Total expenses	26,200	23,830
INCOME FROM OPERATIONS	8,172	8,497
OTHER INCOME (EXPENSE):
Interest expense	(7,561)	(6,891)
Investment income and other	3	7
Foreign transaction loss	0	(2)
INCOME BEFORE PROVISION FOR INCOME TAXES	614	1,611
Provision for income taxes	0	0
NET INCOME	614	1,611
Dividends on preferred stock	(3,618)	(3,576)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (3,004)	$ (1,965)
NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic (in dollars per share)	$ (0.04)	$ (0.03)
Diluted (in dollars per share)	$ (0.04)	$ (0.03)
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic (shares)	77,114,826	58,204,532
Diluted (shares)	77,114,826	58,204,532

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Capital Stock

3 Months Ended

Mar. 31, 2015

Stockholders' Equity Note [Abstract]

Capital Stock

Capital Stock

Preferred Stock

The Company currently has 40,000,000 shares of preferred stock authorized for issuance under its certificate of incorporation. The Company has designated 10,000,000 shares to constitute its 8.625% Series A Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 shares to constitute its 10.75% Series B Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share.

Series A Preferred Stock

At March 31, 2015, there were 4,045,000 shares of the Series A Preferred Stock issued and outstanding.

The Series A Preferred Stock ranks senior to the Company's common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock.

The Series A Preferred Stock cannot be converted into common stock, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends.

There is no mandatory redemption of the Series A Preferred Stock.

The Company pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three months endedMarch 31, 2015, the Company recognized dividend expense of $2.2 million for the Series A Preferred Stock.

Series B Preferred Stock

At March 31, 2015, there were 2,140,000 shares of the Series B Cumulative Preferred Stock issued and outstanding.

The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with the Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock.

Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company will have the option to redeem the Series B Preferred Stock, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If the Company does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into up to an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption.

There is no mandatory redemption of the Series B Preferred Stock.

The Company pays cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the three months endedMarch 31, 2015, the Company recognized dividend expense of $1.4 million for the Series B Preferred Stock.

Other Share Issuances

The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the period indicated:

	For the Three Months Ended March 31, 2015
Other share issuances:
Shares of restricted common stock granted	1,421,224
Shares of restricted common stock vested	1,274,872
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
Shares of restricted common stock surrendered upon vesting/exercise(1)	382,238
Shares of restricted common stock forfeited	23,657

 __________________

(1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

On June 12, 2014, the Company's stockholders approved an amendment and restatement to the Gastar Exploration Inc. Long-Term Incentive Plan (the “LTIP”), effective April 24, 2014, to, among other things, increase the number of shares reserved for issuance under the LTIP by 3,000,000 shares. There were 2,849,434 shares available for issuance under the LTIP at March 31, 2015.

Shares Reserved

At March 31, 2015, the Company had 866,600 common shares reserved for the exercise of stock options.

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Derivative Instruments and Hedging Activity

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activity

Derivative Instruments and Hedging Activity

The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk.

All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the condensed consolidated statements of operations in gain (loss) on commodity derivatives contracts. For the three months ended March 31, 2015 and 2014, the Company reported a gain of $4.3 million and a loss of $3.2 million, respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts still held at March 31, 2015 and 2014.

As of March 31, 2015, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume(1)	Total of Notional Volume	Base Fixed Price		Floor (Long)		Short Put		Ceiling (Short)
		(in Bbls)
2015(2)	Costless collar	400	48,800	$	—	$	85.00	$	—	$	96.50
2015(2)	Costless collar	360	43,920	$	—	$	85.00	$	—	$	97.80
2015(2)	Costless collar	150	18,300	$	—	$	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	85,400	$	—	$	90.00	$	70.00	$	—
2015	Put spread	250	68,750	$	—	$	89.00	$	69.00	$	—
2015	Costless three-way collar	750	206,250	$	—	$	52.50	$	40.00	$	62.05
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	Costless three-way collar	450	164,700	$	—	$	57.50	$	42.50	$	80.00
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	Costless three-way collar	200	73,000	$	—	$	60.00	$	42.50	$	85.00
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 April to June 2015.

(3) For the period July to December 2015.

(4) For the period January to August 2018.

As of March 31, 2015, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price			Floor (Long)		Short Put		Call (Long)		Ceiling (Short)
		(in MMBtus)
2015	Fixed price swap	400	110,000	$	4.00		$	—	$	—	$	—	$	—
2015	Fixed price swap	2,500	687,500	$	4.06		$	—	$	—	$	—	$	—
2015	Protective spread	2,600	715,000	$	4.00		$	—	$	3.25	$	—	$	—
2015	Fixed price swap	5,000	1,375,000	$	3.49		$	—	$	—	$	—	$	—
2015	Fixed price swap	2,000	550,000	$	3.53		$	—	$	3.25	$	—	$	—
2015	Producer three-way collar	2,500	687,500	$	—		$	3.70	$	3.00	$	—	$	4.09
2015	Producer three-way collar	5,000	1,375,000	$	—		$	3.77	$	3.00	$	—	$	4.11
2015(1)	Producer three-way collar	2,000	428,000	$	—		$	3.00	$	2.25	$	—	$	3.34
2015(1)	Fixed price swap	10,000	2,140,000	$	2.94		$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.12	)	$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.11	)	$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.14	)	$	—	$	—	$	—	$	—
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
2016	Producer three-way collar	5,000	1,830,000	$	—		$	3.40	$	2.65	$	—	$	4.10
2016	Basis swap(3)	2,500	915,000	$	(1.10	)	$	—	$	—	$	—	$	—
2017	Short call	10,000	3,650,000	$	—		$	—	$	—	$	—	$	4.75

 _______________________________

(1) For the period April to October 2015.

(2) Represents basis swaps at the sales point of Dominion South.

(3) Represents basis swaps at the sales point of TetcoM2.

As of March 31, 2015, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price
		(in Bbls)
2015	Fixed price swap	250	68,750	$	45.61

As of March 31, 2015, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features.

In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period April 2015 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated:

	March 31, 2015		December 31, 2014
	(in thousands)
Current commodity derivative premium put payable	$	2,472	$	2,481
Long-term commodity derivative premium payable	4,809		4,702
Total unamortized put premium liabilities	$	7,281	$	7,183

	For the Three Months Ended March 31, 2015
	(in thousands)
Put premium liabilities, beginning balance	$	7,183
Amortization of put premium liabilities	(582		)
Additional put premium liabilities	680
Put premium liabilities, ending balance	$	7,281

The following table provides information regarding the amortization of the deferred put premium liabilities by year as of March 31, 2015:

	Amortization
	(in thousands)
April to December 2015	1,714
January to December 2016	3,050
January to December 2017	1,684
January to August 2018	833
Total unamortized put premium liabilities	$	7,281

Additional Disclosures about Derivative Instruments and Hedging Activities

The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:

	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
		Fair Value
	Balance Sheet Location	March 31, 2015			December 31, 2014
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	18,815		$	19,687
Commodity derivative contracts	Other assets	13,404			7,815
Commodity derivative contracts	Current liabilities	(56		)	—
Commodity derivative contracts	Long-term liabilities	(340		)	—
Total derivatives not designated as hedging instruments		$	31,823		$	27,502

		Amount of Gain (Loss) Recognized in Income on Derivatives For the Three Months Ended March 31,
	Location of Gain (Loss) Recognized in Income on Derivatives	2015		2014
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Gain (loss) on commodity derivatives contracts	$	10,223	$	(6,514	)
Total		$	10,223	$	(6,514	)

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Interest Expense (Tables)

3 Months Ended

Mar. 31, 2015

Interest Expense [Abstract]

Schedule Of Components Of Interest Expense

The following table summarizes the components of interest expense for the periods indicated:

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Interest expense:
Cash and accrued	$	7,928		$	7,134
Amortization of deferred financing costs(1)	822			733
Capitalized interest	(1,189		)	(976		)
Total interest expense	$	7,561		$	6,891

 _________________________________

(1) The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

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Property, Plant And Equipment (Tables)

3 Months Ended

Mar. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization

The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:

	March 31, 2015		December 31, 2014
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	17,468	$	29,193
Acreage acquisition costs	94,079		91,362
Capitalized interest	8,794		7,719
Total unproved properties excluded from amortization	$	120,341	$	128,274

Schedule Of Relevant Assumptions Used In Ceiling Test Computations

The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:

	2015
	Total Impairment		March 31
Henry Hub natural gas price (per MMBtu)(1)			$	3.88
West Texas Intermediate oil price (per Bbl)(1)			$	82.72
Impairment recorded (pre-tax) (in thousands)	$	—	$	—

	2014
	Total Impairment		March 31
Henry Hub natural gas price (per MMBtu)(1)			$	3.99
West Texas Intermediate oil price (per Bbl)(1)			$	98.30
Impairment recorded (pre-tax) (in thousands)	$	—	$	—

 _________________________________

(1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

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Earnings Per Share

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Earnings per Share

In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.

	For the Three Months Ended March 31,
	2015			2014
	(in thousands, except per share and share data)
Net loss attributable to common stockholders	$	(3,004	)	$	(1,965	)
Weighted average common shares outstanding - basic	77,114,826			58,204,532
Incremental shares from unvested restricted shares	—			—
Incremental shares from outstanding stock options	—			—
Incremental shares from outstanding PBUs	—			—
Weighted average common shares outstanding - diluted	77,114,826			58,204,532
Net loss per share of common stock attributable to common stockholders:
Basic	$	(0.04	)	$	(0.03	)
Diluted	$	(0.04	)	$	(0.03	)
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares	450,556			119,496
Stock options	—			—
Unvested PBUs	373,325			—
Total	823,881			119,496

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Interest Expense

3 Months Ended

Mar. 31, 2015

Interest Expense [Abstract]

Interest Expense

Interest Expense

The following table summarizes the components of interest expense for the periods indicated:

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Interest expense:
Cash and accrued	$	7,928		$	7,134
Amortization of deferred financing costs(1)	822			733
Capitalized interest	(1,189		)	(976		)
Total interest expense	$	7,561		$	6,891

 _________________________________

(1) The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

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Income Taxes

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

For the three months endedMarch 31, 2015 and 2014, respectively, the Company did not recognize a current income tax benefit or provision as the Company has a full valuation allowance against assets created by net operating losses generated. The Company believes it more likely than not that the assets will not be utilized.

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

Commitments and Contingencies

Litigation

Gastar Exploration Ltd vs. U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No.2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage is $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Fourteenth Court of Appeals, which that court denied. The insurers then sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The insurers recently filed in the Texas Supreme Court a motion for rehearing of their denied petition for review, which the court has not ruled on. If the court denies the motion, the case will be remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements.

The Company has been expensing legal costs on these proceedings as they are incurred.

The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

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Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	3 Months Ended
	Mar. 31, 2015 bbl
Costless collar | Crude Oil | Costless Collar 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	48,800	[2]
Floor (Long) (Price per MMBtu)	85.00	[2]
Ceiling (Short) (Price per MMBtu)	96.50	[2]
Costless collar | Crude Oil | Costless Collar 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	360	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	43,920	[2]
Floor (Long) (Price per MMBtu)	85.00	[2]
Ceiling (Short) (Price per MMBtu)	97.80	[2]
Costless collar | Crude Oil | Costless Collar 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	150	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	18,300	[2]
Floor (Long) (Price per MMBtu)	85.00	[2]
Ceiling (Short) (Price per MMBtu)	96.25	[2]
Costless three-way collar | Crude Oil | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400	[1],[3]
Total of Notional Volume (MMBtu's or Bbls)	73,600	[3]
Floor (Long) (Price per MMBtu)	85.00	[3]
Short Put (Price per MMBtu)	70.00	[3]
Ceiling (Short) (Price per MMBtu)	96.50	[3]
Costless three-way collar | Crude Oil | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	275	[1]
Total of Notional Volume (MMBtu's or Bbls)	100,600
Floor (Long) (Price per MMBtu)	85.00
Short Put (Price per MMBtu)	65.00
Ceiling (Short) (Price per MMBtu)	95.10
Costless three-way collar | Crude Oil | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	280	[1]
Total of Notional Volume (MMBtu's or Bbls)	102,200
Floor (Long) (Price per MMBtu)	80.00
Short Put (Price per MMBtu)	65.00
Ceiling (Short) (Price per MMBtu)	97.25
Costless three-way collar | Crude Oil | Costless Three Way Collar 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	325	[1],[3]
Total of Notional Volume (MMBtu's or Bbls)	59,800	[3]
Floor (Long) (Price per MMBtu)	85.00	[3]
Short Put (Price per MMBtu)	65.00	[3]
Ceiling (Short) (Price per MMBtu)	97.80	[3]
Costless three-way collar | Crude Oil | Costless Three Way Collar 2 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	330	[1]
Total of Notional Volume (MMBtu's or Bbls)	120,780
Floor (Long) (Price per MMBtu)	80.00
Short Put (Price per MMBtu)	65.00
Ceiling (Short) (Price per MMBtu)	97.35
Costless three-way collar | Crude Oil | Costless Three Way Collar 2 | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	242	[1]
Total of Notional Volume (MMBtu's or Bbls)	88,150
Floor (Long) (Price per MMBtu)	80.00
Short Put (Price per MMBtu)	60.00
Ceiling (Short) (Price per MMBtu)	98.70
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	50	[1],[3]
Total of Notional Volume (MMBtu's or Bbls)	9,200	[3]
Floor (Long) (Price per MMBtu)	85.00	[3]
Short Put (Price per MMBtu)	65.00	[3]
Ceiling (Short) (Price per MMBtu)	96.25	[3]
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 3 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	450	[1]
Total of Notional Volume (MMBtu's or Bbls)	164,700
Floor (Long) (Price per MMBtu)	57.50
Short Put (Price per MMBtu)	42.50
Ceiling (Short) (Price per MMBtu)	80.00
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 3 | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	200	[1]
Total of Notional Volume (MMBtu's or Bbls)	73,000
Floor (Long) (Price per MMBtu)	60
Short Put (Price per MMBtu)	42.50
Ceiling (Short) (Price per MMBtu)	85.00
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 4 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	750	[1]
Total of Notional Volume (MMBtu's or Bbls)	206,250
Floor (Long) (Price per MMBtu)	52.50
Short Put (Price per MMBtu)	40.00
Ceiling (Short) (Price per MMBtu)	62.05
Put spread | Crude Oil | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	500	[1]
Total of Notional Volume (MMBtu's or Bbls)	182,500
Floor (Long) (Price per MMBtu)	82.00
Short Put (Price per MMBtu)	62.00
Put spread | Crude Oil | 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	425	[1],[4]
Total of Notional Volume (MMBtu's or Bbls)	103,275	[4]
Floor (Long) (Price per MMBtu)	80.00	[4]
Short Put (Price per MMBtu)	60.00	[4]
Put spread | Crude Oil | Put Spread 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	700	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	85,400	[2]
Floor (Long) (Price per MMBtu)	90.00	[2]
Short Put (Price per MMBtu)	70.00	[2]
Put spread | Crude Oil | Put Spread 1 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	550	[1]
Total of Notional Volume (MMBtu's or Bbls)	201,300
Floor (Long) (Price per MMBtu)	85.00
Short Put (Price per MMBtu)	65.00
Put spread | Crude Oil | Put Spread 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	250	[1]
Total of Notional Volume (MMBtu's or Bbls)	68,750
Floor (Long) (Price per MMBtu)	89.00
Short Put (Price per MMBtu)	69.00
Put spread | Crude Oil | Put Spread 2 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	300	[1]
Total of Notional Volume (MMBtu's or Bbls)	109,800
Floor (Long) (Price per MMBtu)	85.50
Short Put (Price per MMBtu)	65.50
Put spread | Crude Oil | Put Spread 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	600	[1],[3]
Total of Notional Volume (MMBtu's or Bbls)	110,400	[3]
Floor (Long) (Price per MMBtu)	87.00	[3]
Short Put (Price per MMBtu)	67.00	[3]
Fixed price swap | Natural Gas | Fixed Price Swap 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400
Total of Notional Volume (MMBtu's or Bbls)	110,000
Base Fixed Price (Price per MMBtu or Bbl)	4.00
Fixed price swap | Natural Gas | Fixed Price Swap 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	687,500
Base Fixed Price (Price per MMBtu or Bbl)	4.06
Fixed price swap | Natural Gas | Fixed Price Swap 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,375,000
Base Fixed Price (Price per MMBtu or Bbl)	3.49
Fixed price swap | Natural Gas | Fixed Price Swap 4 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	550,000
Base Fixed Price (Price per MMBtu or Bbl)	3.53
Short Put (Price per MMBtu)	3.25
Fixed price swap | Natural Gas | Fixed Price Swap 5 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000	[5]
Total of Notional Volume (MMBtu's or Bbls)	2,140,000	[5]
Base Fixed Price (Price per MMBtu or Bbl)	2.94	[5]
Fixed price swap | Natural Gas Liquids | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	250
Total of Notional Volume (MMBtu's or Bbls)	68,750
Base Fixed Price (Price per MMBtu or Bbl)	45.61
Protective spread | Natural Gas | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,600
Total of Notional Volume (MMBtu's or Bbls)	715,000
Base Fixed Price (Price per MMBtu or Bbl)	4.00
Short Put (Price per MMBtu)	3.25
Protective spread | Natural Gas | Protective Spread 3 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Base Fixed Price (Price per MMBtu or Bbl)	4.11
Short Put (Price per MMBtu)	3.25
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	687,500
Floor (Long) (Price per MMBtu)	3.70
Short Put (Price per MMBtu)	3.00
Ceiling (Short) (Price per MMBtu)	4.09
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,375,000
Floor (Long) (Price per MMBtu)	3.77
Short Put (Price per MMBtu)	3.00
Ceiling (Short) (Price per MMBtu)	4.11
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000	[5]
Total of Notional Volume (MMBtu's or Bbls)	428,000	[5]
Floor (Long) (Price per MMBtu)	3.00	[5]
Short Put (Price per MMBtu)	2.25	[5]
Ceiling (Short) (Price per MMBtu)	3.34	[5]
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 4 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Floor (Long) (Price per MMBtu)	4.00
Short Put (Price per MMBtu)	3.25
Ceiling (Short) (Price per MMBtu)	4.58
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 5 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,830,000
Floor (Long) (Price per MMBtu)	3.40
Short Put (Price per MMBtu)	2.65
Ceiling (Short) (Price per MMBtu)	4.10
Basis Swap | Natural Gas | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[6]
Total of Notional Volume (MMBtu's or Bbls)	915,000	[6]
Base Fixed Price (Price per MMBtu or Bbl)	(1.10)	[6]
Basis Swap | Natural Gas | Basis Swap 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[7]
Base Fixed Price (Price per MMBtu or Bbl)	(1.12)	[7]
Basis Swap | Natural Gas | Basis Swap 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[7]
Base Fixed Price (Price per MMBtu or Bbl)	(1.11)	[7]
Basis Swap | Natural Gas | Basis Points 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[7]
Base Fixed Price (Price per MMBtu or Bbl)	(1.14)	[7]
Short call | Natural Gas | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000
Total of Notional Volume (MMBtu's or Bbls)	3,650,000
Ceiling (Short) (Price per MMBtu)	4.75

[1] Crude volumes hedged include oil, condensate and certain components of our NGLs production.

[2] For the period April to June 2015.

[3] For the period July to December 2015.

[4] For the period January to August 2018.

[5] For the period April to October 2015.

[6] Represents basis swaps at the sales point of TetcoM2.

[7] Represents basis swaps at the sales point of Dominion South.

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Derivative Instruments and Hedging Activity (Tables)

3 Months Ended

Mar. 31, 2015

Derivative [Line Items]

Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location

The following table provides information regarding the deferred put premium liabilities for the periods indicated:

	March 31, 2015		December 31, 2014
	(in thousands)
Current commodity derivative premium put payable	$	2,472	$	2,481
Long-term commodity derivative premium payable	4,809		4,702
Total unamortized put premium liabilities	$	7,281	$	7,183

Schedule of Future Amortization of Deferred Put Premium Liabilities

The following table provides information regarding the amortization of the deferred put premium liabilities by year as of March 31, 2015:

	Amortization
	(in thousands)
April to December 2015	1,714
January to December 2016	3,050
January to December 2017	1,684
January to August 2018	833
Total unamortized put premium liabilities	$	7,281

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:

	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
		Fair Value
	Balance Sheet Location	March 31, 2015			December 31, 2014
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	18,815		$	19,687
Commodity derivative contracts	Other assets	13,404			7,815
Commodity derivative contracts	Current liabilities	(56		)	—
Commodity derivative contracts	Long-term liabilities	(340		)	—
Total derivatives not designated as hedging instruments		$	31,823		$	27,502

		Amount of Gain (Loss) Recognized in Income on Derivatives For the Three Months Ended March 31,
	Location of Gain (Loss) Recognized in Income on Derivatives	2015		2014
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Gain (loss) on commodity derivatives contracts	$	10,223	$	(6,514	)
Total		$	10,223	$	(6,514	)

Crude Oil

Derivative [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of March 31, 2015, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume(1)	Total of Notional Volume	Base Fixed Price		Floor (Long)		Short Put		Ceiling (Short)
		(in Bbls)
2015(2)	Costless collar	400	48,800	$	—	$	85.00	$	—	$	96.50
2015(2)	Costless collar	360	43,920	$	—	$	85.00	$	—	$	97.80
2015(2)	Costless collar	150	18,300	$	—	$	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	85,400	$	—	$	90.00	$	70.00	$	—
2015	Put spread	250	68,750	$	—	$	89.00	$	69.00	$	—
2015	Costless three-way collar	750	206,250	$	—	$	52.50	$	40.00	$	62.05
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	Costless three-way collar	450	164,700	$	—	$	57.50	$	42.50	$	80.00
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	Costless three-way collar	200	73,000	$	—	$	60.00	$	42.50	$	85.00
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 April to June 2015.

(3) For the period July to December 2015.

(4) For the period January to August 2018.

Natural Gas

Derivative [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of March 31, 2015, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price			Floor (Long)		Short Put		Call (Long)		Ceiling (Short)
		(in MMBtus)
2015	Fixed price swap	400	110,000	$	4.00		$	—	$	—	$	—	$	—
2015	Fixed price swap	2,500	687,500	$	4.06		$	—	$	—	$	—	$	—
2015	Protective spread	2,600	715,000	$	4.00		$	—	$	3.25	$	—	$	—
2015	Fixed price swap	5,000	1,375,000	$	3.49		$	—	$	—	$	—	$	—
2015	Fixed price swap	2,000	550,000	$	3.53		$	—	$	3.25	$	—	$	—
2015	Producer three-way collar	2,500	687,500	$	—		$	3.70	$	3.00	$	—	$	4.09
2015	Producer three-way collar	5,000	1,375,000	$	—		$	3.77	$	3.00	$	—	$	4.11
2015(1)	Producer three-way collar	2,000	428,000	$	—		$	3.00	$	2.25	$	—	$	3.34
2015(1)	Fixed price swap	10,000	2,140,000	$	2.94		$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.12	)	$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.11	)	$	—	$	—	$	—	$	—
2015	Basis swap(2)	2,500	687,500	$	(1.14	)	$	—	$	—	$	—	$	—
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
2016	Producer three-way collar	5,000	1,830,000	$	—		$	3.40	$	2.65	$	—	$	4.10
2016	Basis swap(3)	2,500	915,000	$	(1.10	)	$	—	$	—	$	—	$	—
2017	Short call	10,000	3,650,000	$	—		$	—	$	—	$	—	$	4.75

 _______________________________

(1) For the period April to October 2015.

(2) Represents basis swaps at the sales point of Dominion South.

(3) Represents basis swaps at the sales point of TetcoM2.

Natural Gas Liquids

Derivative [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of March 31, 2015, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price
		(in Bbls)
2015	Fixed price swap	250	68,750	$	45.61

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Property, Plant And Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Unproved properties, excluded from amortization:
Drilling in progress costs	$ 17,468	$ 29,193
Acreage acquisition costs	94,079	91,362
Capitalized interest	8,794	7,719
Total unproved properties excluded from amortization	$ 120,341	$ 128,274

XML

Interest Expense (Schedule of Components of Interest Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Interest Expense [Abstract]
Cash and accrued	$ 7,928		$ 7,134
Amortization of deferred financing costs	822	[1]	733	[1]
Capitalized interest	(1,189)		(976)
Total interest expense	7,561		6,891
Accretion of debt discount	$ 613		$ 556

[1] The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

XML

Condensed Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 614		$ 1,611
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	14,471		12,382
Stock-based compensation	1,526		1,533
Total (gain) loss on commodity derivatives contracts	(10,223)		6,514
Cash settlements of matured commodity derivatives contracts, net	5,277		(3,015)
Cash premiums paid for commodity derivatives contracts	0		(71)
Amortization of deferred financing costs	822	[1]	733	[1]
Accretion of asset retirement obligation	125		122
Settlement of asset retirement obligation	0		(257)
Changes in operating assets and liabilities:
Accounts receivable	14,279		(750)
Prepaid expenses	275		81
Accounts payable and accrued liabilities	5,957		4,169
Net cash provided by operating activities	33,123		23,052
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties	(46,121)		(25,812)
Advances to operators	(1,753)		(5,001)
Acquisition of oil and natural gas properties - refund	0		4,209
Proceeds from (payment related to) sale of oil and natural gas properties	2,008		(341)
(Payments to) proceeds from non-operators	(795)		4,930
Purchase of furniture and equipment	(3)		(148)
Net cash used in investing activities	(46,664)		(22,163)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	25,000		0
Repayment of revolving credit facility	(5,000)		0
Proceeds from issuance of preferred stock, net of issuance costs	0		886
Dividends on preferred stock	(3,618)		(3,576)
Deferred financing charges	(281)		(135)
Tax withholding related to restricted stock and PBU vestings	(1,425)		(3,544)
Net cash provided by (used in) financing activities	14,676		(6,369)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,135		(5,480)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	11,008		32,393
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 12,143		$ 26,913

[1] The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties or estimated market data based on area transactions, which are Level 3 inputs. For the three months endedMarch 31, 2015, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $35,000 of unproved properties to proved properties for the three months endedMarch 31, 2015 related to acreage in Marcellus East. For the three months endedMarch 31, 2014, management's evaluation of unproved properties resulted in an impairment of $194,000 related to Marcellus East. As no other fair value measurements are required to be recognized on a non-recurring basis at March 31, 2015, no additional disclosures are provided at March 31, 2015.

As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

• Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:

	Fair value as of March 31, 2015
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	12,143	$	—	$	—		$	12,143
Commodity derivative contracts	—		—		32,219			32,219
Liabilities:
Commodity derivative contracts	—		—		(396		)	(396		)
Total	$	12,143	$	—	$	31,823		$	43,966
	Fair value as of December 31, 2014
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	11,008	$	—	$	—		$	11,008
Commodity derivative contracts	—		—		27,502			27,502
Liabilities:
Commodity derivative contracts	—		—		—			—
Total	$	11,008	$	—	$	27,502		$	38,510

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at March 31, 2015 and 2014.

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Balance at beginning of period	$	27,502		$	3,764
Total gains (losses) included in earnings	10,223			(6,514		)
Purchases	866			71
Issuances	(186		)	—
Settlements(1)	(6,582		)	3,299
Balance at end of period	$	31,823		$	620
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$	4,252		$	(3,155	)

 _________________________________

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

At March 31, 2015, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at March 31, 2015 was $371.7 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximates the current market rate (Level 2).

The Company has consistently applied the valuation techniques discussed above in all periods presented.

The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivative Instruments and Hedging Activity.”

XML

Property, Plant And Equipment (Narrative) (Details) (USD $)	3 Months Ended	1 Months Ended	0 Months Ended
	Mar. 31, 2015	Sep. 30, 2010	May 01, 2015 Boe well acre
Property, Plant and Equipment [Line Items]
Amount reclassified from unproved to proved properties	$ 35,000
Gastar Exploration USA | Atinum Joint Venture
Property, Plant and Equipment [Line Items]
Adjusted purchase price		70,000,000
Working interest in wells (percentage)		50.00%
Percentage of reimbursements for lease bonuses and third party lease costs up to 20 million (percentage)	10.00%
Percentage of lease operating expenses covered (percentage)	5.00%
Term of development program	3 years
Gastar Exploration USA | Atinum Joint Venture | Marcellus Shale
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells)	70
Gastar Exploration USA | Atinum Joint Venture | Utica Shale
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells)	1
Gastar Exploration USA | Atinum Joint Venture | Maximum
Property, Plant and Equipment [Line Items]
Total wells to be drilled (wells)	60
Required exploratory wells drilled net productive to be drilled in current fiscal year (wells)	51
Subsequent Event | Mid Continent Divestiture
Property, Plant and Equipment [Line Items]
Gross wells			38
Net wells			16.7
Production of wells (Boe/d)			170
Percentage oil			41.00%
Gross acres (acres)			29,300
Net acres (acres)			19,000
Total consideration			$ 46,200,000

XML

Derivative Instruments and Hedging Activity (Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location) (Details) (Derivatives not designated as hedging instruments, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Total derivatives not designated as hedging instruments	$ 31,823		$ 27,502
Gain (loss) on commodity derivatives contracts	10,223	(6,514)
Gain (loss) on commodity derivatives contracts
Derivatives, Fair Value [Line Items]
Gain (loss) on commodity derivatives contracts	10,223	(6,514)
Current assets
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	18,815		19,687
Other assets
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	13,404		7,815
Current liabilities
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	(56)		0
Long-term liabilities
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	$ (340)		$ 0

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring and Nonrecurring

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:

	Fair value as of March 31, 2015
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	12,143	$	—	$	—		$	12,143
Commodity derivative contracts	—		—		32,219			32,219
Liabilities:
Commodity derivative contracts	—		—		(396		)	(396		)
Total	$	12,143	$	—	$	31,823		$	43,966
	Fair value as of December 31, 2014
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	11,008	$	—	$	—		$	11,008
Commodity derivative contracts	—		—		27,502			27,502
Liabilities:
Commodity derivative contracts	—		—		—			—
Total	$	11,008	$	—	$	27,502		$	38,510

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at March 31, 2015 and 2014.

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Balance at beginning of period	$	27,502		$	3,764
Total gains (losses) included in earnings	10,223			(6,514		)
Purchases	866			71
Issuances	(186		)	—
Settlements(1)	(6,582		)	3,299
Balance at end of period	$	31,823		$	620
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$	4,252		$	(3,155	)

 _________________________________

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