Edgar Filing: GASTAR EXPLORATION LTD

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Form 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 JUNE 30, 2010 OR

¨	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: 001-32714

GASTAR EXPLORATION LTD.

(Exact name of registrant as specified in its charter)


Alberta, Canada		98-0570897
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1331 Lamar Street, Suite 1080 Houston, Texas 77010		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 x No ¨

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 ¨ No ¨

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. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Total number of outstanding common shares, no par value per share, as of August 3, 2010 was 50,375,724.

GASTAR EXPLORATION LTD.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010

TABLE OF CONTENTS


		Page
	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	2
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	3
	Notes to the Condensed Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	(Removed and Reserved)	34
Item 5.	Other Information	35
Item 6.	Exhibits	35
SIGNATURES		36

Unless otherwise indicated or required by the context, (i) “Gastar,” the “Company,” “we,” “us,” and “our” refer to Gastar Exploration Ltd. and its subsidiaries and predecessors, (ii) all dollar amounts appearing in this report on Form 10-Q are stated in United States dollars (“US dollars”) or Australian dollars (“AU$”) and (iii) all financial data included in this report have been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”).

General information about us can be found on our website at www.gastar.com. The information on our website is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, 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 United States Securities and Exchange Commission (“SEC”). Information is also available on the SEC website at www.sec.gov for our United States filings and on SEDAR at www.sedar.com for our Canadian filings.

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2010			December 31, 2009
	(Unaudited)
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,822		$	21,866
Term deposit		—			69,662
Accounts receivable, net of allowance for doubtful accounts of $587 and $609, respectively		4,484			5,336
Receivable from unproved property sale		—			19,412
Receivables from commodity derivative contracts		7,793			4,870
Prepaid expenses		437			669

Total current assets		19,536			121,815


PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization		147,853			132,720
Proved properties		325,739			313,100

Total natural gas and oil properties		473,592			445,820
Furniture and equipment		1,009			867

Total property, plant and equipment		474,601			446,687
Accumulated depreciation, depletion and amortization		(287,421	)		(284,026	)

Total property, plant and equipment, net		187,180			162,661

OTHER ASSETS:
Restricted cash		50			50
Receivables from commodity derivative contracts		11,173			10,698
Deferred charges, net		607			764
Drilling advances and other assets		100			250

Total other assets		11,930			11,762


TOTAL ASSETS	$	218,646		$	296,238


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	6,700		$	8,291
Revenue payable		3,871			4,621
Accrued interest		66			130
Accrued drilling and operating costs		3,767			736
Liabilities from commodity derivative contracts		2,392			3,678
Commodity derivative premium payable		2,632			1,190
Short-term loan		—			17,000
Accrued taxes payable		175			75,887
Other accrued liabilities		1,502			1,438

Total current liabilities		21,105			112,971


LONG-TERM LIABILITIES:
Long-term debt		8,000			—
Liabilities from commodity derivative contracts		3,340			4,047
Commodity derivative premium payable		6,734			8,176
Asset retirement obligation		6,189			5,943
Warrant derivative		2			205

Total long-term liabilities		24,265			18,371


Commitments and contingencies (Note 13)

SHAREHOLDERS’ EQUITY:
Preferred stock, no par value; unlimited shares authorized; no shares issued		—			—
Common stock, no par value; unlimited shares authorized; 50,393,938 and 50,028,592 shares issued and outstanding at June 30, 2010 and December 31, 2009, respectively		263,809			263,809
Additional paid-in capital		22,267			20,782
Accumulated deficit		(112,800	)		(119,695	)

Total shareholders’ equity		173,276			164,896


TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	218,646		$	296,238

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

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands, except share and per share data)
REVENUES:
Natural gas and oil revenues	$	6,737		$	11,962		$	13,495		$	25,423
Unrealized natural gas hedge gain (loss)		(972	)		(4,426	)		8,406			(4,622	)

Total revenues		5,765			7,536			21,901			20,801

EXPENSES:
Production taxes		93			92			216			249
Lease operating expenses		1,914			1,449			3,657			3,326
Transportation, treating and gathering		1,094			325			2,343			818
Depreciation, depletion and amortization		1,664			3,361			3,395			11,360
Impairment of natural gas and oil properties		—			—			—			68,729
Accretion of asset retirement obligation		96			88			191			175
General and administrative expense		3,944			3,487			7,776			6,445

Total expenses		8,805			8,802			17,578			91,102


INCOME (LOSS) FROM OPERATIONS		(3,040	)		(1,266	)		4,323			(70,301	)

OTHER INCOME (EXPENSE):
Interest expense		(20	)		(1,137	)		(98	)		(2,299	)
Investment income and other		548			10			1,340			23
Warrant derivative gain		55			—			203			—
Foreign transaction gain (loss)		16			—			335			(3	)


INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES		(2,441	)		(2,393	)		6,103			(72,580	)

Provision for income tax expense (benefit)		57			—			(792	)		—


NET INCOME (LOSS)	$	(2,498	)	$	(2,393	)	$	6,895		$	(72,580	)


NET INCOME (LOSS) PER SHARE:
Basic	$	(0.05	)	$	(0.05	)	$	0.14		$	(1.68	)

Diluted	$	(0.05	)	$	(0.05	)	$	0.14		$	(1.68	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		49,042,874			44,854,954			49,020,072			43,163,088
Diluted		49,042,874			44,854,954			49,529,357			43,163,088

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

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six Months Ended June 30,
	2010			2009
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	6,895		$	(72,580	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		3,395			11,360
Impairment of natural gas and oil properties		—			68,729
Stock-based compensation		1,639			2,134
Unrealized natural gas hedge (gain) loss		(8,406	)		4,622
Realized loss (gain) on derivative contracts		1,763			(2,109	)
Amortization of deferred financing costs and debt discount		157			1,408
Accretion of asset retirement obligation		191			175
Warrant derivative gain		(203	)		—
Changes in operating assets and liabilities:
Accounts receivable		1,615			3,474
Commodity derivative contracts		1,252			2,889
Prepaid expenses		232			368
Accrued taxes payable		(1,245	)		—
Accounts payable and accrued liabilities		(2,837	)		(5,068	)

Net cash provided by operating activities		4,448			15,402


CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties		(24,591	)		(33,029	)
Drilling advances		—			(4,791	)
Proceeds from sale of natural gas and oil properties		19,199			—
Purchase of furniture and equipment		(142	)		(13	)
Purchase of term deposit		(4,855	)		—

Net cash used in investing activities		(10,389	)		(37,833	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares		—			13,819
Repayment of revolving credit facility		—			(4,975	)
Repayment of subordinated unsecured notes		—			(2,950	)
Repayment of short-term loan		(17,000	)		—
Proceeds from term loan		—			25,000
Proceeds from revolving credit facility		8,000			—
Increase in restricted cash		—			(463	)
Deferred financing charges		—			(1,430	)
Other		(103	)		(224	)

Net cash (used in) provided by financing activities		(9,103	)		28,777


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(15,044	)		6,346
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		21,866			6,153

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	6,822		$	12,499

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

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

Gastar Exploration Ltd. (“Gastar”, the “Company” or “Parent”) is an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States. The Company’s principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as shale resource plays. The Company currently is pursuing natural gas exploration in the deep Bossier gas play in the Hilltop area of East Texas and the Marcellus Shale play in the Appalachian area of West Virginia and central and southwestern Pennsylvania. The Company also conducts coal bed methane (“CBM”) development activities within the Powder River Basin of Wyoming and Montana.

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company and its subsidiaries 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, 2009 (“2009 Form 10-K”) filed with the SEC. Please refer to the notes to the financial statements included in the Company’s 2009 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. All material items included in those notes have not 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 US dollars unless otherwise noted and were prepared from the records of the Company by management in accordance with US 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 Company’s 2009 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 Company’s 2009 Form 10-K. The year-end condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by US GAAP.

The preparation of financial statements in conformity with US 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 natural gas and oil reserve quantities and the related present value of estimated future net cash flows.

The condensed consolidated financial statements include the accounts of the Company and the consolidated accounts of all of its subsidiaries. The entities included in these consolidated accounts are wholly owned by the Company. All significant intercompany accounts and transactions have been eliminated in consolidation.

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

The results of operations for the three and six months ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 pronouncements have been adopted or may impact the Company in future periods:

Stock Compensation – Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. In April 2010, the Financial Accounting Standards Board (“FASB”)’s Emerging Issues Task Force (“EITF”) issued an amendment to previously issued guidance regarding the classification of a share-based payment award as either equity or a liability. The amendments clarify that a share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance or service condition. Therefore, such an award should not be classified as a liability if it otherwise qualifies as equity. This guidance is effective for fiscal years and interim periods within those fiscal years beginning on or after December 15, 2010. Earlier application is permitted. This guidance should be applied by recording a cumulative-effect adjustment to the opening balance of retained earnings and the cumulative-effect adjustment should be calculated for all awards outstanding as of the beginning of the fiscal year in which it is initially applied, as if the guidance had been applied consistently since the inception of the award. The cumulative-effect adjustment should be presented separately. The adoption of this guidance did not impact the Company’s operating results, financial position and cash flows.

Derivatives and Hedging. In March 2010, the FASB issued an amendment to previously issued guidance regarding embedded credit derivatives. This amendment provides clarification of the scope exception for embedded credit derivatives that transfer credit risk only in the form of subordination of one financial instrument to another. All entities that enter into contracts containing an embedded credit derivative feature related to the transfer of credit risk that is not only in the form of subordination of one financial instrument to another will be affected by the amendment because the amendment clarifies that the embedded credit derivative scope exception per the guidance does not apply to such contracts. This amended guidance is effective at the beginning of the first fiscal quarter beginning after June 15, 2010. Early adoption is permitted at the beginning of the first fiscal quarter beginning after the issuance of this amendment. The Company is currently evaluating the impact of this guidance on its operating results, financial position and cash flows.

Fair Value Measurements. In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance was adopted on January 1, 2010 for Level 1 and Level 2 fair value measurements and did not impact the Company’s operating results, financial position or cash flows but did require additional disclosures regarding the fair value of financial instruments. See Part I, Item 1. “Financial Statements, Note 6 – Fair Value Measurements.”

Variable Interest Entities. In June 2009, the FASB issued authoritative guidance related to variable interest entities which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting rights should be consolidated and modifies the approach for determining the primary beneficiary of a variable interest entity. This guidance requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. The guidance related to variable interest entities was effective on January 1, 2010 and did not have an impact on the Company’s operating results, financial position or cash flows.

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Subsequent Events. In May 2009, the FASB issued authoritative guidance on subsequent events to incorporate accounting guidance that originated as auditing standards into the body of authoritative literature issued by the FASB. This guidance required the evaluation of subsequent events through the date the financial statements are issued or are available for issue and the disclosure of the date through which subsequent events were evaluated and the basis for that date. This guidance was effective for interim and annual financial periods ending after June 15, 2009. The Company adopted the requirements of this guidance for the period ended June 30, 2009 and the adoption did not have an impact on the Company’s operating results, financial position or cash flows. On February 25, 2010, the FASB amended this guidance to remove the requirement to disclose the date through which an entity has evaluated subsequent events.

Modernization of Natural Gas and Oil Reporting. In January 2009, the SEC issued revisions to the natural gas and oil reporting disclosures, “Modernization of Oil and Gas Reporting, Final Rule” (the “Final Rule”). In addition to changing the definition and disclosure requirements for natural gas and oil reserves, the Final Rule changed the requirements for determining quantities of natural gas and oil reserves. The Final Rule also changed certain accounting requirements under the full cost method of accounting for natural gas and oil activities. The amendments are designed to modernize the requirements for the determination of natural gas and oil reserves, aligning them with current practices and updating them for changes in technology. The Final Rule was effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. In addition, in January 2010, the FASB issued an accounting standards update relating to standards for extractive oil and gas activities. The accounting standards update amends existing standards to align the proved reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. The Company adopted the new standards effective December 31, 2009. The new standards were applied prospectively as a change in estimate. The use of the Final Rule’s historical 12-month unweighted average of the first-day-of-the-month price affected the Company’s depletion expense calculation for the three and six months ended June 30, 2010 resulting in an increased expense of approximately $31,000 and $15,000, respectively, and did not have an impact on earnings per share. In April 2010, the FASB issued a further accounting standards update regarding extractive oil and gas industries to incorporate in accounting standards the revisions to Rule 4-10 of the SEC’s Regulation S-X. The amendment primarily consists of the addition and deletion of definitions of terms related to fossil fuel exploration and production arising from technology changes over the past several decades. The accounting guidance in Rule 4-10 did not change.

3. Property, Plant and Equipment

The amount capitalized as natural gas and oil properties was incurred for the purchase and development of various properties in the United States (“US”), specifically the states of Montana, Pennsylvania, Texas, West Virginia and Wyoming.

At June 30, 2010, unproved properties excluded from amortization consisted of drilling in progress costs of $5.7 million, acreage acquisition costs of $124.1 million and capitalized interest of $18.1 million. At December 31, 2009, unproved properties excluded from amortization consisted of drilling in progress costs of $3.8 million, acreage acquisition costs of $111.0 million and capitalized interest of $17.9 million. The Company’s East Texas exploration is ongoing and currently is anticipated to be completed over the next six years. The Marcellus Shale exploration activities have commenced, and the Company currently anticipates these activities could continue for up to 10 years.

Management’s ceiling test evaluation for the six months ended June 30, 2010 did not result in an impairment of proved properties. The June 30, 2010 ceiling test evaluation utilized a historical 12-month unweighted average of the first-day-of-the-month Henry Hub natural gas price of $4.10 per MMBtu. For the six months ended June 30, 2009, the results of management’s ceiling test evaluations resulted in an impairment of proved properties of $68.7 million recorded at March 31, 2009 utilizing a period-end Henry Hub natural gas price of $3.61 per MMBtu.

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Sale of Petroleum Exploration Licenses 238, 433, and 434 and Repayment of Debt

On July 13, 2009, Gastar Exploration New South Wales, Inc. (“Gastar New South Wales”) and Gastar Exploration USA, Inc. (“Gastar USA”), each wholly owned subsidiaries of the Company, completed the sale of all of the Company’s interest in Petroleum Exploration Licenses (“PEL”) 238 (including Petroleum Production License 3), PEL 433, and PEL 434 in New South Wales, Australia and the concurrent sale of the Company’s common shares of Gastar Power Pty Ltd. (“Gastar Power”), the Company’s wholly-owned subsidiary holding its 35% working interest in the Wilga Park Power Station (collectively, the “Australian Assets”), to Santos QNT Pty Ltd. and Santos International Holdings Pty Ltd. (collectively, “Santos”). The sale was made pursuant to a definitive sale agreement dated July 2, 2009 by and among Gastar New South Wales, Gastar USA and Santos.

The Australian Assets included the Company’s 35% working interest in PEL 238, a CBM exploratory property covering approximately 2.2 million gross (761,400 net) acres, located in the Gunnedah Basin of New South Wales, as well as 1.9 million gross (664,000 net) acres in PEL 433, approximately 1.9 million gross (669,000 net) acres in PEL 434 and the Company’s foreign subsidiary, Gastar Power, which acquired a 35% working interest in the Wilga Park Power Station in February 2009.

Including gross reserve certification target proceeds, the Australian Assets were sold for an aggregate purchase price of $250.4 million (AU$320.0 million), before transaction costs of $1.5 million, resulting in a gain on the sale of assets of $211.2 million at December 31, 2009. At March 31, 2010, the Company had received approximately $248.9 million (AU$318.0 million), excluding taxes and transaction expenses, with the balance to be paid upon receipt of certain government approvals. In April 2010, the final governmental approval was obtained and Santos remitted the remaining balance based on the current foreign exchange rate of approximately $1.8 million (AU$2.0 million) to the Company. The sale agreement also acknowledged the Company’s retention of its right to future cash payments of up to $10.0 million pursuant to a pre-existing farm-in agreement in the event certain production thresholds are reached on PEL 238. The Company follows the full cost method of accounting, which typically does not allow for gain on sale recognition involving less than 25% of the reserves in a given cost center. All of the Company’s properties in Australia were sold to Santos; therefore, gain recognition on the sale of unproven property was deemed the proper accounting treatment.

The Company used the proceeds from the sale of the Australian Assets to (i) repay the $13.0 million outstanding on its secured original revolving credit facility, (ii) repay in full its $25.0 Million Term Loan, (iii) repurchase all of its outstanding $100.0 million 12³/4% Senior Secured Notes due December 31, 2012 at a price of 106.375% of par, plus accrued and unpaid interest, (iv) repay, at par, an initial $10.3 million of its Convertible Subordinated Debentures, and (v) repay the remaining $300,000 of Subordinated Unsecured Notes Payable.

4. Short-Term Loan

On November 20, 2009, the Parent entered into a $17.0 million secured short-term loan agreement with the lender parties and administrative agent thereto (the “Short-Term Loan”). Concurrent with the execution of the Short-Term Loan, the Parent drew $17.0 million and used the proceeds, together with cash on hand, to repay all $19.7 million of its outstanding 9.75% convertible senior unsecured subordinated debentures due November 20, 2009. The Short-Term Loan bore interest at the floating prime rate of the lender, or 5.0% per annum, from issuance to repayment. The Short-Term Loan was repaid in full on January 8, 2010.

5. Long-Term Debt

Revolving Credit Facility

On October 28, 2009, Gastar USA, together with the Parent and Subsidiary Guarantors, and the lenders, administrative agent and letter of credit issuer party thereto, entered into an amended and restated credit facility, amending and restating in its entirety the original revolving credit facility (the “Revolving Credit Facility”). The Revolving Credit Facility provided an initial borrowing base of $47.5 million, with borrowings bearing interest, at

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

the Company’s election, at the prime rate or LIBO rate plus an applicable margin. The borrowing base was subsequently reduced from $47.5 million to $40.0 million during June 2010 in accordance with the Second Amendment, as discussed below. Pursuant to the Revolving Credit Facility, the applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on LIBO rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.50% is payable quarterly based on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity date of January 2, 2013.

The Revolving Credit Facility is guaranteed by the Parent and all its current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees under the Revolving Credit Facility are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA and its subsidiaries, excluding de minimus value properties as determined by the lender. The 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 each foreign subsidiary of Gastar USA.

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

•

Restrictions on liens;

•

Restrictions on incurring other indebtedness without the lenders’ consent;

•

Restrictions on dividends and other restricted payments;

•

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

•

Maintenance of a maximum ratio of indebtedness to EBITDA on a rolling four quarter basis, as adjusted, of not greater than 4.0 to 1.0, commencing with the quarter ended December 31, 2009; 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 commencing December 31, 2009, to be less than 2.5 to 1.0.

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

•

Failure to make payments under the Revolving Credit Facility;

•

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

•

The occurrence of a “Change in Control” (as defined in the Revolving Credit Facility) of the Parent.

Should there occur a Change in Control of the Parent, then, five days after such occurrence, immediately and without notice, (i) all amounts outstanding under the Revolving Credit Facility shall automatically become immediately due and payable and (ii) the commitments shall immediately cease and terminate unless and until reinstated by the lender in writing. If amounts outstanding under the Revolving Credit Facility become immediately due and payable, the obligation of Gastar USA with respect to any commodity hedge exposure shall be to provide cash as collateral to be held and administered by the lender as collateral agent.

Following our scheduled semi-annual borrowing base redetermination in May, on June 24, 2010, Gastar USA, together with the other parties thereto, entered into the Second Amendment to the Amended and Restated Credit Agreement (the “Second Amendment”). The Second Amendment amended the Revolving Credit Facility, by, among other things, allowing the Company (i) to hedge up to 80% of the proved developed producing (“PDP”) reserves reflected in its reserve report using hedging other than floors and protective spreads, (ii) relatedly, to present to the administrative agent a report showing any PDP additions resulting from new wells or the conversion of proved developed non-producing reserves to PDP reserves since the last reserve report in order to hedge the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

revised PDP reserves, and (iii) removing limitations on hedging using floors and protective spreads. Additionally, the Second Amendment reduced the borrowing base under the Revolving Credit Facility to $40.0 million from $47.5 million. As of June 30, 2010, the Company had $8.0 million outstanding under the Revolving Credit Facility.

Credit support for the Company’s open derivatives at June 30, 2010 is provided through inter-creditor agreements or open accounts. As of June 30, 2010, the availability under the borrowing base available to the Company was $32.0 million. The borrowing base currently available to the Company is $40.0 million. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. The Company and the lenders may request one additional unscheduled redetermination annually.

At June 30, 2010, the Company was not in compliance with the 80% hedge limitation for 2011 under the Revolving Credit Facility. The Company has been granted a waiver in regards to the hedge limitation through March 31, 2011. The Company was in compliance with all other covenants under the Revolving Credit Facility at June 30, 2010.

6. 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 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. As none of the Company’s non-financial assets and liabilities were impaired during the period-ended June 30, 2010, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at June 30, 2010.

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 (“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. Level 3 instruments are natural gas costless collars, warrants, index, basis and fixed price swaps and put and call options. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 report them gross on its condensed consolidated balance sheets.

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 June 30, 2010 and December 31, 2009:


	Fair value as of June 30, 2010
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	6,822	$	—	$	—		$	6,822
Commodity derivative contracts		—		—		18,966			18,966
Liabilities:
Commodity derivative contracts		—		—		(5,732	)		(5,732	)
Warrant derivative		—		—		(2	)		(2	)

Total	$	6,822	$	—	$	13,232		$	20,054


	Fair value as of December 31, 2009
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	21,866	$	—	$	—		$	21,866
Commodity derivative contracts		—		—		15,568			15,568
Liabilities:
Commodity derivative contracts		—		—		(7,725	)		(7,725	)
Warrant derivative		—		—		(205	)		(205	)

Total	$	21,866	$	—	$	7,638		$	29,504

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2010 and 2009. Level 3 instruments presented in the table consist of net derivatives that, in management’s judgment, reflect the assumptions a marketplace participant would have used at June 30, 2010 and 2009.


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)
Balance at beginning of period	$	15,011		$	6,104		$	7,638		$	8,708
Total gains (losses) (realized or unrealized):
included in earnings		675			829			9,203			4,990
included in other comprehensive income		—			—			—			—
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements (1)		(2,454	)		(5,306	)		(3,609	)		(12,071	)
Transfers in and (out) of Level 3		—			—			—			—

Balance at end of period	$	13,232		$	1,627		$	13,232		$	1,627


The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at June 30, 2010 and 2009	$	(917	)	$	(4,426	)	$	8,609		$	(4,622	)

(1)	Includes the sale of calls at a weighted average price of $6.92 on approximately 3.3 MMBtu per day for the period April 2010 through December 2012 and hedge monetizations yielding $138,000 and $1.3 million of cash settlements for the three and six months ended June 30, 2010 respectively.

At June 30, 2010, the estimated fair value of cash and cash equivalents, term deposits, accounts receivable and accounts payable approximates their carrying value due to their short-term nature.

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 Part I, Item 1. “Financial Statements, Note 7—Derivative Instruments and Hedging Activity.”

7. 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 natural gas price risk.

Effective October 1, 2008, the Company elected to discontinue hedge accounting on all existing derivative contracts and elected not to designate any derivative contracts as cash flow hedges. Any hedge effectiveness related to the Company’s previous cash flow hedging relationships were to remain in other comprehensive income until the underlying forecasted transactions affected earnings. As a result, for the three and six months ended June 30, 2009, the Company reported gains of $828,000 and $1.7 million, respectively, which were reclassified into earnings as a result of previously discontinued cash flow hedges. As of December 31, 2009, all other comprehensive income had been reclassified to earnings. All derivative contracts are carried at their fair value on the balance sheet and all unrealized gains and losses are recorded in the statement of operations in unrealized natural gas hedge gain (loss), while realized gains and losses related to contract settlements are recognized in natural gas and oil revenues. For the three and six months ended June 30, 2010, the Company reported unrealized losses of $972,000 and unrealized gains of $8.4 million, respectively, in the statement of operations related to the change in the fair value of its

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

commodity derivative instruments. For the three and six months ended June 30, 2009, the Company reported unrealized losses of $4.4 million and $4.6 million, respectively, in the statement of operations related to the changes in fair value of its commodity derivative instruments

As of June 30, 2010, the following derivative transactions were outstanding with the associated notational volumes and weighted average underlying hedge prices:


Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price			Floor (Long)		Short Put		Ceiling (Short)
		(in MMBtu's)
2010	Put spread	9,151	1,315,500	$	—		$	6.03	$	4.24	$	—
2010	Costless collar	20,262	2,348,000		—			5.91		4.35		7.48
2010	Basis - HSC (1)	14,000	2,423,500		(0.24	)		—		—		—
2010	Basis - CIG (2)	1,000	184,000		(1.31	)		—		—		—

2011	Put spread	2,673	981,550		—			6.00		4.00		—
2011	Costless collar	15,320	4,903,450		—			6.12		4.19		7.65
2011	Fixed price swap	2,000	730,000		6.11			—		—		—
2011	Short calls	2,500	225,000		—			—		—		9.15
2011	Basis - HSC (1)	10,167	1,839,000		(0.23	)		—		—		—
2011	Basis - CIG (2)	800	292,000		(1.21	)		—		—		—

2012	Put spread	13,028	4,770,420		—			6.00		4.00		—
2012	Costless collar	5,410	1,979,580		—			6.00		4.00		7.39

(1)	East Houston-Katy – Houston Ship Channel

(2)	Inside FERC Colorado Interstate Gas, Rocky Mountains

As of June 30, 2010, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institution, which are not known to the Company to be in default on their derivative positions. Credit support for the Company’s open derivatives at June 30, 2010 is provided under the Revolving Credit Facility through inter-creditor agreements or open credit accounts of up to $5.0 million. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.

In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period July 2010 through December 2012. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. At June 30, 2010, the balance of unamortized put premium liabilities was $9.3 million, of which $2.6 million is recorded as a current commodity derivative premium payable and $6.7 million is recorded as a long-term commodity derivative premium payable. Of the total unamortized put premium liabilities, $1.2 million, $3.4 million and $4.7 million will be amortized in the second half of 2010, 2011 and 2012, respectively.

Warrants

The Company reclassified the fair value of its warrants to purchase common stock, which had exercise price reset features, from equity to liability status as if these warrants were treated as a derivative liability since their date of issue in June 2008. On January 1, 2009, the Company reclassified from additional paid-in capital, as a cumulative effect adjustment, $5.4 million to beginning retained earnings and did not recognize any value to

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

common stock warrant liability for representing the fair value of such warrants on such date. The fair value of these warrants to purchase common stock was $2,000 as of June 30, 2010, and the Company recognized $55,000 and $203,000 in unrealized gains in other income for the change in fair value of these warrants for the three and six months ended June 30, 2010, respectively.

The following warrants to purchase common shares were outstanding as of June 30, 2010:


Warrants Outstanding	Fair Value (in thousands)		Weighted Price per Share Range		Average Remaining Life in Years	Average Exercise Price
2,000,000	$	2	(1	)	1.4	(1	)

(1)

The warrants are exercisable for $13.75 per share in the event that, on or before June 11, 2011, the Company sells all or substantially all of its present natural gas and oil interests located in Leon and Robertson Counties in East Texas for net proceeds exceeding $500.0 million. A sale or a series of sales of all or substantially all of the Company’s present East Texas properties prior to June 11, 2011 for $500.0 million or less will terminate the warrants. If the Company does not sell all or substantially all of these properties by June 11, 2011, the warrants will be exercisable for a six-month period commencing on that date at $15.00 per share. The Company is not obligated to sell any of its East Texas properties. Fair value is based on the Black-Scholes-Merton model for option pricing.

Additional Disclosures about Derivative Instruments and Hedging Activities

The tables below provide information on the location and amounts of derivative fair values in the statement of financial position and derivative gains and losses in the 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	June 30, 2010			December 31, 2009
		(in thousands)
Derivatives not designated as hedging instruments
Current	Receivables from commodity derivative contracts	$	7,793		$	4,870
Long-term	Receivables from commodity derivative contracts		11,173			10,698
Current	Liabilities from commodity derivative contracts		(2,392	)		(3,678	)
Long-term	Liabilities from commodity derivative contracts		(3,340	)		(4,047	)
Long-term	Warrant derivative		(2	)		(205	)


Total derivatives not designated as hedging instruments		$	13,232		$	7,638

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Amount of Gain (Loss) Recognized in Income on Derivatives
		Amount of Gain (Loss) Recognized in Income on Derivatives For the Three Months Ended
	Location of Gain (Loss) Recognized in Income on Derivatives	June 30, 2010			June 30, 2009
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Unrealized natural gas hedge gain (loss)	$	(972	)	$	(4,426	)
Warrant derivative	Other income (expense)		55			—

Total		$	(917	)	$	(4,426	)


	Amount of Gain (Loss) Recognized in Income on Derivatives
		Amount of Gain (Loss) Recognized in Income on Derivatives For the Six Months Ended
	Location of Gain (Loss) Recognized in Income on Derivatives	June 30, 2010			June 30, 2009
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Unrealized natural gas hedge gain (loss)	$	8,406		$	(4,622	)
Warrant derivative	Other income (expense)		203			—

Total		$	8,609		$	(4,622	)

8. Capital Stock

Common Shares

The Company’s articles of incorporation allow the Company to issue an unlimited number of common shares without par value. On July 23, 2009, the Company filed an article of amendment to its articles of incorporation with the Registrar of Corporations of Alberta, Canada for the purpose of affecting the 1-for-5 Reverse Split. The Company’s shareholders approved the reverse split at the 2008 Annual General and Special Meeting of Shareholders held on June 20, 2008 by a special resolution authorizing a reverse split of the Company’s common shares on the basis of one (1) new common share for up to five (5) common shares outstanding or such fewer number of common shares as the Board of Directors may, in its sole discretion, approve at a later date. The Board of Directors approved the 1-for-5 Reverse Split on June 29, 2009. As of the opening of trading on August 3, 2009, the Company’s common shares began trading on the NYSE Amex under the same symbol of “GST” on a post 1-for-5 Reverse Split basis. No scrip or fractional certificates were issued in connection with the 1-for-5 Reverse Split. Shareholders who otherwise would have been entitled to receive fractional shares because they held a number of common shares not evenly divisible by five received a number of shares after rounding up to the next common share.

Preferred Shares

On June 30, 2009, the Company filed an amendment to its articles of incorporation to be effective as of June 30, 2009 with the Registrar of Corporations of Alberta, Canada for the purpose of creating and adding an unlimited number of preferred shares to the authorized capital of the Company. The Company’s shareholders approved the amendment by special resolution at the 2007 Annual General and Special Meeting of Shareholders held on June 1, 2007. Pursuant to the amendment, the number of preferred shares which may be issued from time to time and the privileges, restrictions and conditions of such preferred shares when issued will be determined by the Board of Directors of the Company.

Other Share Issuances

During the three and six months ended June 30, 2010 and pursuant to the Company’s 2006 Long-Term Incentive Plan, 21,000 and 400,050 restricted common shares were granted and issued, respectively. In addition, 26,757 and 34,704 common shares were forfeited in connection with the payment of estimated withholding taxes on restricted shares that vested during the three and six months ended June 30, 2010, respectively.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Shares Reserved

At June 30, 2010, the Company had reserved 4,468,131 common shares to be issued pursuant to the exercise of stock options (1,148,100 common shares), the issuance of granted but unvested restricted shares (1,320,031 common shares) and the exercise of a warrant (2,000,000 common shares).

9. Interest Expense

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)
Interest expense:
Cash and accrued	$	85		$	5,447		$	190		$	10,273
Amortization of deferred financing costs and debt discount		61			722			157			1,408
Capitalized interest		(126	)		(5,032	)		(249	)		(9,382	)

Total interest expense	$	20		$	1,137		$	98		$	2,299

10. Related Party Transactions

Chesapeake Energy Corporation

On November 4, 2005, November 11, 2006 and May 23, 2007, Chesapeake Energy Corporation (“Chesapeake”) acquired 5,430,328, 1,000,000 and 351,439 common shares, respectively, in private placement transactions. Chesapeake has the right, with certain exceptions, to maintain its percentage ownership of the Company, on a fully diluted basis, by participating in future stock issuances and has the right to have an observer present at meetings of the Board of Directors.

As of June 30, 2010, Chesapeake owned 6,781,767 common shares, or 13.5% of the Company’s outstanding common shares. See Part I, Item 1. “Financial Statements, Note 13—Commitments and Contingencies.”

11. Income Taxes

For the three and six months ended June 30, 2010, the Company recognized a current income tax expense of $57,000 and a current income tax benefit of $792,000, respectively. The current quarter income tax expense represents Australian withholding tax on Australian interest income earned during the period. The income tax benefit for the six month period ended June 30, 2010 is primarily the result of the Australian Taxation Office’s (“ATO”) issuance of an amended assessment of the income tax with respect to the gain on sale of the Company’s Australian Assets in July 2009. The issuance of the amended assessment by the ATO represented a final resolution in favor of the Company of certain tax issues that could not be resolved until the ATO completed its review of the Australian Assets sale in April 2010. The ATO resolution resulted in the recognition of an Australian tax expense benefit of AU$1.3 million ($1.0 million), which was reduced by AU$278,000 ($252,000) of Australian withholding tax on interest income earned on term deposits in Australia. On June 1, 2010, the accrued Australian taxes payable of $70.4 million was settled using proceeds from the term deposit.

12. Earnings per Share

In accordance with the provisions of authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding for the period. Diluted earnings or loss per share is computed based upon the weighted average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. Potentially dilutive securities are not included in the computation of diluted loss per share, as such the effect would be anti-dilutive.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010		2009
	(in thousands, except per share and share data)
Net income (loss)	$	(2,498	)	$	(2,393	)	$	6,895	$	(72,580	)

Weighted average common shares outstanding—basic		49,042,874			44,854,954			49,020,072		43,163,088
Incremental shares from unvested restricted shares		—			—			437,453		—
Incremental shares from outstanding stock options		—			—			71,832		—

Weighted average common shares outstanding—diluted		49,042,874			44,854,954			49,529,357		43,163,088

Income (loss) per common share:
Basic	$	(0.05	)	$	(0.05	)	$	0.14	$	(1.68	)
Diluted	$	(0.05	)	$	(0.05	)	$	0.14	$	(1.68	)

Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares		179,028			570,641			90,009		538,887
Stock options		905,800			2,003,050			989,933		2,065,205
Warrants		2,000,000			2,004,236			2,000,000		2,004,236
Convertible subordinated debentures		—			1,369,863			—		1,369,863

Total		3,084,828			5,947,790			3,079,942		5,978,191

13. Commitments and Contingencies

Litigation

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc., First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas 12th Judicial District. This lawsuit, dated October 31, 2005, contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil leases located in Leon and Robertson Counties and sold to Chesapeake Energy Corporation pursuant to a transaction closed November 4, 2005. The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota neither properly nor timely exercised any preferential right election it may have had with respect to the inter-dependent Chesapeake transaction. In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its opinion on January 9, 2008 reversing the trial court’s rulings, rendering judgment in favor of Navasota on its claims for breach of contract and specific performance, and remanding the case for further proceedings on Navasota’s other counts, which include claims for suit to quiet title, trespass to try title, tortuous interference with contract, conversion, money had and received, and declaratory relief. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, which was denied on March 18, 2008. The Company and Chesapeake filed a joint Petition for Review in the Texas Supreme Court on May 13, 2008. On August 28, 2008, the Texas Supreme Court requested briefing on the merits. On January 9, 2009, the Texas Supreme Court denied the Petition for Review. On January 26, 2009, the Company and Chesapeake jointly filed a motion for rehearing in the Texas Supreme Court on its denial of the Petition for Review. On April 24, 2009, the Texas Supreme Court denied the Petition for Review.

Pursuant to a provision in the November 4, 2005 Purchase and Sale and Exploration Development Agreement with Chesapeake, Chesapeake acknowledged the existence of the Navasota lawsuit and claims and further agreed that if Navasota were to prevail on its claims, that Chesapeake would convey the affected interests it purchased from the Company to Navasota upon receipt of the purchase price and/or other consideration paid by Navasota. Therefore, the Company believes that Navasota’s exercise of its rights of specific performance should impact only Chesapeake’s assigned leasehold interests. However, in December 2008, Chesapeake stated to the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Company that if the Texas Supreme Court were not to reverse the decision of the Tenth Court of Appeals, Chesapeake would seek rescission of the 2005 transaction and restitution of consideration paid, indicating that Chesapeake might assert such rescission and restitution as to the November 4, 2005 Purchase and Sale and Exploration Development Agreement; a November 4, 2005 Exploration and Development Agreement; and a November 4, 2005 Common Share Purchase Agreement. In its December 2008 communication, Chesapeake did not identify particular sums as to which it might seek restitution, but amounts paid to the Company in connection with the 2005 transaction could be asserted to include the $76.0 million paid by Chesapeake for the purchase of 5.5 million common shares as part of the transaction in 2005 and/or other amounts. Chesapeake has amended its Answer to include cross-claims and counterclaims, including a claim for rescission.

On or about June 9, 2009, Navasota filed and served its Fourth Amended Petition, essentially re-pleading its previously-asserted claims against the Company and Chesapeake. Navasota has exercised its rights of specific performance, and Chesapeake assigned leases to Navasota in July 2009.

In addition, while the Navasota Resources litigation is pending, it is possible that expenditures incurred, or authorizations for proposed expenditures, for drilling activities on leases which include the disputed interest may remain unpaid or not be authorized by the non-operators asserting competing ownership rights, which could require the Company to either fund a disproportionate amount of drilling costs at its own risk or postpone its drilling program on affected leases. The Company intends to vigorously defend all claims asserted in the suit.

Craig S. Tillotson v. S. David Plummer 2nd, Spencer Plummer 3rd, Tony Ferguson, John Parrott, Thomas Robinson, GeoStar Corporation, First Source Wyoming, Inc. GeoStar Financial Services Corporation, Gastar Exploration Ltd., Zeus Investments, LLC and John Does 1-10 (Civil No. 080412334). This lawsuit was filed on July 7, 2008 in Utah state court by Craig S. Tillotson (“Tillotson”), in which he alleges that he was fraudulently induced to invest in a mare leasing program operated by Classic Star LLC, (“ClassicStar”) a subsidiary of GeoStar Corporation (“GeoStar”), on the basis of certain verbal representations, and to convert interests in that program into shares of a working interest in the Powder River Basin. Tillotson asserts causes of action against all defendants including common law fraud, fraudulent inducement, statutory securities fraud under Utah state law, civil conspiracy, and negligent misrepresentation, and asserts certain additional causes of action only against GeoStar, a GeoStar affiliate, and David and Spencer Plummer. The Company has not been served and has not yet answered or otherwise responded. The Company intends to vigorously defend the suit.

In re ClassicStar Mare Lease Litigation and Gregory R. Raifman, individually and as Trustee of the Raifman Family Revocable Trust Dated 7/2/03, Susan Raifman, individually and as Trustee of the Raifman Family Revocable Trust Dated 7/2/03, and Gekko Holdings, LLC, d/b/a Gekko Breeding and Racing v. ClassicStar LLC, ClassicStar Farms, LLC, Strategic Opportunity Solutions, LLC d/b/a Buffalo Ranch, GeoStar Corporation, S. David Plummer, Spencer D. Plummer III, Tony Ferguson, Thomas Robinson, John Parrot, Karren Hendrix, Stagg Allen & Company, P.C. f/k/a Karren Hendrix & Associates, P.C., Terry L. Green, ClassicStar Farms, Inc., Gastar Exploration, Ltd. and Does 1-1,000; In the United States District Court for the Eastern District of Kentucky (Cause No. 5:07-cv-347-JMH, Master File No. 5:07-cv-353-JMH). This lawsuit was filed on February 2, 2009 in federal court in Kentucky as part of a multi-district litigation proceeding, naming the Company as one of the several defendants. The plaintiffs allege that they were induced to participate in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing program for working interests in wells or shares of Company stock owned by defendants other than the Company. The plaintiffs assert several causes of action against all defendants, including violations of the RICO Act, common law fraud, negligent misrepresentation, constructive trust, unjust enrichment, and negligence. The plaintiffs also assert additional causes of action only against the ClassicStar defendants, David and Spencer Plummer, Karren Hendrix, Terry Green, Strategic Opportunity Solutions, and Does 1-1,000. On June 5, 2009, the Company filed a motion to dismiss the suit for failure to state a claim and for want of personal and subject matter jurisdiction. The motion is pending at this time. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Briefing is not yet complete on the motion. The Company intends to vigorously defend the suit.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In re ClassicStar Mare Lease Litigation and West Hill Farms, LLC, et al. v. ClassicStar LLC, ClassicStar Farms, LLC, ClassicStar 2004, LLC, National Equine Lending Co., LLC, New NEL, LLC, GeoStar Corp., GeoStar Equine Energy, Inc., Tony Ferguson, David Plummer, ClassicStar Thoroughbreds, LLC, Spencer Plummer, Karren Hendrix Stagg Allen & Co., Thom Robinson, John Parrot, First Equine Energy Partners, LLC, Strategic Opportunity Solutions, LLC d/b/a Buffalo Ranch, ClassicStar 2005 Powerfoal Stables, LLC, ClassicStar Farms, Inc., GeoStar Financial Services Corp., Gastar Exploration, Ltd., and John Does 1-3; In the United States District Court for the Eastern District of Kentucky (Cause No. 06-243-JMH, Master File No. 5:07- cv-353-JMH). This lawsuit was filed on February 2, 2009 in federal court in Kentucky as part of a multi-district litigation proceeding, naming the Company as one of several defendants. The plaintiffs allege that they were induced to participate in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing program for working interests in wells or shares of Company stock owned by defendants other than the Company. The plaintiffs assert several causes of action against the majority of the defendants, including the Company. These causes of action include violations of the RICO Act, common law fraud, negligent misrepresentation, theft by deception, unjust enrichment, conspiracy, aiding and abetting, and fraudulent transfer. The plaintiffs also assert additional causes of action against certain defendants other than the Company for breach of contract, state and federal securities fraud, anticipatory breach, and conversion. On March 19, 2009, the Company filed a motion to dismiss the suit for failure to state a claim and for want of personal and subject matter jurisdiction. The motion is pending at this time. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Briefing is not yet complete on the motion. The suit is set for trial beginning in November 2010. The Company intends to vigorously defend the suit.

In re ClassicStar Mare Lease Litigation and AA-J Breeding, LLC, Su-Sim, LLC, Derby Stakes, LLC, Uri Halfon, and Ora-Oli Halfon v. GeoStar Corp., GeoStar Financial Services Corp., First Source Wyoming, Inc., ClassicStar, LLC, ClassicStar Farms, LLC, ClassicStar Farms, Inc., Karren Hendrix, Stagg, Allen, & Company, P.C., f/k/a Karren, Hendrix & Assoc. P.C., Handler, Thayer, & Duggan, LLC, Thomas J. Handler, J.D., P.C., S. David Plummer, Spencer D. Plummer III, Tony Ferguson, Terry L. Green, and Gastar Exploration, Ltd.; In the United States District Court for the Eastern District of Kentucky (Cause No. 5:08-cv-79-JMH, Master File No. 5:07-cv-353-JMH). This lawsuit was filed on February 6, 2009 in federal court in Kentucky as part of a multi-district litigation proceeding, naming the Company as one of several defendants. The plaintiffs allege that they were induced to participate in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing program for working interests in wells or shares of Company stock. The plaintiffs assert several causes of action against all defendants, including violations of the RICO Act, breach of contract, common law fraud, misrepresentation, constructive trust, unjust enrichment, accounting, and conversion. The plaintiffs also assert additional causes of action only against Karren Hendrix, Handler, Thayer, & Duggan, LLC, and Thomas J. Handler. On May 22, 2009, the Company filed a motion to dismiss the suit for failure to state a claim and for want of personal and subject matter jurisdiction. The motion is pending at this time. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Briefing is not yet complete on the motion. The Company intends to vigorously defend the suit.

In re ClassicStar Mare Lease Litigation and John Goyak, Dana Goyak, John Goyak & Associates, Inc., and Jupiter Ranches, LLC, v. ClassicStar Racing Stable, LLC, ClassicStar 2003 Racing Partnership, LLC, GeoStar Financial Services Corporation, GeoStar Corporation, Private Consulting Group, Inc., S. David Plummer, Spencer Plummer, Thomas Bissmeyer, Thomas Williams, Gary Thornhill, Robert Holt, Elizabeth Holt, David Lieberman, Tony Ferguson, John Parrott, Thom Robinson, Strategic Opportunity Solutions d/b/a Buffalo Ranch, and First Source Wyoming; In the United States District Court for the Eastern District of Kentucky (Cause No. 08-cv-0053, Master File No. 5:07-cv-353-JMH). On July 15, 2009, the Court granted the plaintiffs leave to amend their pleadings in order to add the Company to the suit as one of several defendants. The plaintiffs allege that they were induced to participate in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing program for working interests in wells or shares of Company stock owned by defendants other than the Company. The plaintiffs assert several causes of action including violations of the RICO Act, common law fraud, breach of contract, unjust enrichment, common law conspiracy, constructive trust, and fraud. The plaintiffs also assert additional causes of action against certain defendants other than the Company. On September 3, 2009, the Company filed a motion to dismiss the suit for failure to state a claim and for want of

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

personal and subject matter jurisdiction. The motion is pending at this time. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Briefing is not yet complete on the motion. The Company intends to vigorously defend the suit.

In re ClassicStar Mare Lease Litigation and James D. Lyon, Chapter 7 Trustee of ClassicStar LLC v. Tony P. Ferguson, S. David Plummer, Spencer D. Plummer III, Shane D. Plummer, Jennifer Stahle, Boyce J. Sanderson, Thomas E. Robinson, John W. Parrott, Frederick J. Lambert, ClassicStar Farms, Inc., Tartan Business L.C., Dinosaur Enterprises, L.L.C., Cadillac Farms, Inc., ClassicStar Farms LLC, GeoStar Corporation, First Source Texas, Inc., First Source Bossier, L.L.C., First Texas Gas, LP, CBM Resources Pty, Ltd., Associated Geophysical Services, Inc., Conquest Group Operating Company, West Virginia Development, Inc., West Virginia Gas Corporation, Squaw Creek Development, Inc., Arkoma Basin Development, Inc., Royalty Acquisition Company, BNG Producing & Drilling, GeoStar Financial Corporation, GeoStar Financial Services Corporation, GeoStar Leasing Corporation, Conquest Exploration, Inc., First Source Wyoming, Inc., Squaw Creek, Inc., Strategic Opportunity Solutions, LLC d/b/a Buffalo Ranch, National Equine Lending Co., L.C., New NEL, LLC, First Equine Energy Partners LLC, GeoStar Equine Energy, Inc., Private Consulting Group, Inc., Gastar Exploration, Ltd., Gastar Exploration USA, Inc. f/k/a First Sourcenergy Wyoming, Inc., Gastar Exploration Victoria, Inc. f/k/a First Sourcenergy Victoria, Inc., Gastar Exploration Texas, Inc. f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC f/k/a Bossier Basin, LLC, Gastar Exploration Texas, LP f/k/a First Source Gas, LP, Gastar Exploration New South Wales, Inc. f/k/a First Sourcenergy Group, Inc., Gastar Exploration Power Pty, Ltd., Eastern Star Gas, Limited, Brookstone Development, Ltd., Debora D. Plummer, Viking Real Estate, L.C., Crown Jewels Limited Partnership, Woodford Thoroughbreds LLC and Does 1-100, including, but not limited to, various subsidiaries and affiliates of GeoStar Corporation and various subsidiaries and affiliates of Gastar Exploration, Ltd. and various entities affiliated or associated with S. David Plummer and/or Debora D. Plummer; In the United States District Court for the Eastern District of Kentucky (Cause No. 5:09-cv-215-JMH, Master File No. 5:07-cv-353-JMH). This lawsuit was filed June 16, 2009 in federal court in Kentucky as part of a multi-district litigation proceeding. The suit, brought by the Chapter 7 liquidation bankruptcy trustee for ClassicStar, names more than 50 defendants, including the Company and seven of its subsidiaries. The trustee alleges that cash from investors in ClassicStar’s mare leasing programs was systematically diverted from ClassicStar over a six year period by various defendants, among them the former officers, directors, managers, and members of ClassicStar, with the assistance and participation of various other defendants including ClassicStar affiliates; entities controlled by ClassicStar’s former officers and affiliates; GeoStar; current or former officers or shareholders of GeoStar; and GeoStar’s subsidiaries, former subsidiaries, or formerly controlled companies, including the Company and its subsidiaries. The defendants include officers and former officers of GeoStar who also served as officers or directors of the Company and its subsidiaries, or who were Company shareholders. No current officer or director of the Company has been named as a defendant. The trustee alleges that the Company and its subsidiaries were beneficiaries of an unspecified amount of the allegedly diverted ClassicStar funds while allegedly under the control of GeoStar and its officers. The trustee further alleges that the Company and its subsidiaries, along with other defendants, aided and abetted breaches of fiduciary duties owed to ClassicStar by some of the defendants. The Company defendants, along with other defendants, are also alleged to have participated in, or were the beneficiaries of, or aided or abetted in, intentional or constructive fraudulent transfers of ClassicStar funds. The complaint also makes claims for an accounting and conversion of all funds diverted from ClassicStar by any of the defendants and makes certain additional state law claims, including claims under Utah’s UPUA law (similar to RICO), breach of contract, unjust enrichment, civil conspiracy, and alter ego. The trustee alleges that as a result of the acts complained of (including the alleged transfer of at least $330.0 million in cash from ClassicStar to various defendants), at least $1 billion in claims have been made against the ClassicStar estate. The trustee seeks damages in excess of $1 billion in compensatory damages, $330.0 million in punitive damages, costs, attorney’s fees, and interest. The lawsuit is consolidated for pretrial purposes in federal court in Kentucky as part of the previously disclosed multi-district litigation proceeding involving multiple actions filed by purported investors in the ClassicStar mare leasing programs, some of which name Gastar as one of several defendants. On August 19, 2009, the Company and its seven subsidiary defendants filed a motion to dismiss the trustee’s suit for failure to state a claim and for want of personal and subject matter jurisdiction. The motion is pending at this time and discovery is proceeding. On June 14, 2010, the trustee filed a motion for summary judgment against all defendants in the case. The trustee’s motion for summary judgment seeks an order from the court finding the defendants liable as to nearly all of the trustee’s causes of action, but does not

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seek findings regarding the amount(s) of damages for which the defendants may be liable. Briefing is not yet complete on the motion. The court has scheduled a trial of the matter to begin in November 2010. The Company intends to vigorously defend the suit.

In re ClassicStar Mare Lease Litigation and Stanwyck Glen Farms, LLC, Thomas E. Morello, and Denise G. Morello v. Wilmington Trust of Pennsylvania, Wilmington Trust FSB, Wilmington Trust Corp., Private Consulting Group, Inc., David S. Forman, National Equine Lending Company, LLC, GeoStar Corporation, Gastar Exploration Ltd., GeoStar Financial Services Corporation, S. David Plummer, Spencer Plummer, Tony Ferguson, and ClassicStar LLC; in the United States District Court of the Eastern District of Kentucky (Cause No. 5:09-cv-015-JMH, Master File No. 5:07-cv-353-JMH). On January 8, 2010, the plaintiffs in this case filed an amended complaint adding the Company to the suit as one of several defendants. The plaintiffs allege that they were induced to participate in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing program for shares of Company stock owned by defendants other than the Company. The plaintiffs assert several causes of action including violations of the federal and New Jersey RICO Acts, common law fraud, unjust enrichment, common law conspiracy, constructive trust, accounting for shares, breach of contract, and fraud. The plaintiffs also assert additional causes of action against certain defendants other than the Company. On April 5, 2010, the Company filed a motion to dismiss the suit for failure to state a claim and for want of personal and subject matter jurisdiction. The motion is pending at this time and discovery is proceeding. The Company intends to vigorously defend the suit.

In re ClassicStar Mare Lease Litigation and Premiere Thoroughbreds, LLC, Greg Minor, and Stephanie Minor v. ClassicStar LLC, ClassicStar Farms Inc., New NEL LLC, ClassicStar Thoroughbreds LLC, Karren Hendrix Stagg Allen & Co., Terry L. Green, ClassicStar 2004, ClassicStar 2005 Powerfoal Stables LLC, Strategic Opportunity Solutions, LLC d/b/a Buffalo Ranch, GeoStar Corporation, First Equine Energy Partners LLC, GeoStar Equine Energy Inc., S. David Plummer, Tony P. Ferguson, John W. Parrott, Thomas E. Robinson, Spencer D. Plummer III, GeoStar Financial Services Corp., Gastar Exploration Ltd., and John Does; in the United States District Court of the Eastern District of Kentucky (Cause No. 5:07-cv-348-JMH, Master File No. 5:07-cv-353-JMH). On November 16, 2009, the plaintiffs in this case filed an amended complaint adding the Company to the suit as one of several defendants. The plaintiffs allege that they were induced to participate in a mare leasing program operated by the defendants and then were induced to exchange their interest in that program into units in an entity known as First Equine Energy Partners (FEEP). The FEEP units were allegedly exchangeable into shares of Gastar stock owned by GeoStar Corporation and subject to a put option provided by GeoStar Corporation. The plaintiffs assert several causes of action including violations of the federal and Florida RICO Acts, common law fraud, unjust enrichment, common law conspiracy, accounting, and negligent misrepresentation. The plaintiffs also allege securities fraud under federal and Florida law and failure to register with respect to the sale of FEEP units. The plaintiffs also assert additional causes of action against certain defendants other than the Company. On March 31, 2010, the Company filed a motion to dismiss the suit for failure to state a claim and for want of personal and subject matter jurisdiction. The motion is pending at this time. The Company intends to vigorously defend the suit.

Midway Land & Development Inc. v. EnCana Oil & Gas (USA), Inc. v. Navasota Resources, LTD, LLP, Alta Mesa Resources LP f/k/a Navasota Resources, Inc., and Navasota Resources LTD., LLP and Gastar Exploration Texas LP and Gastar Exploration, LTD.; In the District Court of Robertson County, Texas, 82ND Judicial District (Judge Stem), (Cause No. 08-12-18,265-CV). Gastar Exploration Texas LP and Gastar Exploration, LTD were served as a third-party defendant (“Counterclaim Defendant”) by EnCana Oil & Gas (USA), Inc. on September 8, 2009. The Company understands that the underlying action between Midway Land & Development Inc. and EnCana Oil & Gas (USA), Inc. has been pending since 2008. In the underlying action, Midway seeks to recover from the EnCana Defendants a 2.5% working interest on certain wells located on lands within an area of mutual interest incorporated in a Joint Operating Agreement dated July 7, 2000, between First Source Texas, Inc., as operator, and Navasota Resources, Inc. and Kentex Energy, LLC (Midway’s predecessor in interest). Under the AMI agreement, it is alleged that each of the parties has the right to acquire an interest in any lease or a mineral interest acquired by any of the other parties on land situated within the AMI (for consideration set forth in the JOA). The Gastar Defendants, among others, own or claim interest in lands that Midway contends are within the AMI. The EnCana Defendants seek declaratory relief from the Court declaring that the AMI provision in the JOA is

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

unenforceable because it does not include a legally sufficient description of the lands within the AMI. Further, the EnCana Defendants seek to have a stipulation dated September 9, 2003 related to the AMI also declared unenforceable under the Statute of Frauds. It is alleged that the stipulations provides that Kentex (Midway’s predecessor in interest) shall be vested with an undivided five percent after payout working interest in each oil and gas well located on the leases listed on Exhibit A to the Stipulation. Gastar has answered the lawsuit and discovery is proceeding. The Company intends to vigorously defend the suit.

Gastar Exploration Texas L.P. vs. J. Ken Welch d/b/a W-S-M Oil Company, et al; Cause No. 0-09-117 in the 87th Judicial District Court of Leon County, Texas. This lawsuit, filed on March 12, 2009, is a suit for trespass to try title and, in the alternative, to quiet title, to an undivided mineral interest under several Company oil and gas leases covering approximately 4,273.7 gross acres (the “Leases”). In this suit the Company contends that certain oil and gas leases claimed by the defendants have expired according to their terms and that the defendants’ failure to release those leases constitutes a trespass upon and cloud on the Leases. The defendants have responded with a General Denial and produced a portion of the documents the Company sought in its Request for Production of Documents. They have also served their own requests for admissions and production of documents, to which the Company has responded. After repeated demands, the defendants have promised to comply and produce certain documents they obtained from third parties through depositions on written questions. Through independent discovery, the Company is gathering evidence to diminish the defendant’s interest ownership claims and will continue to vigorously pursue this claim.

The Company has been expensing legal defense costs on these proceedings as they are incurred. The Company has not accrued a liability for settlement or other resolution of these proceedings because, in the Company’s judgment, the incurrence or amount of such liabilities is either not probable or not reasonably estimable.

14. Statement of Cash Flows – Supplemental Information

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


	For the Six Months Ended June 30,
	2010		2009
	(in thousands)

Cash paid for interest	$	193	$	9,744
Cash paid for taxes		452		—

Non-cash transactions:
Term deposit surrendered for accrued taxes	$	70,446	$	—
Non-cash capital expenditures excluded from accounts payable and accrued drilling costs		3,527		(5,002	)
Asset retirement obligation included in natural gas and oil properties		54		210
Drilling advances application		150		7,144

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15. Comprehensive Income (Loss)

The Company’s comprehensive income (loss) for the periods indicated is as follows:


	For the Six Months Ended June 30,
	2010		2009
	(in thousands)

Net income (loss)	$	6,895	$	(72,580	)
Change in:
Commodity hedging activities - current period reclassification to earnings		—		(1,685	)
Foreign currency translation adjustments		—		(15	)

Comprehensive income (loss)	$	6,895	$	(74,280	)

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking information regarding Gastar that is intended to be covered by the “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, and Section 21E of the Securities Exchange Act of 1934, as amended. 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, 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;

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Business strategy and budgets;

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Anticipated capital expenditures;

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Drilling of wells;

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Natural gas and oil reserves;

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Timing and amount of future production of natural gas and oil;

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Operating costs and other expenses;

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Cash flow and anticipated liquidity;

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Prospect development; and

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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. For a more detailed description of the risks and uncertainties involved, see Part II, Item 1A. “Risk Factors” of this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances, or otherwise. 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:

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Low and/or declining prices for natural gas and oil;

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Demand for natural gas and oil;

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Natural gas and oil price volatility;

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The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry wells;

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Ability to raise capital to fund capital expenditures or repay or refinance debt upon maturity;

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

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

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Operating hazards inherent to the natural gas and oil business;

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Down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

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

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Adverse weather conditions;

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

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The number of well locations to be drilled and the time frame in which they will be drilled;

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Delays in anticipated start-up dates;

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Actions or inactions of third-party operators of our properties;

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Ability to find and retain skilled personnel;

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Strength and financial resources of competitors;

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Potential defects in title to our properties;

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Federal and state regulatory developments and approvals;

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Losses possible from pending or future litigation;

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Environmental risks; and

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Worldwide political and economic conditions.

Other factors that could affect our financial performance or cause our actual results to differ materially from our projected results are described under (i) Part II, Item 1A. “Risk Factors” and elsewhere in this report, (ii) Part I, Item 1A. “Risk Factors” and elsewhere in our 2009 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 they are made, whether as a result of new information, future events or otherwise, to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events.

Overview

We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as shale resource plays. We are pursuing natural gas exploration in the deep Bossier gas play in the Hilltop area of East Texas and the Marcellus Shale in the Appalachian area of West Virginia and central and southwestern Pennsylvania. We also conduct CBM development activities within the Powder River Basin of Wyoming and Montana. We are a Canadian corporation incorporated in Alberta in 1987. We are publicly traded on the NYSE Amex under the ticker symbol “GST”.

Natural Gas and Oil Activities

The following provides an overview of our major natural gas and oil 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.

Hilltop Area, East Texas. The majority of our activities have been in the Bossier play in the Hilltop area of East Texas approximately midway between Dallas and Houston in Leon and Robertson Counties. As of June 30, 2010, our acreage position in the play was approximately 31,600 gross (16,300 net) acres. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production and attractive long-lived per well reserves.

In late October 2009, we began drilling the Donelson #4 well, a vertical lower Bossier test. The well was originally drilled to a total depth of approximately 19,000 feet; however, while attempting to log the well, the drill

pipe became stuck due to hole stability issues. The well was sidetracked, and while re-drilling, the well experienced a significant gas kick and had to be plugged back to approximately 15,600 feet to re-drill to a revised total depth of 18,800 feet. This second sidetrack operation was completed in May 2010. The lower B-6 Bossier zone was completed and flowed at an initial gross sales rate of 8.6 MMcf per day. The initial completion was placed behind a temporary plug and a lower B-5 zone was completed at an initial gross sales rate of 10.7 MMcf per day. The second completion was also placed behind a temporary plug and the upper B-5 zone was fractured on July 19, 2010 and is currently producing at a gross sales rate of 10.0 MMcf per day. The B-5 zone will be produced until the reservoir pressures equalize and, at that time, all B-5 and B-6 zones will be co-mingled and produced together. Three additional zones remain to be completed at future dates. As of June 30, 2010, the cost incurred to drill and initially complete the Donelson #4 well, net of estimated reimbursement under existing well control insurance policies, is approximately $12.6 million gross ($9.1 million net). Gastar has a 67% before payout working interest and an approximate 50% before payout net revenue interest in the well.

In March 2010, we commenced a recompletion of the Belin#1 well in the “Lanier” sand at approximately 16,700 feet. The zone was fracture stimulated and during initial flow back operations the well produced significant amounts of formation sand. It appears that the formation sand production coincided with a casing failure at approximately 16,700 feet. We have successfully milled through and subsequently repaired the damaged portion of the casing and returned the well to production in late June 2010. The well is currently producing at an average gross sales rate of 8.0 MMcf per day. Gastar has a 50% before payout working interest and an approximate 34% before payout net revenue interest in the well.

During the second quarter, we treated down-hole salting and scale problems in some of our higher producing East Texas wells and completed expense workovers on two additional wells. For the three and six months ended June 30, 2010, net production from the Hilltop area averaged 13.6 MMcfe per day and 15.3 MMcfe per day, respectively.

Appalachia – West Virginia and Central and Southwestern Pennsylvania. The Marcellus Shale is Middle Devonian aged shale that underlies much 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. Advancements in two technologies, stimulation and horizontal drilling, have produced promising results in the Marcellus Shale. These developments have resulted in increased leasing and drilling activity in the area. As of June 30, 2010, our acreage position in the play was approximately 38,400 gross (34,600 net) acres, of which the majority is considered to be in the core, over-pressured area of the Marcellus play and is in close proximity to wells being drilled by other operators.

In October 2009, we commenced drilling our first vertical Marcellus Shale well, the Yoho #1. We drilled the well to a depth of 6,600 feet, and it was completed and tested in January 2010. It tested at a stabilized gross rate of 1.5 MMcf and 120 barrels of condensate per day, with no water production at approximately 1,000 psi of flowing tubing pressure. We currently are waiting for a connection to a pipeline and do not expect natural gas sales until third quarter 2011.

During the six months ended June 30, 2010, we drilled 1 gross (1.0 net) shallow vertical well resulting in total shallow wells drilled by us to date of 16 gross (14.8 net) in the area. Currently, thirteen wells are on production, two are shut-in due to pipeline curtailments and one is awaiting a pipeline connection.

For the three and six months ended June 30, 2010, net production from the Appalachia area averaged approximately 0.4 MMcfe per day and 0.4 MMcfe per day, respectively.

Coalbed Methane – Powder River Basin, Wyoming and Montana. We own an approximate 40% average working interest in approximately 40,700 gross (17,200 net) acres in the Powder River Basin of Wyoming and Montana. As a result of decreased drilling activity and curtailments during 2009 due to lower realized gas prices, Powder River Basin production averaged 1.8 MMcfe per day and 2.0 MMcfe per day for the three and six months ended June 30, 2010, respectively.

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.

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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2010		2009		2010		2009

Production:
Natural gas (MMcf)		1,428		2,323		3,181		5,016
Oil (MBbl)		2		1		4		2
Total production (MMcfe)		1,440		2,332		3,204		5,030

Total (MMcfed)		15.8		25.6		17.7		27.8

Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities	$	3.50	$	2.85	$	3.97	$	3.13
Natural gas per Mcf, including impact of realized hedging activities		4.62		5.12		4.16		5.05
Oil per Bbl		72.67		53.00		72.36		46.72

Selected operating expenses (in thousands):
Production taxes	$	93	$	92	$	216	$	249
Lease operating expenses		1,914		1,449		3,657		3,326
Transportation, treating and gathering		1,094		325		2,343		818
Depreciation, depletion and amortization		1,664		3,361		3,395		11,360
General and administrative expense		3,944		3,487		7,776		6,445

Selected operating expenses per Mcfe:
Production taxes	$	0.06	$	0.04	$	0.07	$	0.05
Lease operating expenses		1.33		0.62		1.14		0.66
Transportation, treating and gathering		0.76		0.14		0.73		0.16
Depreciation, depletion and amortization		1.16		1.44		1.06		2.26
General and administrative expense		2.74		1.50		2.43		1.28

Three Months Ended June 30, 2010 compared to the Three Months Ended June 30, 2009

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $6.7 million for the three months ended June 30, 2010, down from $12.0 million for the three months ended June 30, 2009. The decrease in revenues was the result of a 38% decrease in volumes and a 9% decrease in prices. Average daily production on an equivalent basis was 15.8 MMcfe per day for the three months ended June 30, 2010 compared to 25.6 MMcfe per day for the same period in 2009. Of the decrease in volumes, 86% was due to lower East Texas production primarily related to delays in the Donelson #4 well coming on production and operational issues on the Belin #1 along with the second quarter of 2009 benefitting from Belin #1 high production rate. Fourteen percent of the decreased volumes were primarily attributable to production declines in Wyoming.

During the three months ended June 30, 2010, approximately 67% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $1.6 million in revenues resulting in an increase in total price realized from $3.50 per Mcf to $4.62 per Mcf. The realized hedge impact includes $724,000 of amortization of prepaid put purchase and call sale premiums and contract monetizations. Excluding the non-cash amortization, the realized effect of hedging was a gain of $2.3 million comprised of $2.7 million of NYMEX hedge gains offset by $353,000 of regional basis losses. For the remainder of 2010, we have costless collar hedges for approximately 20,000 MMBtu per day representing 81% of our estimated future natural gas production with a weighted average floor of $5.91, short put of $4.35 and a ceiling of $7.48. In addition, we have put spread hedges for approximately 9,200 MMBtu per day representing 37% of our estimated future natural gas production with a weighted average floor of $6.03 and a short put of $4.24.

Unrealized natural gas hedge loss was $972,000 for the three months ended June 30, 2010 compared to an unrealized natural gas hedge loss of $4.4 million for the three months ended June 30, 2009. The decrease in unrealized natural gas hedge impact was the result of a hedge benefit as a result of lower future NYMEX gas prices partially offset by losses related to projected basis differentials.

Production taxes We reported production taxes of $93,000 for the three months ended June 30, 2010 compared to $92,000 for the three months ended June 30, 2009. The increase in production taxes was primarily the result of higher oil revenues in Texas partially offset by lower taxes in Wyoming due to lower revenues.

Lease operating expenses. We reported lease operating expenses of $1.9 million for the three months ended June 30, 2010 up from $1.4 million for the three months ended June 30, 2009. This increase was primarily due to an increase in workover expenses of $410,000 and slightly higher ad valorem costs. Our lease operating expenses were $1.33 per Mcfe for the three months ended June 30, 2010 compared to $0.62 per Mcfe for the same period in 2009. The increase in the rate per Mcfe was primarily due to lower production volumes and higher workover costs of $0.30 per Mcfe.

Transportation, treating and gathering. We reported transportation expenses of $1.1 million for the three months ended June 30, 2010 up from $325,000 for the three months ended June 30, 2009. This increase was primarily due to gathering charges in Texas under the Hilltop Gathering Agreement, effective November 2009, partially offset by lower costs in Wyoming. The current quarter included a true up charge under the Hilltop Gathering Agreement based on a minimum volume requirement of $543,000.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $1.7 million for the three months ended June 30, 2010 down from $3.4 million for the three months ended June 30, 2009. The decrease in DD&A expense was the result of a 19% decrease in the DD&A rate per Mcfe and a 38% decrease in production. The DD&A rate for the three months ended June 30, 2010 was $1.16 per Mcfe compared to $1.44 per Mcfe for the same period in 2009. The decrease in the rate is primarily due to lower proved costs as a result of gathering sales proceeds credited to proved property costs in late 2009.

General and administrative. We reported general and administrative expenses of $3.9 million for the three months ended June 30, 2010 up from $3.5 million for the three months ended June 30, 2009. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $880,000 and $713,000 for the three months ended June 30, 2010 and 2009, respectively. The increase in stock-based compensation expense is due primarily to the issuance of additional restricted shares with a higher fair value. Excluding stock-based compensation expense, general and administrative expense increased $290,000 to $3.1 million for the three months ended June 30, 2010 compared to June 30, 2009. This increase is primarily due to higher legal costs of $669,000 related to ongoing litigation matters and lower contract labor expense.

Interest expense. We reported interest expense of $20,000 for the three months ended June 30, 2010 compared to $1.1 million for the three months ended June 30, 2009. The decrease in interest expense was primarily the result of lower debt outstanding due to the payoff of substantially all outstanding debt during 2009.

Investment income and other. We reported investment income of $548,000 for the three months ended June 30, 2010 compared to $10,000 for the three months ended June 30, 2009. The increase in investment income is primarily due to interest earned on the Australian term deposit established in conjunction with the sale of the Australian properties for the future tax payment on the sale. At maturity on June 1, 2010, the term deposit was used to settle the Australian tax liability resulting from the Australian property sale in 2009.

Warrant derivative gain. For the three months ended June 30, 2010, we reported a $55,000 non-cash gain related to the fair value measurement of our warrants outstanding.

Foreign transaction gain (loss). We reported a foreign transaction gain of $16,000 for the three months ended June 30, 2010 primarily due to Australian denominated cash.

Provision for income tax expense (benefit). We reported $57,000 of income tax expense for the three months ended June 30, 2010 primarily due to withholding tax on the interest income from the Australian term deposit. At maturity on June 1, 2010, the term deposit was used to settle the tax liability resulting from the Australian property sale in 2009.

Six Months Ended June 30, 2010 compared to the Six Months Ended June 30, 2009

Revenues. Natural gas and oil revenues were $13.5 million for the six months ended June 30, 2010, down from $25.4 million for the six months ended June 30, 2009. The decrease in revenues was the result of a 36%

decrease in volumes and a 17% decrease in prices. Average daily production on an equivalent basis was 17.7 MMcfe per day for the six months ended June 30, 2010 compared to 27.8 MMcfe per day for the same period in 2009. Of the decrease in volumes, 83% was due to lower East Texas production, primarily related to delays in new wells coming on production to offset decline on existing wells and lower Belin #1 production due to the well being off production for the majority of the second quarter, combined with the first half of 2009 benefitting from Belin #1 initial flush production, and 17% was due to lower Wyoming production.

During the six months ended June 30, 2010, approximately 52% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $594,000 in revenues resulting in an increase in total price received from $3.97 per Mcf to $4.16 per Mcf. The realized hedge impact includes $1.8 million of amortization of prepaid put purchase and call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was a gain of $2.4 million comprised of $3.4 million of NYMEX hedge gains offset by $1.0 million of regional basis losses.

Unrealized natural gas hedge income was $8.4 million for the six months ended June 30, 2010 compared to an unrealized natural gas hedge loss of $4.6 million for the six months ended June 30, 2009. The increase in unrealized natural gas hedge impact was the result of additional hedged volumes and the benefit resulting from lower future NYMEX gas prices offset by losses related to basis differentials.

Production taxes We reported production taxes of $216,000 for the six months ended June 30, 2010 compared to $249,000 for the six months ended June 30, 2009. The decrease in production taxes was primarily the result of lower revenues in Wyoming due to lower production volumes.

Lease operating expenses. We reported lease operating expenses of $3.7 million for the six months ended June 30, 2010 up from $3.3 million for the six months ended June 30, 2009. This increase was primarily due to an increase in workover expenses of $292,000 and slightly higher ad valorem taxes. Our lease operating expenses were $1.14 per Mcfe for the six months ended June 30, 2010 compared to $0.66 per Mcfe for the same period in 2009. The increase in the rate per Mcfe was primarily due to lower production volumes and an increase in workover costs of $0.14 per Mcfe.

Transportation, treating and gathering. We reported transportation expenses of $2.3 million for the six months ended June 30, 2010 up from $818,000 for the six months ended June 30, 2009. This increase was primarily due to gathering charges in Texas under the Hilltop Gathering Agreement, effective November 2009, partially offset by lower costs in Wyoming. The six months ended June 30, 2010 included a true up charge under the Hilltop Gathering Agreement based on a minimum volume requirement of $934,000.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $3.4 million for the six months ended June 30, 2010 down from $11.4 million for the six months ended June 30, 2009. The decrease in DD&A expense was the result of a 53% decrease in the DD&A rate per Mcfe and a 36% decrease in production. The DD&A rate for the six months ended June 30, 2010 was $1.06 per Mcfe compared to $2.26 per Mcfe for the same period in 2009. The decrease in the rate is primarily due to lower proved costs as a result of a ceiling impairment recorded at March 31, 2009 and gathering sales proceeds credited to proved property costs in late 2009.

Impairment of natural gas and oil properties. We did not report an impairment of natural gas and oil properties for the six months ended June 30, 2010 due to lower proved property costs and higher natural gas and oil prices compared to the same period in 2009. We reported an impairment of natural gas and oil properties of $68.7 million for the six months ended June 30, 2009. The 2009 impairment was recorded at March 31, 2009 and was the result of a significant decline in natural gas prices in 2009.

General and administrative. We reported general and administrative expenses of $7.8 million for the six months ended June 30, 2010 up from $6.4 million for the six months ended June 30, 2009. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $1.6 million and $2.1 million for the six months ended June 30, 2010 and 2009, respectively. The decrease in stock-based compensation expense is due primarily to the decision in March 2009 to pay the 2008 management bonuses of $801,000 in vested restricted common shares in lieu of cash. Excluding stock-based compensation expense, general and administrative expense increased $1.8 million to $6.1 million for the six months ended June 30, 2010 compared to June 30, 2009. This increase is primarily due to higher legal costs of $1.5 million related to ongoing litigation matters and lower personnel costs for the six months ended June 30, 2009 due to the March 2009 payment of 2008 management bonuses in restricted common shares rather than in cash.

Interest expense. We reported interest expense of $98,000 for the six months ended June 30, 2010 compared to $2.3 million for the six months ended June 30, 2009. The decrease in interest expense was primarily the result of lower debt outstanding due to the payoff of substantially all outstanding debt during 2009.

Investment income and other. We reported investment income of $1.3 million for the six months ended June 30, 2010 compared to $23,000 for the six months ended June 30, 2009. The increase in investment income is primarily due to interest earned on the Australian term deposit established in conjunction with the sale of the Australian properties for the future tax payment on the sale. At maturity on June 1, 2010, the term deposit was used to settle the tax liability resulting from the Australian property sale in 2009.

Warrant derivative gain. For the six months ended June 30, 2010, we reported a $203,000 non-cash gain related to the fair value measurement of our warrants outstanding.

Foreign transaction gain (loss). We reported a foreign transaction gain of $335,000 for the six months ended June 30, 2010 compared to a foreign transaction loss of $3,000 for the six months ended June 30, 2009. The increase in the foreign transaction gain was primarily due to Australian exchange rate fluctuations regarding our Australian denominated cash and accounts receivable balances arising from the sale of the Australian properties.

Provision for income tax expense (benefit). We reported $792,000 of income tax benefit for the six months ended June 30, 2010 primarily due to a $1.0 million downward adjustment of the tax expense related to the sale of the Australian properties after final review from the Australian Tax Office partially offset by withholding tax on the interest income from the Australian term deposit. At maturity on June 1, 2010, the term deposit was used to settle the tax liability resulting from the Australian property sale in 2009.

Liquidity and Capital Resources

Overview. Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under our revolving credit facility, and access to capital markets, to the extent available. The capital markets, as they relate to us, have been adversely impacted by the recent financial crisis, the possibility of a continuing world recession that may extend for a long period into the future, the potential lack of liquidity in the banking system and the potential unavailability and cost of credit. Though recently there has been some improvement in the capital markets, there is no guarantee that such will continue. 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 natural gas and oil prices, drilling results and cash flow.

For the six months ended June 30, 2010, we reported cash flows provided by operating activities of $4.5 million, net cash used in investing activities of $10.4 million and net cash used in financing activities of $9.1 million. As a result of these activities, our cash and cash equivalents balance decreased by $15.0 million, resulting in a June 30, 2010 cash and cash equivalents balance of $6.8 million.

At June 30, 2010, we had a net working capital deficit of approximately $1.6 million.

Future capital and other expenditure requirements. Capital expenditures for the remainder of 2010 are projected to be approximately $35.3 million, consisting of $16.7 million in East Texas, $17.2 million in Appalachia in the Marcellus Shale, $400,000 in the Powder River Basin and an additional $1.0 million for capitalized interest and other costs. We plan on funding this capital activity through our existing cash balances, internally generated cash flows from operating activities, access to availability under our revolving credit facility, a potential joint venture or partial sale of assets. The majority of projected capital expenditures are operated by us and thus, we can adjust capital expenditures for changes in commodity prices, cash flows from operating activities or availability under the revolving credit facility.

Commodity Hedging Activities. Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas. 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 natural gas prices, we have entered into financial commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas price risk. We typically hedge a fixed price for natural gas at our sales points of NYMEX less basis to mitigate the risk of differentials to the NYMEX Henry Hub Index and our sales points. In addition to NYMEX swaps and collars and fixed price swaps, we also have entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. See Part I, Item 1. “Financial Statements, Note 7 – Derivative Instruments and Hedging Activity.”

At June 30, 2010, the estimated fair value of all of our commodity derivative instruments was a net asset of $13.2 million, comprised of current and noncurrent assets and liabilities. In conjunction with certain commodity derivative hedging activity, we deferred the payment of certain put premiums for the production month period July 2010 through December 2012. At June 30, 2010, we had a current commodity derivative premium payable of $2.6 million and a long-term commodity derivative premium payable of $6.7 million. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month.

By removing the price volatility from a portion of our natural gas for 2010, 2011 and 2012, 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.

As of June 30, 2010, all of our economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to us to be in default on their derivative positions. Credit support for our open derivatives at June 30, 2010 is provided under the revolving credit facility through inter-creditor agreements or open credit accounts of up to $5.0 million. 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. At June 30, 2010, we had $8.0 million outstanding under the revolving credit facility. Our borrowing base is $40.0 million based on the results of the most recent redetermination, which was completed during May 2010 and became effective with the Second Amendment to our Revolving Credit Facility on June 24, 2010. The most recent redetermination resulted in a reduction of our borrowing base from $47.5 million to $40.0 million primarily in connection with the previously announced delays in returning the Belin #1Well, located in the Hilltop area of East Texas, to production following re-completion attempts. Subsequent to the redetermination of the borrowing base, the Belin #1 Well was returned to production from all zones previously producing and 3 zones recently completed. Borrowings under the facility bear interest, at our election, at the prime rate or LIBO rate plus an applicable margin. Pursuant to the revolving credit facility, the applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on the LIBO rate, depending on the utilization percentage in relation to the borrowing base. Under the revolving credit facility, we are subject to certain financial covenants, including interest coverage ratio, a total net indebtedness to EBITDA ratio and current ratio requirement. Currently, our availability under our borrowing base is $32.0 million.

As of June 30, 2010, we were not in compliance with the 80% hedge limitation for 2011 under the Revolving Credit Facility. We have been granted a waiver in regards to the hedge limitation through March 31, 2011. We were in compliance with all other financial covenants under the Revolving Credit Facility at June 30, 2010, including interest coverage ratio, a total net indebtedness to EBITDA ratio and current ratio requirements. See Part I, Item 1. “Financial Statements, Note 5 – Long-Term Debt.”

Off-Balance Sheet Arrangements

As of June 30, 2010, 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 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.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with US 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 that could have been selected 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 1. “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 2009 Form 10-K.

Recent Accounting Developments

For a discussion of recent accounting developments, see Part I, Item I. “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 natural gas production and 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 natural gas in the region produced. Prices received for natural gas 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 six months ended June 30, 2010, a 10% change in the prices received for natural gas production (before hedging activities) would have had an approximate $1.3 million impact on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Part I, Item I. “Financial Statements, Note 7—Derivative Instruments and Hedging Activity” to our consolidated financial statements in this report for additional information regarding our hedging activities.

Interest Rate Risk

At June 30, 2010, we had $8.0 million outstanding under our revolving credit facility. However, we currently do not use interest rate derivatives to mitigate our exposure to the volatility in interest rates, including under our revolving credit facility, as this risk is minimal.

Foreign Currency Exchange Risk

During 2009, we sold all of our Australian Assets. As a result, all of our future revenues and capital expenditures and substantially all of our expenses will be in US dollars, thus limiting our exposure to foreign currency exchange risk. We settled our accrued Australian tax liability during the second quarter of 2010.

Item 4.

Controls and Procedures

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 our 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 June 30, 2010. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2010, 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.

Changes in Internal Control over Financial Reporting

In conjunction with its review of our results of operations and hedging in connection with the quarterly review at June 30, 2010, management determined that at March 31, 2010, the commodity derivative premium payable was inappropriately netted with the receivables from commodity derivative contracts resulting in an incorrect marked to market value for commodity derivative assets and understatement of unrealized natural gas hedge gains for the period. As a result of its analysis of this accounting error, management concluded that our previously issued unaudited interim financial statements as of and for the three months ended March 31, 2010 included in our Quarterly Report on Form 10-Q for the period ended March 31, 2010 should no longer be relied upon and therefore required restatement. Accordingly, on June 29, 2010, we filed a Current Report on Form 8-K and Amendment No. 1 on Form 10-Q/A to the Quarterly Report for the period ended March 31, 2010 to restate the financial statements and related disclosures included therein and otherwise reflect the adjustments described above.

We also performed a re-evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures and, as part of our evaluation, we reviewed the circumstances surrounding the accounting treatment of the matters relating to the restatement. Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2010 our disclosure controls and procedures were not effective in that there was a failure to properly record and report receivables from commodity derivative contracts and unrealized natural gas hedge gains (losses) for the period.

We implemented a number of changes in our internal control structure to address the internal control weakness described above. Our disclosure controls and procedures now include additional analysis of the reported commodity derivative assets and liabilities and additional levels of review. Except as described herein, there were no other changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

A discussion of current legal proceedings is set forth in Part I, Item I. “Financial Statements, Note 13—Commitments and Contingencies” to our condensed consolidated financial statements in this report.

Item 1A.

Risk Factors

Information about material risks related to our business, financial condition and results of operations for the three months ended June 30, 2010, does not materially differ from that set out under Part I, Item 1A. “Risk Factors” in our 2009 Form 10-K, except as set forth below. You should carefully consider the factors discussed in our 2009 Form 10-K. 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.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Company’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on the Company, its financial condition, and its results of operations.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

(Removed and Reserved)

Item 5.

Other Information

None.

Item 6. Exhibits

The following is a list of exhibits filed or furnished (as indicated) as part of this Form 10-Q. Where so indicated by a note, exhibits which were previously filed are incorporated herein by reference.


Exhibit Number		Description
3.1		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005. Registration No. 333-127498).
3.2		Articles of Amendment and Share Structure attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd., dated as of June 30, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 1, 2009. File No. 001-132714).
3.3		Articles of Amendment attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of July 23, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 24, 2009. File No. 001-132714).
3.4		Amended Bylaws of Gastar Exploration Ltd., dated as of June 3, 2010 (incorporated herein by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated June 4, 2010. File No. 001-32714).
10.1		Amended and Restated Credit Agreement dated October 28, 2009 by and among Gastar Exploration USA, Inc., the Guarantors party thereto, Amegy Bank National Association, as Administrative Agent and Letter of Credit Issuer, BMO Capital Markets Corp. as Co-Lead Arranger and Joint Bookrunner, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 3, 2009. File No. 001-32714).
10.2		Consent and First Amendment to Amended and Restated Credit Agreement dated November 20, 2009, by and among Gastar Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto, and Amegy Bank National Association, as Administrative Agent (incorporated herein by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated November 25, 2009. File No. 001-32714).
10.3		Second Amendment to Amended and Restated Credit Agreement dated June 24, 2010, by and among Gastar Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as Administrative Agent (incorporated herein by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated June 28, 2010. File No. 001-32714).
31.1†		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1††		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2††		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

†	Filed herewith.

††	Furnished herewith.

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 LTD.

Date: August 5, 2010	By:	/s/ J. RUSSELL PORTER
		J. Russell Porter
		President and Chief Executive Officer
		(Duly authorized officer and principal executive officer)

Date: August 5, 2010	By:	/s/ MICHAEL A. GERLICH
		Michael A. Gerlich
		Vice President and Chief Financial Officer
		(Duly authorized officer and principal financial and accounting officer)

EXHIBIT INDEX


Exhibit Number		Description
3.1		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005. Registration No. 333-127498).
3.2		Articles of Amendment and Share Structure attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd., dated as of June 30, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 1, 2009. File No. 001-132714).
3.3		Articles of Amendment attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of July 23, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 24, 2009. File No. 001-132714).
3.4		Amended Bylaws of Gastar Exploration Ltd., dated as of June 3, 2010 (incorporated herein by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated June 4, 2010. File No. 001-32714).
10.1		Amended and Restated Credit Agreement dated October 28, 2009 by and among Gastar Exploration USA, Inc., the Guarantors party thereto, Amegy Bank National Association, as Administrative Agent and Letter of Credit Issuer, BMO Capital Markets Corp. as Co-Lead Arranger and Joint Bookrunner, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 3, 2009. File No. 001-32714).
10.2		Consent and First Amendment to Amended and Restated Credit Agreement dated November 20, 2009, by and among Gastar Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto, and Amegy Bank National Association, as Administrative Agent (incorporated herein by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated November 25, 2009. File No. 001-32714).
10.3		Second Amendment to Amended and Restated Credit Agreement dated June 24, 2010, by and among Gastar Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as Administrative Agent (incorporated herein by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated June 28, 2010. File No. 001-32714).
31.1†		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1††		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2††		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

†	Filed herewith.

††	Furnished herewith.

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