Gastar Exploration (GSTCQ) 10-Q 2010 Q3 Quarterly report

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 SEPTEMBER 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	(I.R.S. Employer Identification No.)
incorporation or organization)
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):

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

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 November 2, 2010 was 50,378,094.

GASTAR EXPLORATION LTD.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September  30, 2010 and 2009		2
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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		26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37
Item 4.	Controls and Procedures		37
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		38
Item 1A.	Risk Factors		38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		38
Item 3.	Defaults Upon Senior Securities		38
Item 4.	(Removed and Reserved)		38
Item 5.	Other Information		39
Item 6.	Exhibits		39
SIGNATURES			40

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 (“U.S. 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 (“U.S. GAAP”).

General information about us can be found on our website atwww.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 atwww.sec.gov for our United States filings.

i

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2010			December 31, 2009
	(Unaudited)
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,937		$	21,866
Term deposit		—			69,662
Accounts receivable, net of allowance for doubtful accounts of $577 and $609, respectively		2,954			5,336
Receivable from unproved property sale		—			19,412
Commodity derivative contracts		12,233			4,870
Prepaid expenses		269			669
Total current assets		22,393			121,815
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization		151,793			132,720
Proved properties		338,954			313,100
Total natural gas and oil properties		490,747			445,820
Furniture and equipment		1,032			867
Total property, plant and equipment		491,779			446,687
Accumulated depreciation, depletion and amortization		(290,094	)		(284,026	)
Total property, plant and equipment, net		201,685			162,661
OTHER ASSETS:
Restricted cash		50			50
Commodity derivative contracts		11,567			10,698
Deferred charges, net		567			764
Drilling advances and other assets		100			250
Total other assets		12,284			11,762
TOTAL ASSETS	$	236,362		$	296,238
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,127		$	8,291
Revenue payable		4,556			4,621
Accrued interest		167			130
Accrued drilling and operating costs		3,540			736
Commodity derivative contracts		3,263			3,678
Commodity derivative premium payable		3,024			1,190
Accrued litigation settlement liability		19,750			—
Short-term loan		—			17,000
Accrued taxes payable		—			75,887
Other accrued liabilities		1,706			1,438
Total current liabilities		39,133			112,971
LONG-TERM LIABILITIES:
Long-term debt		24,000			—
Commodity derivative contracts		2,141			4,047
Commodity derivative premium payable		5,838			8,176
Accrued litigation settlement liability		1,400			—
Asset retirement obligation		6,463			5,943
Warrant derivative		—			205
Total long-term liabilities		39,842			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; 50,378,094 and 50,028,592 shares issued and outstanding at September 30, 2010 and December 31, 2009, respectively		263,809			263,809
Additional paid-in capital		22,789			20,782
Accumulated deficit		(129,211	)		(119,695	)
Total shareholders' equity		157,387			164,896
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	236,362		$	296,238

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

1

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands, except share and per share data)
REVENUES:
Natural gas and oil revenues	$	8,657		$	7,553		$	22,152		$	32,976
Unrealized natural gas hedge gain (loss)		5,487			(3,290	)		13,893			(7,912	)
Total revenues		14,144			4,263			36,045			25,064
EXPENSES:
Production taxes		84			76			300			325
Lease operating expenses		1,549			1,759			5,206			5,085
Transportation, treating and gathering		1,165			172			3,508			990
Depreciation, depletion and amortization		2,673			2,954			6,068			14,314
Impairment of natural gas and oil properties		—			—			—			68,729
Accretion of asset retirement obligation		101			90			292			265
General and administrative expense		3,842			5,156			11,618			11,601
Litigation settlement expense		21,150			—			21,150			—
Total expenses		30,564			10,207			48,142			101,309
LOSS FROM OPERATIONS		(16,420	)		(5,944	)		(12,097	)		(76,245	)
OTHER INCOME (EXPENSE):
Interest expense		(22	)		(1,031	)		(120	)		(3,330	)
Early extinguishment of debt		—			(15,902	)		—			(15,902	)
Investment income and other		3			499			1,343			522
Gain on sale of assets		—			193,376			—			193,376
Unrealized warrant derivative gain (loss)		2			(495	)		205			(495	)
Foreign transaction gain		14			3,765			349			3,762
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES		(16,423	)		174,268			(10,320	)		101,688
Provision for income tax expense (benefit)		(12	)		65,776			(804	)		65,776
NET INCOME (LOSS)	$	(16,411	)	$	108,492		$	(9,516	)	$	35,912
NET INCOME (LOSS) PER SHARE:
Basic	$	(0.33	)	$	2.21		$	(0.19	)	$	0.80
Diluted	$	(0.33	)	$	2.21		$	(0.19	)	$	0.79
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		49,148,207			48,990,509			49,063,253			45,126,907
Diluted		49,148,207			49,107,492			49,063,253			45,243,890

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

2

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine Months  Ended September 30,
	2010			2009
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(9,516	)	$	35,912
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		6,068			14,314
Impairment of natural gas and oil properties		—			68,729
Stock-based compensation		2,352			2,767
Unrealized natural gas hedge (gain) loss		(13,893	)		7,912
Realized loss (gain) on derivative contracts		1,604			(2,605	)
Amortization of deferred financing costs and debt discount		220			1,635
Accretion of asset retirement obligation		292			265
Loss on early extinguishment of debt		—			7,027
Gain on sale of assets		—			(193,376	)
Unrealized warrant derivative (gain) loss		(205	)		495
Accrued litigation settlement liability		21,150			—
Changes in operating assets and liabilities:
Accounts receivable		2,847			5,215
Commodity derivative contracts		1,232			2,889
Prepaid expenses		400			497
Accrued taxes payable		(1,420	)		69,832
Accounts payable and accrued liabilities		(3,333	)		(8,821	)
Net cash provided by operating activities		7,798			12,687
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties		(43,588	)		(40,868	)
Drilling advances		—			(7,122	)
Proceeds from sale of natural gas and oil properties		19,199			229,541
Purchase of furniture and equipment		(165	)		(15	)
Purchase of term deposit		(4,855	)		(52,374	)
Net cash (used in) provided by investing activities		(29,409	)		129,162
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares		—			13,829
Repayment of 12 3/4 % senior secured notes		—			(100,000	)
Repayment of term loan		—			(25,000	)
Repayment of revolving credit facility		—			(18,875	)
Repayment of convertible senior unsecured subordinated debentures		—			(10,305	)
Repayment of subordinated unsecured notes		—			(3,250	)
Repayment of short-term loan		(17,000	)		—
Proceeds from term loan		—			25,000
Proceeds from revolving credit facility		24,000			—
Deferred financing charges		(22	)		(1,485	)
Other		(296	)		(298	)
Net cash provided by (used in) financing activities		6,682			(120,384	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(14,929	)		21,465
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		21,866			6,153
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	6,937		$	27,618

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

3

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 (“U.S.”). 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 U.S. dollars unless otherwise noted and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 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 U.S. GAAP.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved 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 to the current year presentation; these reclassifications have no impact on net income (loss).

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

4

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 Company is currently evaluating the impact of this guidance and does not expect its adoption to have a material impact on the Company’s operating results, financial position or 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. The adoption of this guidance did not impact the Company’s operating results, financial position or 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 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.

5

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 U.S. 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 nine months ended September 30, 2010 resulting in decreased depletion expense of approximately $77,000 and $62,000, 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, specifically the states of Montana, Pennsylvania, Texas, West Virginia and Wyoming.

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

	September 30, 2010		December 31, 2009
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	6,312	$	3,822
Acreage acquisition costs		127,441		111,042
Capitalized interest		18,040		17,856
Total unproved properties excluded from amortization	$	151,793	$	132,720

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.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Management’s ceiling test evaluation for the nine months ended September 30, 2010 did not result in an impairment of proved properties. The September 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 $4.41 per MMBtu. For the nine months ended September 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.

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.

As stated above, the Australian Assets included the Company’s interest in PEL 238, which is a CBM exploratory property covering approximately 2.2 million gross (761,400 net) acres in the Gunnedah Basin of New South Wales, as well as approximately 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.

The Australian Assets were sold for an aggregate purchase price of $232.6 million (AU$300.0 million), before transaction costs of $1.9 million, resulting in a gain on the sale of assets of $193.4 million and estimated Australian income taxes of $65.8 million as of September 30, 2009. Including gross reserve certification target proceeds, the Australian Assets were sold for an adjusted 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 12 ³/4% 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,

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

Amended and Restated 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 (as amended and restated, the “Revolving Credit Facility”). The Revolving Credit Facility provided an initial borrowing base of $47.5 million, with borrowings bearing interest, at 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, and then in October 2010 was returned to the initial borrowing base amount of $47.5 million. 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, excludingde 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 2010, 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 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, primarily in connection with previously announced delays in returning the Company’s Belin #1 Well, located in the Hilltop area of East Texas, to production following re-completion attempts. Subsequent to the redetermination of the borrowing base and entry into the Second Amendment, the Belin #1 Well was returned to production from all zones.

As of September 30, 2010, the Company had $24.0 million outstanding under the Revolving Credit Facility and the availability under the borrowing base was $16.0 million. On October 1, 2010, the borrowing base was increased to $47.5 million, increasing availability for borrowing to $23.5 million. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year, with the next redetermination scheduled for May 2011. 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 was in compliance with all other financial covenants under the Revolving Credit Facility at such time. The Company has been granted a waiver in regards to the hedge limitation through March 31, 2011 and in conjunction with such waiver, at September 30, 2010, the Company was in compliance with all financial covenants under the Revolving Credit Facility.

Credit support for the Company’s open derivatives at September 30, 2010 is provided through inter-creditor agreements or open accounts.

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 September 30, 2010, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at September 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 (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

– 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, index, basis and fixed price swaps, put and call options and warrants. 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.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 September 30, 2010 and December 31, 2009:

	Fair value as of September 30, 2010
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	6,937	$	—	$	—		$	6,937
Commodity derivative contracts		—		—		23,800			23,800
Liabilities:
Commodity derivative contracts		—		—		(5,404	)		(5,404	)
Total	$	6,937	$	—	$	18,396		$	25,333
	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 nine months ended September 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 September 30, 2010 and 2009.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands)
Balance at beginning of period	$	13,232		$	1,627		$	7,638		$	8,708
Total gains (losses) (realized or unrealized):
included in earnings		6,944			(1,568	)		16,147			3,422
included in other comprehensive income		—			—			—			—
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements		(1,780	)		(2,217	)		(5,389	)		(14,288	)
Transfers in and (out) of Level 3		—			—			—			—
Balance at end of period	$	18,396		$	(2,158	)	$	18,396		$	(2,158	)
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 September 30, 2010 and 2009	$	5,489		$	(3,785	)	$	14,098		$	(8,407	)

At September 30, 2010, the estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at September 30, 2010 approximates the respective carrying value because the interest rate approximates the current market rate.

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 nine months ended September 30, 2009, the Company reported gains of $497,000 and $2.2 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 nine months ended September 30, 2010, the Company reported unrealized gains of $5.5 million and $13.9 million, respectively, in the statement of operations related to the change in the fair value of its commodity

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

derivative instruments. For the three and nine months ended September 30, 2009, the Company reported unrealized losses of $3.3 million and $7.9 million, respectively, in the statement of operations related to the changes in fair value of its commodity derivative instruments

As of September 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		9,398		866,500	$	—		$	5.93	$	4.19	$	—
2010	Costless collar		8,595		789,000		—			6.31		4.43		7.58
2010	Basis - HSC (1)		12,500		1,150,500		(0.23	)		—		—		—
2010	Basis - CIG (2)		1,000		92,000		(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 September 30, 2010, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. Credit support for the Company’s open derivatives at September 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. The Company began amortizing the deferred put premium liabilities during the current quarter.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table provides information regarding the deferred put premium liabilities for the periods indicated:

	September 30, 2010		December 31, 2009
	(in thousands)
Current commodity derivative premium payable	$	3,024	$	1,190
Long-term commodity derivative premium payable		5,838		8,176
Total unamortized put premium liabilities	$	8,862	$	9,366

The following table provides information regarding the amortization of the deferred put premium liabilities by year as of the period indicated:

	September 30, 2010
	(in thousands)
October - December 2010	$	686
January - December 2011		3,451
January - December 2012		4,725
Total unamortized put premium liabilities	$	8,862

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 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 $0 as of September 30, 2010, and the Company recognized $2,000 and $205,000 in unrealized gains in other income for the change in fair value of these warrants for the three and nine months ended September 30, 2010, respectively.

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

Warrants Outstanding	Fair Value (in thousands)	Weighted Price per Share Range	Average Remaining Life in Years	Average Exercise Price
2,000,000	$     —	(1)	1.2	(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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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	September 30, 2010			December 31, 2009
Derivatives not designated as hedging instruments		(in thousands)
Commodity derivative contracts	Current assets	$	12,233		$	4,870
Commodity derivative contracts	Other assets		11,567			10,698
Commodity derivative contracts	Current liabilities		(3,263	)		(3,678	)
Commodity derivative contracts	Long-term liabilities		(2,141	)		(4,047	)
Warrant derivative	Long-term liabilities		—			(205	)
Total derivatives not designated as hedging instruments		$	18,396		$	7,638
	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	September 30, 2010			September 30, 2009
Derivatives not designated as hedging instruments		(in thousands)
Commodity derivative contracts	Unrealized natural gas hedge gain (loss)	$	5,487		$	(3,290	)
Warrant derivative	Unrealized warrant derivative gain (loss)		2			(495	)
Total		$	5,489		$	(3,785	)
	Amount of Gain (Loss) Recognized in Income on Derivatives
		Amount of Gain (Loss) Recognized in Income on Derivatives For the Nine Months Ended
	Location of Gain (Loss) Recognized in Income on Derivatives	September 30, 2010			September 30, 2009
Derivatives not designated as hedging instruments		(in thousands)
Commodity derivative contracts	Unrealized natural gas hedge gain (loss)	$	13,893		$	(7,912	)
Warrant derivative	Unrealized warrant derivative gain (loss)		205			(495	)
Total		$	14,098		$	(8,407	)

8. Capital Stock

Common Shares

The Company’s Board of Directors approved a 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. At September 30, 2010, there were preferred shares issued or outstanding.

Other Share Issuances

The following table provides information regarding the issuances and forfeitures of common shares pursuant to the Company’s 2006 Long-Term Incentive Plan for the periods indicated:

	For the Three Months Ended September 30, 2010		For the Nine Months Ended September 30, 2010
Other share issuances:
Restricted common shares granted		40,500		440,550
Restricted common shares vested and issued		142,098		221,737
Common shares forfeited (1)		56,344		91,048

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

Shares Reserved

The following table summarizes the components of common shares reserved at September 30, 2010:

Common shares reserved for the:
Exercise of stock options	1,110,100
Exercise of warrants	2,000,000
Total common shares reserved	3,110,100

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. Interest Expense

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands)
Interest expense:
Cash and accrued	$	145		$	2,143		$	335		$	12,416
Amortization of deferred financing costs and debt discount		63			227			220			1,635
Capitalized interest		(186	)		(1,339	)		(435	)		(10,721	)
Total interest expense	$	22		$	1,031		$	120		$	3,330
Early extinguishment of debt:
Call premium	$	—		$	8,875		$	—		$	8,875
Unamortized deferred financing costs and debt discount		—			7,027			—			7,027
Total debt extinguishment expense	$	—		$	15,902		$	—		$	15,902

10. Related Party Transactions

Chesapeake Energy Corporation

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 September 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” of this report.

11. Income Taxes

For the three and nine months ended September 30, 2010, the Company recognized a current income tax benefit of $12,000 and $804,000, respectively. The current quarter income tax benefit represents a benefit for state income taxes. The income tax benefit for the nine month period ended September 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2010			2009		2010			2009
	(in thousands, except per share and share data)
Net income (loss)	$	(16,411	)	$	108,492	$	(9,516	)	$	35,912
Weighted average common shares outstanding - basic		49,148,207			48,990,509		49,063,253			45,126,907
Incremental shares from outstanding stock options		—			116,983		—			116,983
Weighted average common shares outstanding - diluted		49,148,207			49,107,492		49,063,253			45,243,890
Income (loss) per common share:
Basic	$	(0.33	)	$	2.21	$	(0.19	)	$	0.80
Diluted	$	(0.33	)	$	2.21	$	(0.19	)	$	0.79
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares		179,028			1,039,324		120,008			1,039,324
Stock options		867,800			1,175,317		948,774			1,175,317
Warrants		2,000,000			2,000,000		2,000,000			2,000,000
Convertible subordinated debentures		—			899,315		—			899,315
Total		3,046,828			5,113,956		3,068,782			5,113,956

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, Texas12th 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.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Both motions are pending at this time. The Company has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Both motions are pending at this time. The suit is set for trial beginning in April 2011. The Company has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Both motions are pending at this time. The Company has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 personal and subject matter jurisdiction. On June 14, 2010, the Company filed a motion for summary judgment against the plaintiffs. Both motions are pending at this time. The Company has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. 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 seek findings regarding the amount(s) of damages for which the defendants may be liable. The Company’s motion to dismiss and the trustee’s motion for summary judgment are pending at this time and discovery is proceeding. On September 27, 2010, the Company filed a motion for summary judgment against the trustee. Briefing is not yet complete on the motion. The court has scheduled a trial of the matter to begin in April 2011. The Company has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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 has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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. On August 6, 2010, the Company filed a motion for summary judgment against the plaintiffs. Both motions are pending at this time. The Company has entered into a letter of intent to settle this matter as described in the final paragraph of this footnote.

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,

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

LTD were served as third-party defendants 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 (“JOA”), between First Source Texas, Inc., as operator, and Navasota Resources, Inc. and Kentex Energy, LLC (Midway’s predecessor in interest). Under the Area of Mutual Interest (“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 interests 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 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. The Company has answered the lawsuit and discovery is proceeding.

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. With respect to theNavasota Resources, Tillotson and Midway Land & Developmentmatters, 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. With respect to the sevenIn re ClassicStar Mare Lease Litigationmatters listed above (collectively, “ClassicStar Mare Lease Litigation”), the Company commenced negotiations in late September 2010 to address the potential resolution of each of the matters. On October 26-27, 2010, the Company signed a letter of intent with representatives of the plaintiffs outlining a proposed settlement agreement with the plaintiffs in these matters to resolve their claims. The proposed settlement is subject to the execution of definitive documents and when complete, will be contingent upon approval of the bankruptcy court overseeing the Chapter 7 liquidation of ClassicStar, LLC, the United States Bankruptcy Court for the Eastern District of Kentucky (“Bankruptcy Court”). If the settlement is finalized and approved as proposed, the Company would pay to the plaintiffs an aggregate of $21.2 million in cash, including an initial $18.0 million payment to be paid late fourth quarter of 2010 and the remaining $3.2 million as a non-interest bearing payment obligation consisting of sixteen monthly payments, the first of which shall be $150,000 and the next fifteen of which shall be $200,000 each, in exchange for dismissal of the plaintiffs’ claims in all seven cases. As a result of the signed letter of intent and in accordance with accounting guidance, the Company recorded $21.2 million in litigation settlement expense in the Condensed Consolidated Statement of Operations for the three and nine months ended September 30, 2010 and short-term and long-term accrued litigation settlement liabilities of $19.8 million and $1.4 million, respectively, on the Condensed Consolidated Balance Sheet at September 30, 2010.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 Nine Months Ended September 30,
	2010		2009
	(in thousands)
Cash paid for interest	$	303	$	13,659
Cash paid for taxes		615		—
Non-cash transactions:
Term deposit surrendered for accrued taxes	$	70,446	$	—
Capital expenditures excluded from accounts payable and accrued costs		961		(6,756	)
Asset retirement obligation included in natural gas and oil properties		228		272
Drilling advances application		150		9,345

15. Comprehensive Income (Loss)

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

	For the Nine Months Ended September 30,
	2010			2009
	(in thousands)
Net (loss) income	$	(9,516	)	$	35,912
Change in:
Commodity hedging activities – current period reclassification to earnings		—			(2,181	)
Foreign currency translation adjustments		—			(19	)
Comprehensive income	$	(9,516	)	$	33,712

16. Subsequent Events

Atinum Joint Venture

On September 21, 2010, the Company entered into a purchase and sale agreement with Atinum Marcellus I LLC (“Atinum”), an affiliate of Atinum Partners Co., Ltd, a Korean investment firm (the “Atinum Joint Venture”). Pursuant to the agreement, at the closing of the transactions on November 1, 2010, the Company assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consists of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well, in a transaction valued at $70.0 million. Atinum paid the Company approximately $30.0 million in cash at the closing and will pay an additional $40.0 million over time to cover a portion of the Company’s drilling costs (“drilling carry”). Upon completion of the funding of the drilling carry, the Company will make additional assignments to Atinum, as necessary, so Atinum will own a 50% interest in the 34,200 net acres of Marcellus Shale rights currently owned by the Company.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The terms of the drilling carry require Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of the Company’s ultimate 50% share of those same costs until the $40.0 million drilling carry has been satisfied. The Company and Atinum are pursuing an initial three-year development program that calls for the partners to drill one horizontal Marcellus Shale well during the remainder of 2010 and a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. An initial AMI will be established for potential additional acreage acquisitions in Ohio and New York along with the counties in West Virginia and Pennsylvania in which the existing Atinum Joint Venture interests are located. Within the initial AMI, the Company will act as operator and is obligated to offer any future AMI lease acquisitions to Atinum on a 50/50 basis, and Atinum will pay the Company on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. Until June 30, 2011, Atinum will have the right to participate in any future leasehold acquisitions made by the Company outside of the initial AMI and within West Virginia or Pennsylvania on terms identical to those governing the existing Atinum Joint Venture.

ClassicStar Mare Lease Litigation Settlement

On October 26-27, 2010, the Company signed a letter of intent with representatives of the ClassicStar Mare Lease Litigation plaintiffs outlining a proposed settlement agreement with the plaintiffs in these matters to resolve their claims. The proposed settlement is subject to the execution of definitive documents and when complete, will be contingent upon approval of the Bankruptcy Court. If the settlement is finalized and approved as proposed, the Company would pay to the plaintiffs an aggregate of $21.2 million in cash, including an initial $18.0 million payment to be paid late fourth quarter of 2010 and the remaining $3.2 million as a non-interest bearing payment obligation consisting of sixteen monthly payments, the first of which shall be $150,000 and the next fifteen of which shall be $200,000 each, in exchange for dismissal of the plaintiffs’ claims in all seven cases. As a result of the signed letter of intent and in accordance with accounting guidance, the Company recorded $21.2 million in litigation settlement expense in the Condensed Consolidated Statement of Operations for the nine months ended September 30, 2010 and short-term and long-term litigation settlement liabilities of $19.8 million and $1.4 million, respectively, on the Condensed Consolidated Balance Sheet at September 30, 2010.

25

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;

• Business strategy and budgets;

• Anticipated capital expenditures;

• Drilling of wells;

• Natural gas and oil reserves;

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

• Operating costs and other expenses;

• Cash flow and anticipated liquidity;

• Prospect development; and

• Property acquisitions and sales.

Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. 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:

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

• Demand for natural gas and oil;

• Natural gas and oil price volatility;

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

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

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

• 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;

• Operating hazards inherent to the natural gas and oil business;

• 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;

• Adverse weather conditions;

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

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

• Delays in anticipated start-up dates;

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

• Ability to find and retain skilled personnel;

�� Strength and financial resources of competitors;

• Potential defects in title to our properties;

• Federal and state regulatory developments and approvals;

• Losses possible from pending or future litigation;

• Environmental risks; and

• 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”.

The following discussion addresses material changes in our results of operations for the three and nine months ended September 30, 2010 compared to the three and nine months ended September 30, 2009 and material changes in our financial condition since December 31, 2009. It should be read in conjunction with our 2009 Form 10-K, which includes as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations, disclosures regarding critical accounting policies.

Recent Developments

ClassicStar Mare Lease Litigation Settlement.On October 26-27, 2010, we signed a letter of intent with representatives of the ClassicStar Mare Lease Litigation plaintiffs outlining a proposed settlement agreement where we would pay to the plaintiffs an aggregate of $21.2 million in cash, including an initial $18.0 million payment to be paid late fourth quarter of 2010 and the remaining $3.2 million as a non-interest bearing payment obligation consisting of sixteen monthly payments, the first of which shall be $150,000 and the next fifteen of which shall be $200,000 each, in exchange for dismissal of the plaintiffs’ claims in all seven cases. The proposed settlement is contingent upon approval of the Bankruptcy Court. We recorded $21.2 million in litigation settlement expense in the Statement of Operations for the nine months ended September 30, 2010 and short-term and long-term litigation settlement liabilities of $19.8 million and $1.4 million, respectively, on the Balance Sheet at September 30, 2010.

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Atinum Joint Venture.On September 21, 2010, we entered into a purchase and sale agreement with Atinum, an affiliate of Atinum Partners Co., Ltd, a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, we assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consists of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well, in a transaction valued at $70.0 million. Atinum paid us approximately $30.0 million in cash at the closing and will pay an additional $40.0 million over time for a drilling carry. Upon completion of the funding of the drilling carry, we will make additional assignments to Atinum, as necessary, so Atinum will own a 50% interest in the 34,200 net acres of Marcellus Shale rights currently owned by us.

The terms of the drilling carry require Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of our ultimate 50% share of those same costs until the $40.0 million drilling carry has been satisfied. We and Atinum are pursuing an initial three-year development program that calls for the partners to drill one horizontal Marcellus Shale well during the remainder of 2010, a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. An initial AMI will be established for potential additional acreage acquisitions in Ohio and New York along with the counties in West Virginia and Pennsylvania in which the existing Atinum Joint Venture interests are located. Within the initial AMI, we will act as operator and are obligated to offer any future AMI lease acquisitions to Atinum on a 50/50 basis, and Atinum will pay us on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. Until June 30, 2011, Atinum will have the right to participate in any future leasehold acquisitions made by us outside of the initial AMI and within West Virginia or Pennsylvania on terms identical to those governing the existing Atinum Joint Venture.

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 September 30, 2010, our acreage position in the play was approximately 33,600 gross (17,900 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 produced at a gross sales rate of 10.0 MMcf per day. The B-5 zone was produced until the reservoir pressures equalized and, on August 26, 2010, the B-5 and B-6 zones were co-mingled and returned to sales. During the three months ended September 30, 2010, the average daily comingled production was 10.1 MMcf per day. Three additional zones remain to be completed at future dates. As of September 30, 2010, our net cost incurred to drill and initially complete the Donelson #4 well, net of estimated reimbursement under existing well control insurance policies, is approximately $9.8 million. 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

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amounts of formation sand. It appears that the formation sand production coincided with a casing failure at approximately 16,700 feet. We successfully milled through and subsequently repaired the damaged portion of the casing and returned the well to production in late June 2010. During the three months ended September 30, 2010, the well produced at an average gross sales rate of 7.0 MMcf per day. Gastar has a 50% before payout working interest and an approximate 37% before payout net revenue interest in the well.

In August 2010, we began drilling the Streater #1 well, a middle Bossier well. This well was successfully completed in a single middle Bossier zone at a depth of 17,800 feet during September 2010. For the first 31 days after completion, the well produced at an average gross sales rate of 8.2 MMcf per day. We plan to complete this well in two additional zones once the current reservoir pressure declines from its current pressure of 5,565 psi. We have a 100% before payout working interest (approximately 76% before payout net revenue interest) in the well.

For the three and nine months ended September 30, 2010, net production from the Hilltop area averaged 20.1 MMcfe per day and 16.9 MMcfe per day, respectively. Current quarter average production increased 6.5 MMcfe per day compared to average production of 13.6 MMcfe per day for the second quarter of 2010.

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 September 30, 2010, our acreage position in the play was approximately 37,600 gross (34,200 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.

On September 21, 2010, we entered into a purchase and sale agreement to form a joint venture with Atinum. Pursuant to the agreement and upon closing on November 1, 2010, we assigned an initial 21.43% interest in all of our existing Marcellus Shale assets in West Virginia and Pennsylvania, which consists of approximately 34,200 net acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well, to Atinum for $70.0 million. Atinum paid us approximately $30.0 million in cash upon closing and will pay an additional $40.0 million over time to cover a drilling carry. Upon completion of the funding of the drilling carry, we will make additional assignments, as necessary, to Atinum as a result of which Atinum will own a 50% interest in the 34,200 net acres of Marcellus Shale rights currently owned by us.

The terms of the drilling carry require Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of our ultimate 50% share of those same costs until the $40.0 million drilling carry has been satisfied. We are pursuing an initial three-year development program that calls for the partners to drill one horizontal Marcellus Shale well during the remainder of 2010 and a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. An initial AMI will be established for potential additional acreage acquisitions in Ohio and New York along with the counties in West Virginia and Pennsylvania in which the existing Atinum Joint Venture interests are located. Within the initial AMI, we will act as operator and are obligated to offer any future lease acquisitions to Atinum on a 50/50 basis, and Atinum will pay us on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. Until June 30, 2011, Atinum will have the right to participate in any future leasehold acquisitions made by us outside of the initial AMI and within West Virginia or Pennsylvania on terms identical to those governing the existing Atinum Joint Venture.

During the nine months ended September 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, fifteen wells are on production and one is awaiting a pipeline connection.

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For the three and nine months ended September 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 43,400 gross (19,600 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 2.0 MMcfe per day for each of the three and nine months ended September 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 September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Production:
Natural gas (MMcf)		2,063		2,139		5,243		7,155
Oil (MBbl)		3		1		7		3
Total production (MMcfe)		2,082		2,145		5,285		7,175
Total (MMcfed)		22.6		23.3		19.4		26.3
Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities	$	3.39	$	2.46	$	3.74	$	2.93
Natural gas per Mcf, including impact of realized hedging activities		4.09		3.50		4.13		4.58
Oil per Bbl		68.47		61.97		70.59		51.29
Selected operating expenses (in thousands):
Production taxes	$	84	$	76	$	300	$	325
Lease operating expenses		1,549		1,759		5,206		5,085
Transportation, treating and gathering		1,165		172		3,508		990
Depreciation, depletion and amortization		2,673		2,954		6,068		14,314
General and administrative expense		3,842		5,156		11,618		11,601
Selected operating expenses per Mcfe:
Production taxes	$	0.04	$	0.04	$	0.06	$	0.05
Lease operating expenses		0.74		0.82		0.99		0.71
Transportation, treating and gathering		0.56		0.08		0.66		0.14
Depreciation, depletion and amortization		1.28		1.38		1.15		1.99
General and administrative expense		1.85		2.40		2.20		1.62

Three Months Ended September 30, 2010 compared to the Three Months Ended September 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 $8.7 million for the three months ended September 30, 2010, up from $7.6 million for the three months ended September 30, 2009. The increase in revenues was the result of an 18% increase in prices partially offset by a 3% decrease in volumes. Average daily production on an equivalent basis was 22.6 MMcfe per day for the three months ended September 30, 2010 compared to 23.3 MMcfe per day for the same period in 2009.

During the three months ended September 30, 2010, approximately 79% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $1.5 million in natural gas and oil revenues resulting in an increase in total price realized from $3.39 per Mcf to $4.09 per Mcf. The realized hedge impact includes a benefit of $159,000 for amortization of prepaid put purchase and call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $1.3 million comprised of

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$2.1 million of NYMEX hedge gains offset by $275,000 of regional basis losses and deferred put premiums of $484,000. For the remainder of 2010, we have costless collar hedges for approximately 8,600 MMBtu per day representing approximately 39% of our estimated future natural gas production with a weighted average floor of $6.31, short put of $4.43 and a ceiling of $7.58. In addition, we have put spread hedges for approximately 9,400 MMBtu per day representing approximately 42% of our estimated future natural gas production with a weighted average floor of $5.93 and a short put of $4.19.

Unrealized natural gas hedge gain was $5.5 million for the three months ended September 30, 2010 compared to an unrealized natural gas hedge loss of $3.3 million for the three months ended September 30, 2009. The increase in unrealized natural gas hedge impact was the result of additional hedged volumes and the hedge benefit as a result of lower future NYMEX gas prices partially offset by losses related to projected basis differentials.

Production taxesWe reported production taxes of $84,000 for the three months ended September 30, 2010 compared to $76,000 for the three months ended September 30, 2009. The increase in production taxes was primarily the result of higher oil revenues in Texas.

Lease operating expenses.We reported lease operating expenses of $1.5 million for the three months ended September 30, 2010 down from $1.8 million for the three months ended September 30, 2009. This decrease was primarily due to a $270,000 decrease in ad valorem taxes and an $89,000 decrease in lease operating expense partially offset by a $137,000 increase in workover expenses. Our lease operating expenses were $0.74 per Mcfe for the three months ended September 30, 2010 compared to $0.82 per Mcfe for the same period in 2009. The decrease in the rate per Mcfe was primarily due to lower ad valorem taxes of $0.12 per Mcfe partially offset by higher workover costs of $0.07 per Mcfe and lower production volumes.

Transportation, treating and gathering.We reported transportation expenses of $1.2 million for the three months ended September 30, 2010 up from $172,000 for the three months ended September 30, 2009. This increase was primarily due to gathering charges in Texas under the Hilltop Gathering Agreement, effective November 2009 in conjunction with the sale of our Hilltop Gathering System. The current quarter included a true up charge under the Hilltop Gathering Agreement based on a minimum volume requirement of $236,000.

Depreciation, depletion and amortization.We reported depreciation, depletion and amortization (“DD&A”) expense of $2.7 million for the three months ended September 30, 2010 down from $3.0 million for the three months ended September 30, 2009. The decrease in DD&A expense was the result of a 7% decrease in the DD&A rate per Mcfe and a 3% decrease in production. The DD&A rate for the three months ended September 30, 2010 was $1.28 per Mcfe compared to $1.38 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 system sales proceeds credited to proved property costs in late 2009.

General and administrative.We reported general and administrative expenses of $3.8 million for the three months ended September 30, 2010 down from $5.2 million for the three months ended September 30, 2009. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $713,000 and $633,000 for the three months ended September 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 decreased $1.4 million to $3.1 million for the three months ended September 30, 2010 compared to September 30, 2009. This decrease is primarily due to a $612,000 decrease in personnel and contract labor expense and a $1.1 million decrease in bonuses due to the 2009 payment of one-time bonuses related to the sale of the Australian Assets partially offset by a $413,000 increase in legal expense.

Litigation settlement expense.We reported litigation settlement expense of $21.2 million for the three months ended September 30, 2010 in conjunction with the signing of the letter of intent, which outlined a proposed settlement agreement, with the plaintiffs of the ClassicStar Mare Lease Litigation. The proposed settlement is contingent upon Bankruptcy Court approval.

Interest expense.We reported interest expense of $22,000 for the three months ended September 30, 2010 compared to $1.0 million for the three months ended September 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.

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Early extinguishment of debt.In conjunction with the repayment of our original revolving credit facility, the term loan and the 12 ³/4% senior secured notes during the third quarter of 2009, we reported debt extinguishment expense of $15.9 million for the three months ended September 30, 2009, comprised of $8.9 million of an early prepayment penalty on the term loan and the 12 ³/4% senior secured notes and $7.0 million of unamortized deferred financing costs on the debt retired. There were no such expenses during the three months ended September 30, 2010.

Investment income and other. We reported investment income of $3,000 for the three months ended September 30, 2010 compared to $499,000 for the three months ended September 30, 2009. The decrease in investment income is primarily due to the three months ending September 30, 2009 including 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 and thus resulting in no comparable investment income for the three months ended September 30, 2010.

Gain on sale of assets.In July 2009, we sold our non-producing Australian assets for approximately $232.6 million, before transaction costs of approximately $1.9 million, resulting in a net gain on sale of assets of $193.4 million for the three months ended September 30, 2009.

Warrant derivative gain (loss).For the three months ended September 30, 2010 and 2009, we reported a $2,000 unrealized gain and a $495,000 unrealized loss, respectively, related to the fair value measurement of our warrants outstanding.

Foreign transaction gain.We reported a foreign transaction gain of $14,000 for the three months ended September 30, 2010 compared to a gain of $3.8 million for the three months ended September 30, 2009. The decrease in the foreign transaction gain is primarily due to the decrease in Australian denominated cash and accounts receivable balances arising from the sale of the Australian properties.

Provision for income tax expense (benefit). We reported $12,000 of income tax benefit for the three months ended September 30, 2010 compared to $65.8 million of income tax expense for the three months ended September 30, 2009. The 2009 income tax expense resulted from the gain on sale of the Australian assets. The 2010 income tax benefit is primarily due to a benefit for state income taxes.

Nine Months Ended September 30, 2010 compared to the Nine Months Ended September 30, 2009

Revenues.Natural gas and oil revenues were $22.2 million for the nine months ended September 30, 2010, down from $33.0 million for the nine months ended September 30, 2009. The decrease in revenues was the result of a 26% decrease in volumes and a 9% decrease in prices. Average daily production on an equivalent basis was 19.4 MMcfe per day for the nine months ended September 30, 2010 compared to 26.3 MMcfe per day for the same period in 2009. Of the decrease in volumes, 80% 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. The remaining 20% decrease in volumes was due to lower Wyoming production.

During the nine months ended September 30, 2010, approximately 105% of our natural gas production was hedged, of which only 49% had ceiling limitations. The realized effect of hedging on natural gas sales was an increase of $2.0 million in natural gas and oil revenues resulting in an increase in total price received from $3.74 per Mcf to $4.13 per Mcf. The realized hedge impact includes a reduction of $1.6 million for amortization of prepaid put purchase and call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $3.6 million comprised of $5.4 million of NYMEX hedge gains offset by $1.3 million of regional basis losses and deferred put premiums of $484,000.

Unrealized natural gas hedge income was $13.9 million for the nine months ended September 30, 2010 compared to an unrealized natural gas hedge loss of $7.9 million for the nine months ended September 30, 2009.

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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 taxesWe reported production taxes of $300,000 for the nine months ended September 30, 2010 compared to $325,000 for the nine months ended September 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 $5.2 million for the nine months ended September 30, 2010 up from $5.1 million for the nine months ended September 30, 2009. This increase was primarily due to a $429,000 increase in workover expenses partially offset by a $152,000 decrease in lease operating expense and a $185,000 decrease in ad valorem taxes. Our lease operating expenses were $0.99 per Mcfe for the nine months ended September 30, 2010 compared to $0.71 per Mcfe for the same period in 2009. The increase in the rate per Mcfe was primarily due to lower production volumes resulting in an increase in lease operating expenses of $0.16 per Mcfe combined with an increase of workover costs of $0.10 per Mcfe.

Transportation, treating and gathering.We reported transportation expenses of $3.5 million for the nine months ended September 30, 2010 up from $990,000 for the nine months ended September 30, 2009. This increase was primarily due to gathering charges in Texas under the Hilltop Gathering Agreement, effective November 2009 in conjunction with the sale of our Hilltop Gathering System, partially offset by lower costs in Wyoming. The nine months ended September 30, 2010 included cumulative quarterly true up charges under the Hilltop Gathering Agreement based on a minimum volume requirement of $1.2 million.

Depreciation, depletion and amortization.We reported DD&A expense of $6.1 million for the nine months ended September 30, 2010 down from $14.3 million for the nine months ended September 30, 2009. The decrease in DD&A expense was the result of a 42% decrease in the DD&A rate per Mcfe and a 26% decrease in production. The DD&A rate for the nine months ended September 30, 2010 was $1.15 per Mcfe compared to $1.99 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 nine months ended September 30, 2010 due to 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 nine months ended September 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 $11.6 million for each of the nine months ended September 30, 2010 and 2009, respectively. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $2.3 million and $2.8 million for the nine months ended September 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 $432,000 to $9.3 million for the nine months ended September 30, 2010 compared to September 30, 2009. This increase is primarily due to higher legal costs of $1.9 million related to ongoing litigation matters and the payment of 2008 management bonuses in restricted common shares rather than in cash partially offset by a $1.1 million decrease in bonus expense due to a one-time bonus paid in 2009 in conjunction with the sale of the Australian Assets and lower contract labor expense.

Litigation settlement expense.We reported litigation settlement expense of $21.2 million for the nine months ended September 30, 2010 in conjunction with the signing of the letter of intent with the plaintiffs of the ClassicStar Mare Lease Litigation which outlined a proposed settlement agreement. The proposed settlement is contingent upon Bankruptcy Court approval.

Interest expense.We reported interest expense of $120,000 for the nine months ended September 30, 2010 compared to $3.3 million for the nine months ended September 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.

Early extinguishment of debt.In conjunction with the repayment of our original revolving credit facility, the term loan and the 12  ³/4% senior secured notes during the third quarter of 2009, we reported debt extinguishment

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expense of $15.9 million for the nine months ended September 30, 2009, comprised of $8.9 million of an early prepayment penalty on the term loan and the 12 ³/4% senior secured notes and $7.0 million of unamortized deferred financing costs on the debt retired. There were no such expenses during the nine months ended September 30, 2010.

Investment income and other. We reported investment income of $1.3 million for the nine months ended September 30, 2010 compared to $522,000 for the nine months ended September 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.

Gain on sale of assets.In July 2009, we sold our non-producing Australian assets for approximately $232.6 million, before transaction costs of approximately $1.9 million, resulting in a gain on sale of assets of $193.4 million for the nine months ended September 30, 2009.

Warrant derivative gain (loss).For the nine months ended September 30, 2010 and 2009, we reported a $205,000 unrealized gain and a $495,000 unrealized loss, respectively, related to the fair value measurement of our warrants outstanding.

Foreign transaction gain.We reported a foreign transaction gain of $349,000 for the nine months ended September 30, 2010 compared to a foreign transaction gain of $3.8 million for the nine months ended September 30, 2009. The decrease in the foreign transaction gain was primarily due to Australian exchange rate fluctuations and a decrease in our Australian denominated cash and accounts receivable balances arising from the sale of the Australian properties.

Provision for income tax expense (benefit). We reported $804,000 of income tax benefit for the nine months ended September 30, 2010 compared to income tax expense of $65.8 million related to the gain on sale of Australian assets for the nine months ended September 30, 2009. The income tax benefit for the nine months ended September 30, 2010 is 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 and a benefit for state income taxes. 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 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.

With the closing of the Atinum Joint Venture and a proposed settlement to the ClassicStar Mare Lease Litigation, we believe we are in a better position to execute our business plan. Subject to definitive documents and approval by the Bankruptcy Court, the ClassicStar Mare Lease Litigation settlement will remove significant uncertainty surrounding our commitments and contingencies and will reduce our ongoing general and administrative expenses in the future. The Atinum Joint Venture will allow us to accelerate the development of our Marcellus Shale assets. Should the ClassicStar Mare Lease Litigation settlement not be completed, the proposed settlement payments would not be remitted and we would continue to incur legal expenses to defend this matter.

For the nine months ended September 30, 2010, we reported cash flows provided by operating activities of $7.8 million, net cash used in investing activities of $29.4 million and net cash provided by financing activities of $6.7 million. As a result of these activities, our cash and cash equivalents balance decreased by $14.9 million, resulting in a September 30, 2010 cash and cash equivalents balance of $6.9 million.

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At September 30, 2010, we had a net working capital deficit of approximately $16.7 million, including $19.8 million of accrued litigation settlement liability. Currently, the availability under the Revolving Credit Facility is $23.5 million.

Future capital and other expenditure requirements.Capital expenditures for the remainder of 2010 are projected to be approximately $12.8 million, consisting of $10.4 million in East Texas, $1.5 million in Appalachia in the Marcellus Shale, $200,000 in the Powder River Basin and an additional $700,000 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, additional debt or equity issuances or 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. Under the terms of the Atinum Joint Venture, Atinum is required to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of our ultimate 50% share of those same costs until the $40.0 million drilling carry has been satisfied, thus reducing our future capital expenditures related to our Marcellus Shale assets.

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” of this report.

At September 30, 2010, the estimated fair value of all of our commodity derivative instruments was a net asset of $18.4 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 September 30, 2010, we had a current commodity derivative premium payable of $3.0 million and a long-term commodity derivative premium payable of $5.8 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 September 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 September 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 September 30, 2010, we had $24.0 million outstanding under the Revolving Credit Facility compared to our December 31, 2009 outstanding balance of zero. The increase in our long-term debt balance is associated with expenditures for the development and purchase of natural gas and oil properties during the nine months ended September 30, 2010 of $43.6 million. Our borrowing base was $40.0 million at September 30, 2010 based on the results of the May 2010 redetermination, which became effective with the Second Amendment to our Revolving Credit Facility on June 24, 2010. The most recent redetermination was completed during September 2010 and became effective on October 1, 2010 and resulted in an increase in our borrowing base from $40.0 million

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to $47.5 million primarily in connection with the Belin #1 Well returning to production, the recent completion of 3 zones and the drilling of new wells. Borrowings under the Revolving Credit 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 $23.5 million.

At June 30, 2010, we were not in compliance with the 80% hedge limitation for 2011 under the Revolving Credit Facility; we were in compliance with all other financial covenants under the Revolving Credit Facility at such time. We have been granted a waiver in regards to the hedge limitation through March 31, 2011 and in conjunction with such waiver, at September 30, 2010, we were in compliance with all financial covenants under the Revolving Credit Facility. See Part I, Item 1. “Financial Statements, Note 5 – Long-Term Debt” of this report.

Off-Balance Sheet Arrangements

As of September 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.

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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 nine months ended September 30, 2010, a 10% change in the prices received for natural gas production (before hedging activities) would have had an approximate $2.0 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” of this report for additional information regarding our hedging activities.

Interest Rate Risk

At September 30, 2010, we had $24.0 million outstanding under our Revolving Credit Facility. Based on the amount outstanding under our revolving credit facility at September 30, 2010, a one percentage point change in the interest rate would have had a $240,000 impact on our interest expense. 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 U.S. 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 September 30, 2010. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of September 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.

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2010 that has materially affected , or is reasonably likely to materially affect, our internal control over financial reporting.

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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” of this report.

Item 1A. Risk Factors

Information about material risks related to our business, financial condition and results of operations for the nine months ended September 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 U.S. 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 U.S. 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)

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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. 001-32714).
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. 001-32714).
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).
10.4	Purchase and Sale Agreement, dated September 21, 2010, by and between Gastar Exploration USA, Inc. and Atinum Marcellus I LLC (incorporated herein by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated September 24, 2010. File No. 001-32714).
10.5	Form of Participation Agreement (incorporated herein by reference to Exhibit 2.2 of the Company's Current Report on Form 8-K dated September 24, 2010. File No. 001-32714).
10.6	Form of the Final Settlement Agreement and Comprehensive General Release between and among James D. Lyon, Chapter 7 Trustee of ClassicStar LLC, Gastar Exploration Ltd., and Other Individuals and Entities Set Forth Herein effective November 1, 2010 (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 2, 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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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: November 4, 2010	By:	/S/    J. RUSSELL PORTER
		J. Russell Porter President and Chief Executive Officer (Duly authorized officer and principal executive officer)

Date: November 4, 2010	By:	/S/    MICHAEL A. GERLICH
		Michael A. Gerlich Vice President and Chief Financial Officer (Duly authorized officer and principal financial and accounting officer)

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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. 001-32714).
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. 001-32714).
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).
10.4	Purchase and Sale Agreement, dated September 21, 2010, by and between Gastar Exploration USA, Inc. and Atinum Marcellus I LLC (incorporated herein by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated September 24, 2010. File No. 001-32714).
10.5	Form of Participation Agreement (incorporated herein by reference to Exhibit 2.2 of the Company's Current Report on Form 8-K dated September 24, 2010. File No. 001-32714).
10.6	Form of the Final Settlement Agreement and Comprehensive General Release between and among James D. Lyon, Chapter 7 Trustee of ClassicStar LLC, Gastar Exploration Ltd., and Other Individuals and Entities Set Forth Herein effective November 1, 2010 (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 2, 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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