Edgar Filing: GASTAR EXPLORATION LTD

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q for quarterly period ended September 30, 2011

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, 2011

¨	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.

GASTAR EXPLORATION USA, INC.

(Exact name of registrant as specified in its charter)


Alberta, Canada		98-0570897
Delaware		38-3531640
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1331 Lamar Street, Suite 650
Houston, Texas 77010		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 x 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.

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 1, 2011 was:


Gastar Exploration Ltd.		64,696,930 shares of common stock
Gastar Exploration USA, Inc.		750 shares of common stock

GASTAR EXPLORATION LTD.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011

TAB LE OF CONTENTS


		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements		4
	Gastar Exploration Ltd. Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010		4
	Gastar Exploration Ltd. Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		5
	Gastar Exploration Ltd. Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		6
	Gastar Exploration USA, Inc. Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010		7
	Gastar Exploration USA, Inc. Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		8
	Gastar Exploration USA, Inc. Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		9
	Notes to the Condensed Consolidated Financial Statements (unaudited)		10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36
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		39
Item 3.	Defaults Upon Senior Securities		39
Item 4.	(Removed and Reserved)		39
Item 5.	Other Information		39
Item 6.	Exhibits		39
SIGNATURES			42

Unless otherwise indicated or required by the context, (i) “Gastar,” the “Company,” “we,” “us,” “our” and similar terms refer collectively to Gastar Exploration Ltd. and its subsidiaries, including Gastar Exploration USA, Inc., and predecessors, (ii) “Gastar USA” refers to Gastar Exploration USA, Inc., our first-tier subsidiary and primary operating company, (iii) “Parent” refers solely to Gastar Exploration Ltd., (iv) all dollar amounts appearing in this report on Form 10-Q are stated in United States dollars (“U.S. dollars”) and (v) 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 at www.gastar.com. The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the U.S. Securities and Exchange Commission (“SEC”), as well as any amendments and exhibits to those reports, will be available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our United States filings.

Glossary of Terms



AMI		Area of Mutual Interest

Bbl		Barrel of oil

Bbl/d		Barrels of oil per day

Btu		British thermal unit

CBM		Coal bed methane

FASB		Financial Accounting Standards Board

GAAP		Accounting principles generally accepted in the United States of America

MBbl		One thousand barrels of oil

Mcf		One thousand cubic feet of natural gas

Mcf/d		One thousand cubic feet of natural gas per day

MMBtu/d		One million British thermal units per day

MMcf		One million cubic feet of natural gas

MMcf/d		One million cubic feet of natural gas per day

Mcfe		One thousand cubic feet of natural gas equivalent

MMcfe		One million cubic feet of natural gas equivalent

MMcfe/d		One million cubic feet of natural gas equivalent per day

NGL		Natural gas liquid

psi		Pound per square inch

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2011			December 31, 2010
	(Unaudited)
	(in thousands)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,968		$	7,439
Accounts receivable, net of allowance for doubtful accounts of $555 and $571, respectively		8,233			4,034
Commodity derivative contracts		13,432			10,229
Prepaid expenses		378			1,191

Total current assets		29,011			22,893

PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization		135,821			162,230
Proved properties		433,108			345,042

Total natural gas and oil properties		568,929			507,272
Furniture and equipment		1,521			1,175

Total property, plant and equipment		570,450			508,447
Accumulated depreciation, depletion and amortization		(304,129	)		(293,332	)

Total property, plant and equipment, net		266,321			215,115
OTHER ASSETS:
Restricted cash		50			50
Commodity derivative contracts		5,198			8,482
Deferred charges, net		327			508
Advances to operators and other assets		733			304

Total other assets		6,308			9,344

TOTAL ASSETS	$	301,640		$	247,352


LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	8,541		$	8,294
Revenue payable		4,922			4,331
Accrued interest		141			138
Accrued drilling and operating costs		3,919			1,490
Advances from non-operators		28,577			783
Commodity derivative contracts		2,036			1,991
Commodity derivative premium payable		4,424			3,451
Accrued litigation settlement liability		1,592			3,164
Other accrued liabilities		1,535			2,024

Total current liabilities		55,687			25,666

LONG-TERM LIABILITIES:
Long-term debt		10,000			—
Commodity derivative contracts		1,348			1,521
Commodity derivative premium payable		1,414			4,725
Accrued litigation settlement liability		—			800
Asset retirement obligation		8,127			7,249

Total long-term liabilities		20,889			14,295

Commitments and contingencies (Note 12)
SHAREHOLDERS' EQUITY:
Common stock, no par value; unlimited shares authorized; 64,697,430 and 64,179,115 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively		316,346			316,346
Additional paid-in capital		24,767			23,200
Accumulated deficit		(132,950	)		(132,155	)

Total shareholders' equity		208,163			207,391

Non-controlling interest:
Preferred stock of subsidiary, aggregate liquidation preference $20,262 and $0 at September 30, 2011 and December 31, 2010, respectively		16,901			—

Total equity		225,064			207,391

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	301,640		$	247,352

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

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands, except share and per share data)
REVENUES:
Natural gas	$	8,613		$	8,438		$	25,184		$	21,657
Oil		736			219			2,707			495
NGL		239			—			239			—

Total natural gas, oil and NGL revenues		9,588			8,657			28,130			22,152
Unrealized natural gas hedge gain		2,424			5,487			1,027			13,893

Total revenues		12,012			14,144			29,157			36,045
EXPENSES:
Production taxes		157			84			384			300
Lease operating expenses		2,363			1,549			5,945			5,206
Transportation, treating and gathering		1,128			1,165			3,354			3,508
Depreciation, depletion and amortization		3,694			2,673			10,797			6,068
Accretion of asset retirement obligation		138			101			392			292
General and administrative expense		3,100			3,842			8,576			11,618
Litigation settlement expense		—			21,150			—			21,150

Total expenses		10,580			30,564			29,448			48,142

INCOME (LOSS) FROM OPERATIONS		1,432			(16,420	)		(291	)		(12,097	)
OTHER INCOME (EXPENSE):
Interest expense		(24	)		(22	)		(87	)		(120	)
Investment income and other		2			3			7			1,343
Unrealized warrant derivative gain		—			2			—			205
Foreign transaction gain (loss)		(8	)		14			(5	)		349

INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES		1,402			(16,423	)		(376	)		(10,320	)
Provision for income tax benefit		—			(12	)		—			(804	)

NET INCOME (LOSS)		1,402			(16,411	)		(376	)		(9,516	)
Dividend on preferred stock attributable to non-controlling interest		388			—			419			—

NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION LTD.	$	1,014		$	(16,411	)	$	(795	)	$	(9,516	)

NET INCOME (LOSS) PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION LTD. COMMON SHAREHOLDERS:
Basic	$	0.02		$	(0.33	)	$	(0.01	)	$	(0.19	)

Diluted	$	0.02		$	(0.33	)	$	(0.01	)	$	(0.19	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		63,238,069			49,148,207			62,901,860			49,063,253
Diluted		63,842,098			49,148,207			62,901,860			49,063,253

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

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30,
	2011			2010
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(376	)	$	(9,516	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		10,797			6,068
Stock-based compensation		2,003			2,352
Unrealized natural gas hedge gain		(1,027	)		(13,893	)
Realized loss (gain) on derivative contracts		(1,303	)		1,604
Amortization of deferred financing costs and debt discount		193			220
Accretion of asset retirement obligation		392			292
Unrealized warrant derivative gain		—			(205	)
Dividend on preferred stock attributable to non-controlling interest		(419	)		—
Accrued litigation settlement liability		—			21,150
Changes in operating assets and liabilities:
Accounts receivable		(4,199	)		2,847
Commodity derivative contracts		(54	)		1,232
Prepaid expenses		765			400
Accrued taxes payable		—			(1,420	)
Accounts payable and accrued liabilities		774			(2,662	)

Net cash provided by operating activities		7,546			8,469

CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties		(58,672	)		(43,588	)
Advances to operators		(3,299	)		—
Proceeds from sale of natural gas and oil properties		—			19,199
Proceeds from non-operators		27,794			(671	)
Purchase of furniture and equipment		(346	)		(165	)
Purchase of term deposit		—			(4,855	)

Net cash used in investing activities		(34,523	)		(30,080	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility		41,000			24,000
Repayment of revolving credit facility		(31,000	)		—
Repayment of short-term loan		—			(17,000	)
Proceeds from issuance of preferred stock, net of issuance costs		16,855			—
Deferred financing charges		(13	)		(22	)
Other		(336	)		(296	)

Net cash provided by financing activities		26,506			6,682

NET DECREASE IN CASH AND CASH EQUIVALENTS		(471	)		(14,929	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		7,439			21,866

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	6,968		$	6,937

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

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2011			December 31, 2010
	(Unaudited)
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		6,951		$	7,401
Accounts receivable, net of allowance for doubtful accounts of $555 and $571, respectively		8,227			4,034
Commodity derivative contracts		13,432			10,229
Prepaid expenses		350			999

Total current assets		28,960			22,663

PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization		135,821			162,230
Proved properties		433,100			345,034

Total natural gas and oil properties		568,921			507,264
Furniture and equipment		1,521			1,175

Total property, plant and equipment		570,442			508,439
Accumulated depreciation, depletion and amortization		(304,122	)		(293,325	)

Total property, plant and equipment, net		266,320			215,114
OTHER ASSETS:
Restricted cash		25			25
Commodity derivative contracts		5,198			8,482
Deferred charges, net		327			508
Advances to operators and other assets		733			304

Total other assets		6,283			9,319

TOTAL ASSETS		301,563		$	247,096

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable		8,498		$	8,288
Revenue payable		4,922			4,331
Accrued interest		141			138
Accrued drilling and operating costs		3,919			1,490
Advances from non-operators		28,577			783
Commodity derivative contracts		2,036			1,991
Commodity derivative premium payable		4,424			3,451
Accrued litigation settlement liability		1,592			3,164
Other accrued liabilities		1,466			2,017

Total current liabilities		55,575			25,653

LONG-TERM LIABILITIES:
Long-term debt		10,000			—
Commodity derivative contracts		1,348			1,521
Commodity derivative premium payable		1,414			4,725
Accrued litigation settlement liability		—			800
Asset retirement obligation		8,120			7,243
Due to parent		27,361			25,193

Total long-term liabilities		48,243			39,482

Commitments and contingencies (Note 12)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; 810,499 and 0 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively, with liquidation preference of $25.00 per share		8			—
Common stock, no par value; 1,000 shares authorized; 750 shares issued and outstanding		239,431			240,431
Additional paid-in capital		16,893			—
Accumulated deficit		(58,587	)		(58,470	)

Total stockholders' equity		197,745			181,961

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		301,563		$	247,096

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

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands, except share and per share data)
REVENUES:
Natural gas	$	8,613		$	8,438		$	25,184		$	21,657
Oil		736			219			2,707			495
NGL		239			—			239			—

Total natural gas, oil and NGL revenues		9,588			8,657			28,130			22,152
Unrealized natural gas hedge gain		2,424			5,487			1,027			13,893

Total revenues		12,012			14,144			29,157			36,045
EXPENSES:
Production taxes		157			84			384			300
Lease operating expenses		2,363			1,548			5,944			5,204
Transportation, treating and gathering		1,128			1,165			3,354			3,508
Depreciation, depletion and amortization		3,694			2,673			10,797			6,068
Accretion of asset retirement obligation		138			101			392			292
General and administrative expense		2,879			3,646			7,992			10,619
Litigation settlement expense		—			21,150			—			21,150

Total expenses		10,359			30,367			28,863			47,141

INCOME (LOSS) FROM OPERATIONS		1,653			(16,223	)		294			(11,096	)
OTHER INCOME (EXPENSE):
Interest expense		(24	)		(22	)		(86	)		(67	)
Investment income and other		(1	)		(4	)		96			1,335
Foreign transaction gain (loss)		(5	)		14			(2	)		349

INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES		1,623			(16,235	)		302			(9,479	)
Provision for income tax benefit		—			(12	)		—			(804	)

NET INCOME (LOSS)		1,623			(16,223	)		302			(8,675	)
Dividend on preferred stock		388			—			419			—

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDER	$	1,235		$	(16,223	)	$	(117	)	$	(8,675	)

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

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30,
	2011			2010
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(117	)	$	(8,675	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		10,797			6,068
Stock-based compensation		2,003			2,352
Unrealized natural gas hedge gain		(1,027	)		(13,893	)
Realized loss (gain) on derivative contracts		(1,303	)		1,604
Amortization of deferred financing costs and debt discount		193			184
Accretion of asset retirement obligation		392			292
Litigation settlement payable		—			21,150
Changes in operating assets and liabilities:
Accounts receivable		(4,193	)		2,844
Commodity derivative contracts		(54	)		1,232
Prepaid expenses		601			209
Accrued taxes payable		—			(1,420	)
Accounts payable and accrued liabilities		675			(2,360	)

Net cash provided by operating activities		7,967			9,587

CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties		(58,672	)		(43,588	)
Advances to operators		(3,299	)		—
Proceeds from sale of natural gas and oil properties		—			19,199
Proceeds from non-operators		27,794			(671	)
Purchase of furniture and equipment		(346	)		(165	)
Purchase of term deposit		—			(4,855	)

Net cash used in investing activities		(34,523	)		(30,080	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility		41,000			24,000
Repayment of revolving credit facility		(31,000	)		—
Proceeds from issuance of preferred stock, net of issuance costs		16,855			—
Deferred financing charges		(13	)		(22	)
Dividend to parent, net		(836	)		(18,422	)
Other		100			49

Net cash provided by financing activities		26,106			5,605

NET DECREASE IN CASH AND CASH EQUIVALENTS		(450	)		(14,888	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		7,401			21,808

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	6,951		$	6,920

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

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

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

Gastar Exploration Ltd. is a holding company and substantially all of its operations are conducted through, and substantially all of its assets are held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration USA, Inc. and its wholly-owned subsidiaries, all references to “Parent” refer solely to Gastar Exploration Ltd., and all references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration Ltd. and its wholly-owned subsidiaries, including Gastar Exploration USA, Inc.

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2010 (“2010 Form 10-K”) filed with the SEC. Please refer to the notes to the financial statements included in the Company’s 2010 Form 10-K and to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated May 26, 2011 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.

These financial statements are a combined presentation of the condensed consolidated financial statements of the Company and Gastar USA. Separate information is provided for the Company and Gastar USA as required. Except as otherwise noted, there are no material differences between the unaudited condensed consolidated information for the Company presented herein and the unaudited condensed consolidated information of Gastar USA.

The unaudited interim condensed consolidated financial statements of the Company and Gastar USA included herein are stated in U.S. dollars unless otherwise noted and were prepared from the records of the Company and Gastar USA 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 2010 Form 10-K and to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated May 26, 2011. 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 2010 Form 10-K and to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated May 26, 2011.

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 unaudited condensed consolidated financial statements of the Company include the accounts of the Parent and the consolidated accounts of all of its subsidiaries, including Gastar USA. All significant intercompany accounts and transactions have been eliminated in consolidation.

The unaudited condensed consolidated financial statements of Gastar USA include the accounts of Gastar USA and the consolidated accounts of all of its subsidiaries. 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, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. 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:

Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued an amendment to previously issued guidance regarding the reporting and presentation of other comprehensive income. The amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income and the total of comprehensive income. Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. The amendments do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and should be applied retrospectively. Earlier application is permitted. The adoption of this guidance did not impact our operating results, financial position or cash flows.

Fair Value Measurement. In May 2011, the FASB issued an amendment to previously issued guidance regarding fair value measurement and disclosure requirements. The amendments explain how to measure fair value and do not require additional fair value measurements and are not intended to establish valuation standards or affect valuation practices outside of financial reporting. The amendments result in common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. This guidance is effective prospectively for interim and annual periods beginning after December 15, 2011. Early application is not permitted.

Business Combinations. In December 2010, the FASB’s Emerging Issues Task Force issued an amendment to previously issued guidance regarding the pro forma revenue and earnings disclosure requirements for business combinations. The amendments specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures under current guidance to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Earlier application is permitted. The adoption of this guidance did not impact our operating results, financial position or cash flows.

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 U.S., specifically the states of Texas, Pennsylvania, West Virginia, Wyoming and Montana.

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


	September 30, 2011		December 31, 2010
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	1,863	$	17,603
Acreage acquisition costs		118,362		126,388
Capitalized interest		15,596		18,239

Total unproved properties excluded from amortization	$	135,821	$	162,230

Management’s ceiling test evaluations for the nine months ended September 30, 2011 and 2010 did not result in an impairment of proved properties. The September 30, 2011 ceiling test evaluation utilized a historical 12-month un-weighted average of the first-day-of-the-month Henry Hub natural gas price of $4.16 per MMBtu and a West Texas Intermediate oil price of $91.00 per Bbl (adjusted for basis and quality differentials). The September 30, 2010 ceiling test evaluation utilized a historical 12-month un-weighted average of the first-day-of-the-month Henry Hub natural gas price of $4.41 per MMBtu and a West Texas Intermediate oil price of $73.85 per Bbl (adjusted for basis and quality differentials).

Atinum Joint Venture

In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum”), a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, Gastar USA assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consisted 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. Atinum paid Gastar USA approximately $30.0 million in cash at the closing and will pay an additional $40.0 million of future drilling obligations over time in the form of a “drilling carry.” Upon completion of the funding of the drilling carry, Gastar USA 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 initially owned by Gastar USA. The terms of the drilling carry require Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of Gastar USA’s ultimate 50% share of those same costs until the $40.0 million drilling carry has been satisfied. As of September 30, 2011, total cash consideration received by Gastar USA pursuant to the Atinum Joint Venture was approximately $46.1 million, $30.0 million of which was received upon closing and $16.1 million of drilling carry. Approximately $23.9 million of drilling carry obligation remained outstanding at September 30, 2011.

The Atinum Joint Venture is pursuing an initial three-year development program that calls for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. As of September 30, 2011, the Company had drilled and cased 12 wells under the Atinum Joint Venture. An initial AMI was 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 this initial AMI, Gastar USA will act as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay Gastar USA 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 had the right to participate in any leasehold acquisitions made by Gastar USA outside of the initial AMI and within West Virginia or Pennsylvania on terms identical to those governing the existing Atinum Joint Venture.

Marcellus Shale Leasehold Acquisition

In December 2010, Gastar USA completed a $28.9 million acquisition of undeveloped leasehold in the Marcellus Shale concentrated in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six inch steel pipe, a salt water disposal well and five conventional producing wells. This acreage is not included in the Atinum Joint Venture and the counties in which the acquired assets are located are not part of the initial AMI.

4. Long-Term Debt

Amended and Restated Revolving Credit Facility

On October 28, 2009, Gastar USA, together with Parent and Subsidiary Guarantors (as defined in the Revolving Credit Facility), 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 Gastar USA’s 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 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 Parent and all of Gastar USA’s current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees under the Revolving Credit Facility are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA and its subsidiaries, excluding de minimus value properties as determined by the lender. The facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of each foreign subsidiary of Gastar USA.

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

•

Restrictions on liens;

•

Restrictions on incurring other indebtedness without the lenders’ consent;

•

Restrictions on dividends and other restricted payments;

•

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

•

Maintenance of a maximum ratio of indebtedness to EBITDA on a rolling four quarter basis, as adjusted, of not greater than 4.0 to 1.0; and

•

Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0.

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

Following the 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”) amending that certain Amended and Restated Credit Agreement dated October 28, 2009 (as amended by that certain Consent and First Amendment to Amended and Restated Credit Agreement dated November 20, 2009, the Second Amendment and the Third Amendment (as defined below), the “Credit Agreement”) . The Second Amendment amended the Revolving Credit Facility, by, among other things, (i) allowing Gastar USA 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) allowing Gastar USA 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 the limitations on hedging using floors and protective spreads.

On June 14, 2011, Gastar USA, together with the parties thereto, entered into the Third Amendment to the Amended and Restated Credit Agreement (the “Third Amendment”). The Third Amendment amended the Revolving Credit Facility, by, among other things, allowing Gastar USA to issue Series A Preferred Stock (as defined below) described in Part I, Item 1. “Financial Statements, Note 7 – Capital Stock” of this report and, as long as no default exists or would result from such payment and availability under the Credit Agreement equals at least 10% of the then-existing borrowing base under the Credit Agreement, pay cash dividends on the Series A Preferred Stock of no more than $10.0 million in the aggregate in each calendar year.

As of September 30, 2011, the Revolving Credit Facility had a borrowing base of $50.0 million, with $10.0 million of borrowings outstanding and availability of $40.0 million. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. Gastar USA and the lenders may each request one additional unscheduled redetermination annually.

At September 30, 2011, Gastar USA was in compliance with all financial covenants under the Revolving Credit Facility.

Other Debt

Credit support for the Company’s open derivatives at September 30, 2011 is provided under the Revolving Credit Facility through inter-creditor agreements or open accounts of up to $5.0 million.

5. Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations 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. Since none of the Company’s non-financial assets and liabilities were impaired during the period-ended September 30, 2011, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at September 30, 2011.

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

•

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

•

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

•

Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. 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 reports them gross on its condensed consolidated balance sheets.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010:


	Fair value as of September 30, 2011
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	6,968	$	—	$	—		$	6,968
Restricted cash		50		—		—			50
Commodity derivative contracts		—		—		18,630			18,630
Liabilites:
Commodity derivative contracts		—		—		(3,384	)		(3,384	)

Total	$	7,018	$	—	$	15,246		$	22,264


	Fair value as of December 31, 2010
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	7,439	$	—	$	—		$	7,439
Restricted cash		50		—		—			50
Commodity derivative contracts		—		—		18,711			18,711
Liabilites:
Commodity derivative contracts		—		—		(3,512	)		(3,512	)

Total	$	7,489	$	—	$	15,199		$	22,688

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, 2011 and 2010. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at September 30, 2011 and 2010.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Balance at beginning of period	$	13,286		$	13,232		$	15,199		$	7,638
Total gains (losses) (realized or unrealized):
included in earnings		4,813			6,944			7,596			16,147
included in other comprehensive income		—			—			—			—
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements (1)		(2,853	)		(1,780	)		(7,549	)		(5,389	)
Transfers in and (out) of Level 3		—			—			—			—

Balance at end of period	$	15,246		$	18,396		$	15,246		$	18,396

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, 2011 and 2010	$	2,424		$	5,489		$	1,027		$	14,098

(1)	Included in natural gas revenues and other income (expense) on the statement of operations.

At September 30, 2011, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at September 30, 2011 approximates the respective carrying value because the interest rate approximates the current market rate.

6. Derivative Instruments and Hedging Activity

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

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, 2011, the Company reported an unrealized gain of $2.4 million and $1.0 million, respectively, in the condensed consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the three and nine months ended September 30, 2010, the Company reported an unrealized gains of $5.5 million and $13.9 million, respectively, in the condensed consolidated statement of operations related to the change in the fair value of its commodity derivative instruments.

As of September 30, 2011, the following derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:


Settlement Period	Derivative Instrument	Average Daily Volume		Total of Notional Volume		Base Fixed Price			Floor (Long)		Short Put		Ceiling (Short)
		(in MMBtu's)
2011	Put spread		16,025		1,474,000	$	—		$	6.06	$	4.12	$	—
2011	Costless three-way collar		3,262		300,000		—			6.00		4.00		7.00
2011	Fixed price swap		2,000		184,000		6.11			—		—		—
2011	Basis - CIG (1)		800		73,600		(1.21	)		—		—		—
2012	Put spread		13,028		4,770,420		—			6.00		4.00		—
2012	Costless three-way collar		7,410		2,711,580		—			5.73		4.00		6.88
2013	Costless three-way collar		2,500		912,500		—			5.00		4.00		6.45
2013	Fixed price swap		5,000		1,825,000		5.42			—		—		—
2014	Short calls		2,500		912,500		—			—		—		6.00

(1)	Inside FERC Colorado Interstate Gas, Rocky Mountains

As of September 30, 2011, 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, 2011 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 July 2010.

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


	September 30, 2011		December 31, 2010
	(in thousands)
Current commodity derivative premium payable	$	4,424	$	3,451
Long-term commodity derivative premium payable		1,414		4,725

Total unamortized put premium liabilities	$	5,838	$	8,176

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


	September 30, 2011
	(in thousands)
October - December 2011	$	1,113
January - December 2012		4,725

Total unamortized put premium liabilities	$	5,838

Warrants

The Parent reclassified the fair value of its warrants to purchase common shares, 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, Parent 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 zero as of September 30, 2011. The Parent 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, 2011:


Warrants Outstanding	Fair Value (in thousands)	Weighted Price per Share Range	Weighted Average Remaining Life in Years	Average Exercise Price
2,000,000	$0	(1)	0.2	(1)

(1)	The warrants are exercisable on or before December 11, 2011 at $15.00 per share, subject to certain adjustments. Fair value is based on the Black-Scholes-Merton model for option pricing.

Additional Disclosures about Derivative Instruments and Hedging Activities

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


	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
		Fair Value
	Balance Sheet Location	September 30, 2011			December 31, 2010
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	13,432		$	10,229
Commodity derivative contracts	Other assets		5,198			8,482
Commodity derivative contracts	Current liabilities		(2,036	)		(1,991	)
Commodity derivative contracts	Long-term liabilities		(1,348	)		(1,521	)

Total derivatives not designated as hedging instruments		$	15,246		$	15,199


	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, 2011			September 30, 2010
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Unrealized natural gas hedge gain	$	2,424		$	5,487
Warrant derivative	Unrealized warrant derivative gain		—			2

Total		$	2,424		$	5,489


	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, 2011			September 30, 2010
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Unrealized natural gas hedge gain	$	1,027		$	13,893
Warrant derivative	Unrealized warrant derivative gain		—			205

Total		$	1,027		$	14,098

7. Capital Stock

Other Share Issuances

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


	For the Three Months Ended September 30, 2011		For the Nine Months Ended September 30, 2011
Other share issuances:
Restricted common shares granted		—		753,199
Restricted common shares vested		187,416		391,627
Stock options exercised		—		15,000
Common shares forfeited (1)		50,733		118,234
Common shares canceled		30,111		131,650

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

Shares Reserved

The following table summarizes the components of Parent’s common shares reserved at September 30, 2011:


Common shares reserved for the:
Exercise of stock options			990,400
Exercise of warrants			2,000,000

Total common shares reserved			2,990,400

Gastar USA Common Stock

Prior to its conversion, as described below, Gastar USA’s articles of incorporation allowed Gastar USA to issue 1,000 shares of common stock, without par value. There were 750 shares issued and outstanding at September 30, 2011 and December 31, 2010, all of which were held by Parent.

On May 24, 2011, Gastar USA converted from a Michigan corporation to a Delaware corporation (the “Conversion”). Following the Conversion, Gastar USA’s new Delaware certificate of incorporation allows Gastar USA to issue 1,000 shares of common stock, without par value. In connection with the Conversion, the Parent’s 750 shares of common stock in the Michigan corporation were converted to 750 shares of common stock in the new Gastar USA Delaware corporation.

The stockholders’ equity presented in the balance sheet of Gastar USA as of December 31, 2010 gives effect to the Conversion as if it had occurred prior to December 31, 2010.

Gastar USA Preferred Stock

Prior to the Conversion, Gastar USA’s articles of incorporation did not authorize issuance of preferred stock.

Following the Conversion, Gastar USA’s new Delaware certificate of incorporation allows Gastar USA to issue 10,000,000 shares of preferred stock, with $0.01 par value. The preferred stock may be issued from time to time in one or more series. Gastar USA’s Board of Directors (the “Gastar USA Board”) is authorized to fix the number of shares of any series of preferred stock and to determine the designation of any such series. The Gastar USA Board is also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued series of preferred stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series outstanding) the number of shares of any series subsequent to the issues shares of that series).

On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of its 8.625% Series A Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series A Preferred Stock”) through a best efforts underwritten public offering. The net proceeds to Gastar USA were approximately $13.6 million after deducting underwriting discounts, commissions and estimated offering expenses.

On June 29, 2011, Gastar USA entered into an at-the-market sales agreement (“ATM Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”). According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A Preferred Stock through MLV, as its sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV.

As of September 30, 2011, Gastar USA had sold 164,204 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $3.3 million. From September 30, 2011 to October 31, 2011, Gastar USA sold an additional 219,184 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $4.2 million.

The Series A Preferred Stock will be subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. The Parent has entered into a guarantee agreement, whereby it will fully and unconditionally guarantee the payment of dividends that have been declared by the board of directors of Gastar USA, amounts payable upon redemption or liquidation, dissolution or winding up, and any other amounts due with respect to the Series A Preferred Stock, to the extent described in the guarantee agreement. Parent’s obligations with respect to the guarantee will be effectively subordinated to all of its existing and future debt.

The Series A Preferred Stock cannot be converted into common stock of Gastar USA or the Company, but may be redeemed by Gastar USA, at Gastar USA’s option, on or after June 23, 2014 for $25.00 per share plus any accrued and unpaid dividends or in certain circumstances prior to such date as a result of a change in control. Following a change in control, Gastar USA will have the option to redeem the Series A Preferred Stock, in whole but not in part, within 90 days after the date on which the change in control occurs, for cash at the following prices per share, plus accrued and unpaid dividends (whether or not declared), up to the redemption date:


Redemption Date	Redemption Price
Prior to June 23, 2012	$	25.75
On or after June 23, 2012 and prior to June 23, 2013	$	25.50
On or after June 23, 2013 and prior to June 23, 2014	$	25.25
On or after June 23, 2014	$	25.00

Gastar USA will pay cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three and nine months ended September 30, 2011, Gastar USA paid dividends of $388,000 and $419,000, respectively.

8. Interest Expense

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


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(in thousands)
Interest expense:
Cash and accrued	$	180		$	145		$	559		$	335
Amortization of deferred financing costs and debt discount		65			63			193			220
Capitalized interest		(221	)		(186	)		(665	)		(435	)

Total interest expense	$	24		$	22		$	87		$	120

9. Related Party Transactions

Chesapeake Energy Corporation

Chesapeake Energy Corporation (“Chesapeake”) acquired 6,781,767 of Parent’s common shares during 2005 to 2007 in a series of private placement transactions. As a result of its share ownership, Chesapeake has the right to have an observer present at meetings of the Parent’s board of directors.

As of September 30, 2011, Chesapeake owned 6,781,767 of Parent’s common shares, or 10.5% of the Parent’s outstanding common shares.

10. Income Taxes

For the three and nine months ended September 30, 2011, the Company did not recognize a current income tax benefit or provision. 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 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 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$213,000 ($196,000) of Australian withholding tax on interest income earned on term deposits in Australia from the date of the sale through March 31, 2010.

11. Earnings per Share

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


	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2011		2010			2011			2010
	(in thousands, except per share and share data)
Net income (loss) attributable to Gastar Exploration Ltd.	$	1,014	$	(16,411	)	$	(795	)	$	(9,516	)
Weighted average common shares outstanding - basic		63,238,069		49,148,207			62,901,860			49,063,253
Incremental shares from unvested restricted shares		551,687		—			—			—
Incremental shares from outstanding stock options		52,342		—			—			—

Weighted average common shares outstanding - diluted		63,842,098		49,148,207			62,901,860			49,063,253

Net income (loss) per common share attributable to Gastar Exploration Ltd. Common Shareholders:
Basic	$	0.02	$	(0.33	)	$	(0.01	)	$	(0.19	)
Diluted	$	0.02	$	(0.33	)	$	(0.01	)	$	(0.19	)

Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares		500		179,028			149,960			120,008
Stock options		838,200		867,800			857,825			948,774
Warrants		2,000,000		2,000,000			2,000,000			2,000,000

Total		2,838,700		3,046,828			3,007,785			3,068,782

12. 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, which were sold to Chesapeake on November 4, 2005 (the “2005 Transaction”). 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 2005 Transaction. In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its opinion on January 9, 2008 reversing the trial court’s rulings, rendering judgment in favor of Navasota on its claims for

breach of contract and specific performance, and remanding the case for further proceedings on Navasota’s other counts, which include claims for suit to quiet title, trespass to try title, tortuous interference with contract, conversion, money had and received, and declaratory relief. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, which was denied on March 18, 2008. The Company and Chesapeake filed a joint Petition for Review in the Texas Supreme Court on May 13, 2008. On August 28, 2008, the Texas Supreme Court requested briefing on the merits. On January 9, 2009, the Texas Supreme Court denied the Petition for Review. On January 26, 2009, the Company and Chesapeake jointly filed a motion for rehearing in the Texas Supreme Court on its denial of the Petition for Review. On April 24, 2009, the Texas Supreme Court denied the Petition for Review.

Pursuant to a provision in the Purchase and Sale and Exploration Development Agreement, dated November 4, 2005 (the “Purchase and Sale Agreement”), between the Company and 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 Purchase and Sale Agreement and the Common Share Purchase Agreement, both dated November 4, 2005. 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 2005 Transaction and/or other amounts. Chesapeake 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 March 2011, Chesapeake dismissed the cross-claims against the Company, including the claim for rescission, without prejudice to the subsequent refiling of those claims. On April 12, 2011, Navasota filed its Fifth Amended Petition. The Fifth Amended Petition adds a new claim that the Company allegedly has refused to offer Navasota interests in oil and gas leases located within an area of mutual interest, failed to assign Navasota overriding royalty interests, and failed to recognize back-in-after-payout interests. On September 2, 2011, Navasota filed its Sixth Amended Petition. The Sixth Amended Petition adds a new claim that the Company allegedly further violated Navasota’s preferential right under the July 7, 2000 operating agreement to the extent the Company sold any other interests in oil and gas leases located in an area of mutual interest without offering them to Navasota. The Sixth Amended Petition also added a claim that the Company violated the Texas Natural Resource Code sections 402 and 403 by failing to pay production proceeds to Navasota.

The case is currently set for trial in Leon County, Texas on April 24, 2012. 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.

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”). 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 Company also contends that the defendants’ continued production of oil from wells located on the land in question is a trespass to real property for which the Company is entitled to receive damages. The defendants have responded with a general denial and alleged certain affirmative defenses. The defendants have filed their own counterclaim asserting various theories of recovery. The defendants claim that their leases are still valid and that they

own a working interest and/or an overriding royalty in the Company’s Belin Nos. 1, 2 and 3 wells located in Leon County. The parties attended mediation but no settlement was reached. The defendants were deposed in March 2011. On June 30, 2011, five individuals intervened in the lawsuit and claimed that they are owed overriding royalties under the same leases claimed by the defendants. The Company contends that the intervenors are not entitled to any overriding royalties because the leases claimed by the defendants and the intervenors have expired. The case is set for trial starting March 5, 2012. The Company believes it has gathered evidence to diminish or completely defeat the defendants’ and the intervenors’ 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 the Navasota Resources, Tillotson and J. Ken Welch matters, 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.

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

13. Statement of Cash Flows – Supplemental Information

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


	For the Nine Months Ended
	September 30,
	2011			2010
	(in thousands)
Cash paid for interest	$	556		$	303
Cash paid for taxes		—			615
Non-cash transactions:
Term deposit surrendered for accrued taxes	$	—		$	70,446
Non-cash capital expenditures excluded from accounts payable and accrued drilling costs		(99	)		961
Asset retirement obligation included in natural gas and oil properties		486			228
Application of advances to opertors		2,770			150

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking information 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, including the anticipated scheduling and results of such operations;

•

natural gas and oil reserves;

•

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

•

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. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

•

the supply and demand for natural gas and oil;

•

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

•

natural gas and oil price volatility;

•

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

•

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

•

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

•

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

•

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

•

uncertainties about 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;

•

strength and financial resources of competitors;

•

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

•

availability and cost of processing and transportation;

•

changes or advances in technology;

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

•

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

•

environmental risks;

•

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

•

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

•

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

•

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

•

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

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ability to find and retain skilled personnel; and

•

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

For a more detailed description of the risks and uncertainties that we face and other factors that could affect our financial performance or cause our actual results to differ materially from our projected results please see (i) Part II, Item 1A. “Risk Factors” and elsewhere in this report, (ii) Part I, Item 1A. “Risk Factors” and elsewhere in our 2010 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.

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

Overview

We are an independent energy company engaged in the exploration, development and production of 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 unconventional natural gas reserves, such as shale resource plays as well as prospective deep structures identified through seismic and other analytical techniques. We are currently pursuing natural gas exploration in the Marcellus Shale in the Appalachia area of West Virginia and central and southwestern Pennsylvania and in the deep Bossier gas play in the Hilltop area of East Texas. We also conduct limited CBM development activities within the Powder River Basin of Wyoming and Montana.

The Parent is a Canadian corporation, incorporated in Alberta in 1987 and subsisting under the Business Corporations Act (Alberta), with its common shares listed on the NYSE Amex under the symbol “GST.” The Parent is a holding company. Substantially all of the Company’s operations are conducted through, and substantially all of its assets are held by, the Parent’s primary operating subsidiary, Gastar USA, and its subsidiaries. Gastar USA’s Series A Preferred Stock is listed on the NYSE Amex under the symbol “GST.PRA.”

Our current operational activities are conducted primarily in the United States. As of September 30, 2011, our major assets consist of approximately 99,300 gross (74,400 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 35,300 gross (19,400 net) acres in the Bossier play in the Hilltop area of East Texas, and approximately 43,400 gross (19,600 net) acres in the Powder River Basin of Wyoming and Montana.

The following discussion addresses material changes in our results of operations for the three and nine months ended September 30, 2011 compared to the three and nine months ended September 30, 2010 and material changes in our financial condition since December 31, 2010. This discussion should be read in conjunction with our condensed consolidated financial statements and the notes thereto included in Part I. Item 1. “Financial Statements” of this report, as well as our 2010 Form 10-K, which includes important disclosures regarding our critical accounting policies as part of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Except as otherwise noted, there are no material differences between the consolidated information for the Company presented herein and the consolidated information of Gastar USA.

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.

Appalachia – West Virginia and Central and Southwestern Pennsylvania. The Marcellus Shale is Devonian aged shale that underlies much of the Appalachian region of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration target. Advancements in 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, 2011, our acreage position in the play was approximately 99,300 gross (74,400 net) acres, of which approximately 42,800 gross (19,900 net) acres are referred to as Marcellus West acreage, reflecting our interest after the 50% interest is assigned under the Atinum Joint Venture, and 56,500 gross (54,500 net) acres are referred to as Marcellus East acreage. The entirety of our acreage is believed 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 early 2010, we completed the drilling of our first vertical Marcellus Shale well, the Yoho #1. The well 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 are currently waiting for a connection to a pipeline and do not expect natural gas sales until the third quarter of 2012.

On September 21, 2010, we entered into the Atinum Joint Venture pursuant to a purchase and sale agreement with Atinum. Pursuant to the agreement, at the closing of the transaction on November 1, 2010, we assigned to Atinum, for $70.0 million in total consideration, an initial 21.43% interest in all of our existing Marcellus Shale assets in West Virginia and Pennsylvania, consisting of certain undeveloped acreage and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well (the “Atinum Joint Venture Assets”). Atinum paid us approximately $30.0 million in cash upon closing. Additionally, Atinum is obligated to fund its 50% share of drilling, completion and infrastructure costs, and will pay an additional $40.0 million of future drilling costs in the form of a drilling carry obligation by funding 75% of our 50% share of those same costs. 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 Atinum Joint Venture Assets. As of September 30, 2011, approximately $23.9 million of drilling carry obligation remained outstanding.

The Atinum Joint Venture is pursuing an initial three-year development program that calls for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. As of September 30, 2011, we had drilled and cased 12 wells in Marshall County, West Virginia, under the Atinum Joint Venture. Through June 30, 2011, an initial AMI was 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 Assets were located. Subsequent to June 30, 2011, Atinum has the right to participate in any future leasehold acquisitions made by us within Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the existing Atinum Joint Venture. We 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.

In December 2010, we completed a Marcellus Shale leasehold acquisition (the “Marcellus East Acquisition”) for an aggregate purchase price of $28.9 million. The acquisition consisted of undeveloped leasehold in the Marcellus Shale concentrated in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six inch steel pipeline, a salt water disposal well, and five conventional producing wells. The Marcellus East Acquisition acreage was outside the initial AMI with Atinum, and Atinum elected not to acquire a 50%

interest as provided under the terms of the Atinum Joint Venture. We believe their decision was due to the timing of the transaction and limited prior operational results within the initial Atinum Joint Venture AMI. We have completed the drilling of the Hickory Ridge 2H horizontal Marcellus well on the Marcellus East Acquisition acreage in Preston County. We completed the 2,500 foot lateral with a ten-stage fracture stimulation in August 2011 and the well is currently flowing back completion fluids with first sales anticipated by year end 2011. No additional wells are currently planned to be drilled on the Marcellus East Acquisition acreage in 2011 as we commence permitting of a 3-D seismic survey over a portion of the Marcellus East Acquisition acreage with a targeted completion date of early 2013.

As of September 30, 2011, in Marshall County West Virginia, we had completed drilling the Wengerd 1H and 7H Marcellus wells with horizontal lateral extensions of approximately 4,700 feet and 5,700 feet, respectively. We successfully completed fracing operations on the Wengerd 1H and 7H wells in July 2011 and the wells were turned to sales in mid-August. The initial combined 30-day average gross sales rate flowing up 5¹/2 inch production casing was approximately 7.1 MMcf/d of natural gas, 176 barrels of condensate and 347 barrels of NGLs. After all drilling and completing costs have been incurred, we will have an approximate 44.5% working interest and an approximate 37.5% net revenue interest in the Wengerd wells.

On September 23, 2011, the pipeline operator notified us that they had incurred a force majeure event that damaged their pipeline and the pipeline was shut-in until October 18, 2011. After running tubing in the wells during the time the pipeline was being repaired, we attempted to return the Wengerd wells to production on October 21, 2011. Currently, the wells are producing at severely restricted rates due to high line pressures being experienced by the pipeline operator. The pipeline operator is working to reduce line pressures by adding compression in anticipation of additional gas volumes being brought on-line by us later in 2011.

As of September 30, 2011, drilling operations were completed on the Corley 1H, 2H, 3H and 4H Marcellus horizontal wells with average lateral extensions of approximately 4,925 feet per well. Completion operations on the four Corley horizontal wells commenced in early October 2011 with first sales anticipated by mid-November 2011. After all drilling and completing costs have been incurred, we will have an approximate 40.5% working interest and an approximate 34.5% net revenue interest in the Corley wells. As of September 30, 2011, drilling operations were also completed on the Simms 1H, 2H and 3H wells and the Hendrickson 1H, 2H and 4H wells with average lateral extensions on the Simms and Hendrickson wells of approximately 5,000 feet and 4,700 feet, respectively. Fracing operations on the three Simms wells are scheduled to commence in November 2011 with first production anticipated by mid-December 2011. After all drilling and completing costs have been incurred, we will have an approximate 50% working interest and an approximate 42% net revenue interest in the Simms wells. Drilling operations on the Hendrickson 3H and 5H wells were completed in late October 2011 with frac operations on the five Hendrickson wells anticipated to commence in December 2011 and first sales anticipated in May 2012. After all drilling and completing costs have been incurred, we will have an approximate 40.2% working interest and an approximate 33.8% net revenue interest in the Hendrickson wells.

Currently, we have commenced drilling operations on the Hall lease, a three horizontal well Marcellus pad scheduled for production in mid-February 2012, and the Burch Ridge lease, a five horizontal well pad scheduled for production in late July 2012, and we plan to commence drilling operations on the Accettolo lease, a three horizontal well pad scheduled for production in Mid-March 2012, prior to year end. As of year-end 2011, we anticipate our operated well activity in Marshall County, West Virginia, to be comprised of 9 gross (4 net) wells on sales and 10 gross (4.2 net) wells drilled awaiting completion. All wells drilled in Marshall County are subject to the Atinum Joint Venture and after all drilling and completing costs have been incurred, our working interest will range from approximately 50% to 40% with a corresponding 43% to 34% net revenue interest with average lateral extensions of approximately 4,800 feet.

Regarding non-operated activity in the Marcellus Shale, during 2010 we began participating in the drilling of seven horizontal Marcellus Shale wells in Butler County, Pennsylvania with Rex Energy as operator. Drilling of the seven horizontal wells has been completed and fracing operations on three of the wells commenced in late October 2011 with initial sales expected in the fourth quarter of 2011. Completion operations on the remaining four wells should commence early 2012. The Rex Energy wells are subject to the Atinum Joint Venture agreement and drilling carry.

For the three and nine months ended September 30, 2011, net production from Appalachia averaged approximately 2.9 MMcfe/d and 1.4 MMcfe/d, respectively, compared to 0.4 MMcfe/d for each of the three and nine months ended September 30, 2010, respectively.

Hilltop Area, East Texas. The majority of our activities during the first half of 2011 were in the Bossier and shallower potential oil zones in the Hilltop area of East Texas, approximately midway between Dallas and Houston in Leon and Robertson Counties. As of September 30, 2011, our acreage position in the play was approximately 35,200 gross (19,400 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 May 2010, we drilled the Wildman 6H, a horizontal well, in the Glen Rose formation and completed it with a single stage fracture stimulation. The Wildman 6H well was completed using a slotted liner which did not allow for the multi-stage fracture stimulation of the horizontal wellbore where several natural fractures were observed. During the current quarter, the well’s average daily production was approximately 6 bbl/d. Recognizing that our original completion approach was not optimal, we decided to further test the Glen Rose formation. Subsequently, we drilled two other wells to test the Glen Rose formation – another horizontal well, the Wildman 8H, and a vertical well, the Williams #2. The Wildman 8H and Williams #2 were fracture stimulated and completed in late February 2011. During the current quarter, the Wildman 8H average daily production was approximately 42 bbl/d. While initial production results were encouraging, subsequent oil production has been lower than expected, primarily as a result of excessive water production. We will continue to monitor production before continuing with horizontal development of the Glen Rose formation. The Williams #2 was initially flowing naturally after stimulation and was placed on artificial lift at a rate of approximately 6 bbl/d. In June 2011 we added an additional Glen Rose completion but subsequently, the well has been plugged to test an oil shale in the Paluxy formation and is awaiting fracture stimulation to complete the test, which is anticipated to commence later in the fourth quarter of 2011. Following the Paluxy formation test, we are planning to test the Eagle Ford Shale/Woodbine formation. Ultimately we plan on commingling the Glen Rose completions, the Paluxy completions and an Eagle Ford Shale/Woodbine completion in the Williams #2 well.

In January 2011, we attempted to test the Eagle Ford Shale/Woodbine formation with one well in East Texas, the Wildman 7H. The Wildman 7H horizontal well was intended to test the Eagle Ford Shale/Woodbine formation, but due to drilling issues, the well was re-targeted and the horizontal lateral drilled in a slightly deeper transitional limestone zone known as the False Buda. The well was fracture stimulated with a 16-stage completion. Micro-seismic information was gathered during the completion process, and processing and interpretation of that data revealed that our fracture stimulation did not extend upward as anticipated in order to allow extraction from the Eagle Ford Shale/Woodbine formation. The Wildman 7H initially flowed at gross 145 bbl/d and was placed on artificial lift in mid-February 2011. We are currently working to identify the source of water encroachment in this well. We have postponed drilling a subsequent well in 2011 until we have received final core analysis of the Eagle Ford Shale/Woodbine formation taken during the drilling of the Belin #3 well, the additional production results from the Wildman 7H well and additional information from monitoring of offset operator drilling activity in the zone. If we drill an additional Eagle Ford/Woodbine Shale well, we expect the horizontal lateral will be targeted within the portion of the Eagle Ford Shale/Woodbine formation that was originally the target of the Wildman 7H well.

In December 2010, we began drilling the Belin #2 well, an exploration well testing the deep Bossier formation in a separate fault block near the Belin #1 well. The well reached total depth of 19,650 feet and encountered approximately 130 net feet of pay in the lower Bossier formation within five separate sand intervals. The initial formation zone was fracture stimulated in April 2011 with marginal results and a bridge plug was set. In early May 2011, we fracture stimulated the next zone, which, based on log interpretation, should be the most productive lower Bossier zone in the well. During fracture stimulation of the well, we encountered an equipment failure and the frac operation had to be stopped before the designed frac job was completed. We subsequently attempted to re-frac the zone but we were unsuccessful in surpassing any reservoir damage from the first aborted frac attempt. We are currently evaluating completion plans for this well. We have a 67% before payout working interest and an approximate 50% before payout net revenue interest in the Belin #2 well.

We drilled the Belin #3 well in the same fault block as the Belin #2 well. The well reached total depth of 20,100 feet in mid-July 2011 and encountered approximately 60 net feet of pay in the lower Bossier formation within four separate sand intervals. The lower formation zones were fracture stimulated in September and October 2011. The lower zone initial production rate was 1.9 MMcf/d, and the next zone fracture stimulation resulted in an initial production rate of 4.9 MMcf/d. The well is currently averaging approximately 3.3 MMcf/d. We plan to combine the lower formation zones to a single completion and to add two additional Bossier intervals at a later date. We have a 67% before payout working interest and an approximate 50% before payout net revenue interest in the Belin #3 well.

We added two recompletion zones in the Wildman #5 during October 2011. After the recompletion zone pressures normalized, all producing down-hole zones in the well were commingled resulting in a current average production rate of 3.0 MMcf/d.

For the three and nine months ended September 30, 2011, net production from the Hilltop area averaged approximately 16.6 MMcfe/d and 17.9 MMcfe/d, respectively, compared to 20.1 MMcfe/d and 16.9 MMcfe/d for the three and nine months ended September 30, 2010, respectively.

Coalbed Methane – Powder River Basin, Wyoming and Montana. As of September 30, 2011, 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, Powder River Basin production averaged 1.3 MMcfe/d and 1.4 MMcfe/d for the three and nine months ended September 30, 2011, respectively, compared to 2.0 MMcfe/d for each of the three and nine months ended September 30, 2010, respectively.

Recent Gastar USA Preferred Equity Financing

On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of Series A Preferred Stock through a best efforts underwritten public offering. The Parent has entered into a guarantee agreement, whereby it will fully and unconditionally guarantee the payment of dividends that have been declared by the board of directors of Gastar USA, amounts payable upon redemption or liquidation, dissolution or winding up, and any other amounts due with respect to the Series A Preferred Stock, to the extent described in the guarantee agreement. The net proceeds to Gastar USA were approximately $13.6 million after deducting underwriting discounts, commissions and estimated offering expenses. The net proceeds were primarily used to repay borrowings under Gastar USA’s Revolving Credit Facility.

On June 29, 2011, Gastar USA entered into an ATM Agreement with MLV. According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A Preferred Stock through MLV, as our sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV. During the nine months ended September 30, 2011, Gastar USA sold 164,204 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $3.3 million. From September 30, 2011 to October 31, 2011, we sold an additional 219,184 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $4.2 million. We plan to continue issuing Series A Preferred Stock under the ATM Agreement in the future depending on our capital expenditures program and market conditions. See “Liquidity and Capital Resources.”

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				For the Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Production:
Natural gas (MMcf)		1,837		2,063		5,437		5,243
Oil (MBbl)		10		3		31		7
NGL (MBbl)		5		—		5		—
Total production (MMcfe)		1,921		2,082		5,649		5,285

Total (Mmcfe/d)		20.9		22.6		20.7		19.4

Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities	$	3.37	$	3.39	$	3.41	$	3.74
Natural gas per Mcf, including impact of realized hedging activities		4.69		4.09		4.63		4.13
Oil per Bbl		77.64		68.47		87.91		70.59
NGL per Bbl		52.93		—		52.93		—

Selected operating expenses (in thousands):
Production taxes	$	157	$	84	$	384	$	300
Lease operating expenses		2,363		1,549		5,945		5,206
Transportation, treating and gathering		1,128		1,165		3,354		3,508
Depreciation, depletion and amortization		3,694		2,673		10,797		6,068
General and administrative expense		3,100		3,842		8,576		11,618

Selected operating expenses per Mcfe:
Production taxes	$	0.08	$	0.04	$	0.07	$	0.06
Lease operating expenses		1.23		0.74		1.05		0.99
Transportation, treating and gathering		0.59		0.56		0.59		0.66
Depreciation, depletion and amortization		1.92		1.28		1.91		1.15
General and administrative expense		1.61		1.85		1.52		2.20

Three Months Ended September 30, 2011 compared to the Three Months Ended September 30, 2010

Revenues. Our revenues are primarily derived from the production of natural gas in the United States. Total natural gas, oil and NGL revenues were $9.6 million for the three months ended September 30, 2011, up from $8.7 million for the three months ended September 30, 2010. The increase in revenues was the result of a 20% increase in weighted average prices, primarily resulting from increased oil prices and higher oil and NGL volumes for the 2011 period, offset by an 8% decrease in volumes. Average daily production on an equivalent basis was 20.9 MMcfe/d for the three months ended September 30, 2011 compared to 22.6 MMcfe/d for the same period in 2010. Oil and NGL daily production represented approximately 4% of total production for the three months ended September 30, 2011 compared to 1% of daily production for the prior year three month period.

During the three months ended September 30, 2011, approximately 92% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $2.4 million in natural gas and oil revenues resulting in an increase in total price realized from $3.37 per Mcf to $4.69 per Mcf. The realized hedge impact includes a benefit of $432,000 for amortization of prepaid call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $2.0 million, which was comprised of $2.9 million of NYMEX hedge gains offset by $68,000 of regional basis losses and payment of deferred put premiums of $861,000. For the remainder of 2011, we have costless three way collar hedges for approximately 3,300 MMBtu/d with a weighted average floor of $6.00, short put of $4.00 and a ceiling of $7.00. In addition, we have put spread hedges for approximately 16,000 MMBtu/d with a weighted average floor of $6.06 and a short put of $4.12 and fixed price swaps for 2,000 MMBtu/d at $6.11. Currently, these hedge positions represent approximately 99% of our estimated future 2011 natural gas production. During the three months ended September 30, 2010, 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 2010 realized hedge impact included $159,000 of amortization of prepaid call sale and put purchase premiums.

Unrealized natural gas hedge gain was $2.4 million for the three months ended September 30, 2011 compared to $5.5 million for the three months ended September 30, 2010. The decrease in unrealized natural gas hedge gain is the result of a decrease in future volumes hedged and lower future NYMEX gas prices partially offset by losses related to projected basis differentials.

Production taxes. We reported production taxes of $157,000 for the three months ended September 30, 2011 compared to $84,000 for the three months ended September 30, 2010. The increase in production taxes primarily resulted from higher revenues in West Virginia due to increased natural gas, oil and NGL production, partially offset by lower revenues in Wyoming due to lower production volumes.

Lease operating expenses. We reported lease operating expenses of $2.4 million for the three months ended September 30, 2011 compared to $1.5 million for the three months ended September 30, 2010. Our lease operating expenses were $1.23 per Mcfe for the three months ended September 30, 2011 compared to $0.74 per Mcfe for the same period in 2010. The increase in the rate per Mcfe was primarily due to higher ad valorem taxes of $0.12 per Mcfe and higher workover costs of $0.29 per Mcfe and lower production volumes during the three months ended September 30, 2011.

Transportation, treating and gathering. We reported transportation expenses of $1.1 million for the three months ended September 30, 2011 compared to $1.2 million for the three months ended September 30, 2010. The current quarter included $413,000 of charges under our Hilltop gas gathering agreement with Hilltop Resort GS, LLC compared to $236,000 of such charges in the same quarter of 2010. Such charges resulted from actual production volumes being less than minimum contractual volume requirements.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $3.7 million for the three months ended September 30, 2011 up from $2.7 million for the three months ended September 30, 2010. The increase in DD&A expense was the result of a 50% increase in the DD&A rate per Mcfe offset by an 8% decrease in production. The DD&A rate for the three months ended September 30, 2011 was $1.92 per Mcfe compared to $1.28 per Mcfe for the same period in 2010. The increase in the rate is primarily due to higher proved costs associated with recent East Texas wells drilled and additional allocation of undeveloped East Texas leasehold costs from unproved to proved properties based on recent drilling results. Additionally, the September 30, 2010 DD&A rate was reduced by the gathering system sales proceeds credited to proved property costs in the fourth quarter of 2009.

General and administrative. We reported general and administrative expenses of $3.1 million for the three months ended September 30, 2011, down from $3.8 million for the three months ended September 30, 2010. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $760,000 and $713,000 for the three months ended September 30, 2011 and 2010, respectively. The increase in stock-based compensation expense is primarily due to the additional expense recognized during the period related to grants made in early 2011 that were in excess of grants made in the prior year. Excluding stock-based compensation expense, general and administrative expense decreased $789,000 to $2.3 million for the three months ended September 30, 2011 compared to September 30, 2010. This decrease is primarily due to lower legal fees as a result of the Classic Star litigation settlement in November 2010.

Litigation settlement expense. We reported litigation settlement expense of $21.2 million for the three months ended September 30, 2010 in conjunction with the settlement agreement with the plaintiffs of the ClassicStar Mare Lease Litigation.

Dividends on Preferred Stock. We reported dividends on our Series A Preferred Stock of $388,000 for the three months ended September 30, 2011. The Series A Preferred Stock had a stated value of approximately $16.9 million at September 30, 2011 and carries a cumulative dividend rate of 8.625% per annum. There were no shares of Series A Preferred Stock outstanding for the three months ended September 30, 2010.

Nine Months Ended September 30, 2011 compared to the Nine Months Ended September 30, 2010

Revenues. Natural gas, oil and NGL revenues were $28.1 million for the nine months ended September 30, 2011, up from $22.2 million for the nine months ended September 30, 2010. The increase in revenues was the result of a 19% increase in weighted average prices, primarily resulting from increased oil prices and higher oil and NGL volumes for the 2011 period, and a 7% increase in volumes. Average daily production on an equivalent basis was 20.7 MMcfe/d for the nine months ended September 30, 2011 compared to 19.4 MMcfe/d for the same period in 2010. Oil and NGL daily production represented approximately 4% of total production for the nine months ended September 30, 2011 compared to 1% of daily production for the prior year nine month period.

During the nine months ended September 30, 2011, approximately 89% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $6.7 million in natural gas and oil revenues resulting in an increase in total price realized from $3.41 per Mcf to $4.63 per Mcf. The realized hedge impact includes a benefit of $1.3 million for amortization of prepaid call sale and put purchase premiums. Excluding the non-cash amortization, the realized

effect of hedging was an increase in revenues of $5.4 million, which was comprised of $8.1 million of NYMEX hedge gains offset by $552,000 of regional basis losses and payment of deferred put premiums of $2.2 million. During the nine months ended September 30, 2010, 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 realized from $3.74 per Mcf to $4.13 per Mcf. The 2010 realized hedge impact included $1.6 million of amortization of prepaid call sale and put purchase premiums.

Unrealized natural gas hedge gain was $1.0 million for the nine months ended September 30, 2011 compared to $13.9 million for the nine months ended September 30, 2010. The decrease in the unrealized natural gas hedge gain for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010 is primarily due to a change in actual future hedged prices compared to the future price curve as well as a decrease in the future volumes hedged.

Production taxes. We reported production taxes of $384,000 for the nine months ended September 30, 2011 compared to $300,000 for the nine months ended September 30, 2010. The increase in production taxes is primarily the result of higher revenues in West Virginia due to increased natural gas, oil and NGL production, partially offset by lower revenues in Wyoming due to lower production volumes.

Lease operating expenses. We reported lease operating expenses of $5.9 million for the nine months ended September 30, 2011 compared to $5.2 million for the nine months ended September 30, 2010. Our lease operating expenses were $1.05 per Mcfe for the nine months ended September 30, 2011 compared to $0.99 per Mcfe for the same period in 2010.

Transportation, treating and gathering. We reported transportation expenses of $3.4 million for the nine months ended September 30, 2011, down slightly from $3.5 million for the nine months ended September 30, 2010. The current year to date period includes $1.1 million of charges under our Hilltop gas gathering agreement with Hilltop Resort GS, LLC compared to $1.2 million of such charges for the same period in 2010. Such charges resulted from actual production volumes being less than minimum contractual volume requirements.

Depreciation, depletion and amortization. We reported DD&A expense of $10.8 million for the nine months ended September 30, 2011 up from $6.1 million for the nine months ended September 30, 2010. The increase in DD&A expense was the result of a 66% increase in the DD&A rate per Mcfe and a 7% increase in production. The DD&A rate for the nine months ended September 30, 2011 was $1.91 per Mcfe compared to $1.15 per Mcfe for the same period in 2010. The increase in the rate is primarily due to higher proved costs associated with recent East Texas wells drilled and additional allocation of undeveloped East Texas leasehold costs from unproved to proved properties based on recent drilling results. The September 30, 2010 DD&A rate was partially benefitted by the gathering system sales proceeds credited to proved property costs in the fourth quarter of 2009.

General and administrative. We reported general and administrative expenses of $8.6 million for the nine months ended September 30, 2011, down from $11.6 million for the nine months ended September 30, 2010. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $2.0 million and $2.3 million for the nine months ended September 30, 2011 and 2010, respectively. The decrease in stock-based compensation expense is primarily due to the forfeiture of previously issued unvested awards as a result of director and employee resignations, prior year awards being fully amortized and recently issued shares having a lower fair value. Excluding stock-based compensation expense, general and administrative expense decreased $2.7 million to $6.6 million for the nine months ended September 30, 2011 compared to September 30, 2010. This decrease is primarily due to lower legal fees as a result of the Classic Star litigation settlement in November 2010.

Litigation settlement expense. We reported litigation settlement expense of $21.2 million for the nine months ended September 30, 2010 in conjunction with the ClassicStar Mare Lease Litigation settlement agreement.

Interest expense. We reported interest expense of $87,000 for the nine months ended September 30, 2011 compared to $120,000 for the nine months ended September 30, 2010. The decrease in interest expense primarily resulted from lower outstanding debt balances during 2011.

Investment income and other. We reported investment income of $7,000 for the nine months ended September 30, 2011 compared to $1.3 million for the nine months ended September 30, 2010. The decrease in investment income is primarily due to including, in the nine months ended September 30, 2010, interest earned on the Australian term deposit established in conjunction with the sale of the Australian properties in July 2009 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 nine months ended September 30, 2011.

Warrant derivative gain (loss). For the nine months ended September 30, 2010, we reported a $205,000 unrealized gain related to the fair value measurement of our warrants outstanding. At September 30, 2011, the outstanding warrants had a zero fair market value.

Foreign transaction gain. We reported a foreign transaction loss of $5,000 for the nine months ended September 30, 2011 compared to a gain of $349,000 for the nine months ended September 30, 2010. 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 in 2009.

Provision for income tax expense (benefit). We did not report an income tax benefit or expense for the nine months ended September 30, 2011. For the nine months ended September 30, 2010, we reported an income tax benefit of $804,000. The 2010 income tax benefit was primarily due to a $1.0 million downward adjustment of the tax expense related to the sale of the Australian properties after final review from the Australian Tax Office partially offset by withholding tax on the interest income from the Australian term deposit. At maturity on June 1, 2010, the term deposit was used to settle the tax liability resulting from the Australian property sale in 2009.

Dividends on Preferred Stock. We reported dividends on our Series A Preferred Stock of $419,000 for the nine months ended September 30, 2011. The Series A Preferred Stock had a stated value of approximately $16.9 million at September 30, 2011 and carries a cumulative dividend rate of 8.625% per annum. There were no shares of Series A Preferred Stock outstanding for the nine months ended September 30, 2010.

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 the Revolving Credit Facility, issuances of Gastar USA preferred equity and access to capital markets, to the extent available. In addition, our Atinum Joint Venture will provide a cash source for our Marcellus Shale development program by providing carried interest funding of up to $40.0 million, of which $23.9 million remained available to fund our share of future drilling and completion costs on joint venture wells at September 30, 2011. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow.

For the nine months ended September 30, 2011, we reported cash flows provided by operating activities of $7.5 million, net cash used in investing activities, primarily for the development and purchase of natural gas and oil properties, of $34.5 million and net cash provided by financing activities of $26.5 million, consisting of $16.9 million of proceeds from issuances of 810,499 shares of Gastar USA’s Series A Preferred Stock and $10.0 million of net borrowings under our Revolving Credit Facility. As a result of these activities, our cash and cash equivalents balance decreased by $471,000, resulting in a cash and cash equivalents balance of $7.0 million at September 30, 2011.

At September 30, 2011, we had a net working capital deficit of approximately $26.7 million, including $28.6 million of advances from non-operators, of which $8.9 million will be applied to our net future costs pursuant to the carried interest provisions of the Atinum Joint Venture. At September 30, 2011, availability under our Revolving Credit Facility was $40.0 million.

Future capital and other expenditure requirements. Capital expenditures for the fourth quarter of 2011 are projected to be approximately $18.0 million, consisting of drilling, completion, infrastructure, lease acquisition and seismic costs of $13.1 million in Appalachia and $4.2 million in East Texas and an additional $700,000 for capitalized interest and other costs. We plan on funding this capital activity through existing cash balances, internally generated cash flow from operating activities, borrowings under the Revolving Credit Facility and possible future at-the-market issuances of Series A Preferred Stock by Gastar USA. 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, availability under the Revolving Credit Facility or issuances of Gastar USA preferred equity. Our capital expenditures and the scope of our drilling activities may change as a result of several factors, including, but not limited to, changes in natural gas and oil prices, costs of drilling and completion and leasehold acquisitions and drilling results. We currently plan to delay the finalization of our 2012 capital expenditure budget until the first quarter of 2012 so that we may further monitor natural gas and oil prices, preferred share issuances and borrowing base changes for the remainder of the year to ensure that we properly align our cash flow and financing capabilities with our 2012 capital program activity. Pursuant to the Atinum Joint Venture and existing non-operated well commitments, our required 2012 drilling capital budget under these arrangements will be approximately $80.0 to $90.0 million depending on activity level.

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. 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 6 – Derivative Instruments and Hedging Activity” of this report.

At September 30, 2011, the estimated fair value of all of our commodity derivative instruments was a net asset of $15.2 million, comprised of current and noncurrent assets and liabilities. In conjunction with certain commodity derivative hedging activity, we deferred the payment of certain put premiums for the production month period July 2010 through December 2012. At September 30, 2011, we had a current commodity derivative premium payable of $4.4 million and a long-term commodity derivative premium payable of $1.4 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 2011, 2012 and 2013, 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, 2011, 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, 2011 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, 2011, we had $10.0 million outstanding under the Revolving Credit Facility compared to our December 31, 2010 outstanding balance of zero. The increase in our long-term debt balance is associated with expenditures for the development of natural gas and oil properties during the nine months ended September 30, 2011 of $58.7 million. Borrowing base redeterminations are scheduled semi-annually with the next redetermination scheduled for November 2011.

On June 14, 2011, Gastar USA, together with the parties thereto, amended the Revolving Credit facility, by, among other things, allowing Gastar USA to issue Series A Preferred Stock and, as long as no default exists or would result from such payment and availability under the Credit Agreement equals at least 10% of the then-existing borrowing base under the Credit Agreement, pay cash dividends on the Series A Preferred Stock of no more than $10.0 million in the aggregate in each calendar year.

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. At November 1, 2011, our availability under our Revolving Credit Facility was $50.0 million.

At September 30, 2011, Gastar USA was in compliance with all financial covenants under the Revolving Credit Facility. For a more detailed description of the terms of our Revolving Credit Facility, see Part I, Item 1. “Financial Statements, Note 4 – Long-Term Debt” of this report.

Off-Balance Sheet Arrangements

As of September 30, 2011, 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. A discussion of current legal proceedings is set forth in Part. I Item 1. “Financial Statements, Note 12 – Commitments and Contingencies” of this report.

Critical Accounting Policies and Estimates

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

•

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

•

Changes in the estimate or different estimates 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 I. “Financial Statements, Note 2 -Summary of Significant Accounting Policies” of this report and in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” included in our 2010 Form 10-K.

Recent Accounting Developments

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major commodity price risk exposure is to the prices received for our natural gas production. Our results of operations and operating cash flows are affected by changes in market prices. Realized commodity prices received for our production are the spot prices applicable to 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 three and nine months ended September 30, 2011, a 10% change in the prices received for natural gas production would have had an approximate $716,000 and $2.1 million impact, respectively, on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report for additional information regarding our hedging activities.

Interest Rate Risk

At September 30, 2011, we had $10.0 million outstanding under the Revolving Credit Facility. Based on the amount outstanding under our Revolving Credit Facility at September 30, 2011, a one percentage point change in the interest rate would have had a $25,000 impact on our interest expense, all of which would have been capitalized. We currently do not use interest rate derivatives to mitigate our exposure to the volatility in interest rates, including under the Revolving Credit Facility, as this risk is minimal.

Foreign Currency Exchange Risk

During 2009, we sold all of our Australian assets. As a result, all of our current and future revenues and capital expenditures and substantially all of our expenses are in U.S. dollars, thus limiting our exposure to foreign currency exchange risk.

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 the Chief Executive Officer and Chief Financial Officer of Parent and the President and Treasurer of Gastar USA, Parent and Gastar USA each conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2011. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Parent and the President and Treasurer of Gastar USA concluded that, as of September 30, 2011, each company’s 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 the Chief Executive Officer and Chief Financial Officer of Parent and the President and Treasurer of Gastar USA, 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, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

A discussion of current legal proceedings is set forth in Part I, Item 1. “Financial Statements, Note 12 – Commitments and Contingencies” of this report.

Item 1A. Risk Factors

Except as set forth below, information about material risks related to our business, financial condition and results of operations for the three and nine months ended September 30, 2011 does not materially differ from that set out under Part I, Item 1A. “Risk Factors” in our 2010 Form 10-K and Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarters ended March 31, 2011 (“1Q 2011 Form 10-Q”) and June 30, 2011 (“2Q 2011 Form 10-Q”). You should carefully consider the risk factors and other information discussed in our 2010 Form 10-K, 1Q 2011 Form 10-Q and 2Q 2011 Form 10-Q, as well as the information provided in this report. These risks are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, operating results and cash flows.

The process of drilling for and producing natural gas and oil involves many operating risks that can cause substantial losses, and we may not have enough insurance to cover these risks adequately.

The natural gas and oil business involves many operating hazards, such as:

•

Well blowouts, fires and explosions;

•

Surface craterings and casing collapses;

•

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

•

Pipe and cement failures;

•

Formations with abnormal pressures;

•

Stuck drilling and service tools;

•

Pipeline ruptures or spills;

•

Natural disasters; and

•

Releases of toxic natural gas.

Any of these events could cause substantial losses to us as a result of:

•

Injury or death;

•

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

•

damage to natural resources due to underground migration of hydraulic fracturing fluids;

•

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

•

Regulatory investigations and penalties;

•

Suspension of operations; and

•

Repair and remediation costs.

We could also be responsible for environmental damage caused by previous owners of property from whom we purchased leases. As a result, we may incur substantial liabilities to third parties or governmental entities. Although we maintain what we believe is appropriate and customary insurance for these risks, the insurance may not be available or sufficient to cover all of these liabilities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

Item 6. Exhibits

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


Exhibit Number		Description

3.1		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005, Registration No. 333-127498).

3.2		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).

3.3		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).

3.4		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).

3.5		Certificate of Incorporation of Gastar Exploration USA, Inc. (incorporated by refernce to Exhibit 3.3 to Gastar Exploration USA, Inc.'s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).

3.6		Amended and Restated Bylaws of Gastar Exploration USA, Inc. (incorporated by refernce to Exhibit 3.3 to Gastar Exploration USA, Inc.'s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).

3.7		Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.3 of Gastar Exploration USA, Inc.'s Form 8A filed on June 20, 2011).

4.1		Indenture related to the 12³/4% Senior Secured Notes due November 29, 2012, dated as of November 29, 2007, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent and each of the other Guarantors party thereto (including the form of 12³/4% Senior Secured Note due 2012) 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated December 4, 2007. File No. 333-32714).

4.2		Supplemental Indenture dated as of February 16, 2009, related to the 12³/4% Senior Secured Notes due 2012, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent, and each of the other Guarantors party thereto. 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated February 20, 2009. File No. 001-32714).

4.3		Agreement between Gastar Exploration Ltd. and GeoStar Corporation dated August 11, 2005 (incorporated by reference to Exhibit 4.17 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

4.4		Facsimile of common share certificate of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.21 of the Company’s Amendment No. 3 to Registration Statement on Form S-1/A, dated December 15, 2005. Registration No. 333-127498).

4.5		Warrant dated June 11, 2008, entitling GeoStar Corporation to acquire, subject to adjustments, 10,000,000 Gastar Exploration Ltd. common shares (incorporated by reference to Exhibit 4.1 of the Company’s Current Report of Form 8-K dated June 13, 2008. File No. 001-32714).

10.1		Gastar Exploration Ltd. Annual Bonus Plan (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated August 8, 2011. File No. 001-32714).


Exhibit Number		Description

31.1†		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.2†		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.3†		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.4†		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

32.1††		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

32.2††		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

32.3††		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

32.4††		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS††		XBRL Instance Document

101.SCH††		XBRL Taxonomy Extension Schema Document

101.CAL††		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF††		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB††		XBRL Taxonomy Extension Label Linkbase Document

101.PRE††		XBRL Taxonomy Extension Presentation Linkbase Document

†	Filed herewith.

††	Furnished herewith.

SIGNATURES

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


	GASTAR EXPLORATION LTD.

Date: November 3, 2011	By:	/S/ J. RUSSELL PORTER
		J. Russell Porter
		President and Chief Executive Officer
		(Duly authorized officer and principal executive officer)

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 USA, INC.

Date: November 3, 2011	By:	/S/ J. RUSSELL PORTER
		J. Russell Porter
		President
		(Duly authorized officer and principal executive officer)

EXHIBIT INDEX


Exhibit Number		Description

3.1		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005, Registration No. 333-127498).

3.2		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).

3.3		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).

3.4		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).

3.5		Certificate of Incorporation of Gastar Exploration USA, Inc. (incorporated by refernce to Exhibit 3.3 to Gastar Exploration USA, Inc.'s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).

3.6		Amended and Restated Bylaws of Gastar Exploration USA, Inc. (incorporated by refernce to Exhibit 3.3 to Gastar Exploration USA, Inc.'s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).

3.7		Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.3 of Gastar Exploration USA, Inc.'s Form 8A filed on June 20, 2011).

4.1		Indenture related to the 12³/4% Senior Secured Notes due November 29, 2012, dated as of November 29, 2007, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent and each of the other Guarantors party thereto (including the form of 12³/4% Senior Secured Note due 2012) 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated December 4, 2007. File No. 333-32714).

4.2		Supplemental Indenture dated as of February 16, 2009, related to the 12³/4% Senior Secured Notes due 2012, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent, and each of the other Guarantors party thereto. 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated February 20, 2009. File No. 001-32714).

4.3		Agreement between Gastar Exploration Ltd. and GeoStar Corporation dated August 11, 2005 (incorporated by reference to Exhibit 4.17 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

4.4		Facsimile of common share certificate of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.21 of the Company’s Amendment No. 3 to Registration Statement on Form S-1/A, dated December 15, 2005. Registration No. 333-127498).

4.5		Warrant dated June 11, 2008, entitling GeoStar Corporation to acquire, subject to adjustments, 10,000,000 Gastar Exploration Ltd. common shares (incorporated by reference to Exhibit 4.1 of the Company’s Current Report of Form 8-K dated June 13, 2008. File No. 001-32714).

10.1		Gastar Exploration Ltd. Annual Bonus Plan (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated August 8, 2011. File No. 001-32714).


Exhibit Number		Description

31.1†		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.2†		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.3†		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.4†		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

32.1††		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

32.2††		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

32.3††		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

32.4††		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS††		XBRL Instance Document

101.SCH††		XBRL Taxonomy Extension Schema Document

101.CAL††		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF††		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB††		XBRL Taxonomy Extension Label Linkbase Document

101.PRE††		XBRL Taxonomy Extension Presentation Linkbase Document

†	Filed herewith.

††	Furnished herewith.